H2S IN EOR-CONCLUSION OPTIONS NARROWED TO CLAUS OR REDOX PROCESSES

J.E. Johnson
Pritchard Corp.
Overland, Kan.

Stephen J. Tzap, Robert E. Kelley
Raytheon Engineers & Constructors
Denver

Lawrence P. Laczko
OXY USA Inc.
Midland Tex.

Depending on the gas flow rate and the produced tons of sulfur/day, the amine/Claus and Redox processes meet the requirements of a proposed CO2 EOR gas processing plant near Welch, Tex.

In the low gas flow range and sulfur tonnage above 8 long tons/day, amine/Claus was best while for the high gas flow range and sulfur tonnage below 15 long tons/day, Redox was more economical.

Five different sulfur recovery processes were evaluated for OXY USA Inc.'s CO2 enhanced oil recovery project (EOR) in West Texas. Part 1 (OGJ, Nov. 15, p. 61) described the overall processes selected. This concluding part will detail the sulfur recovery options.

REQUIREMENTS

All of the sulfur recovery processes have a base case of 9 long tons/day sulfur with the maximum high-volume case gas flow (year 12) and an alternate case of 9 long tons/day sulfur with the maximum low-volume case gas flow (year 10).

Cases also were developed for the higher sulfur rates of 18 and 27 long tons/day at the same high and low-volume gas flows; i.e., six cases for each process. The higher sulfur rate cases established the economic crossover point for Redox compared to amine/Claus sulfur recovery.

The sulfur recovery system is required to remove sufficient H2S to assure that the H2S Content of the CO2-rich reinjectant will not exceed 100 ppmv prior to field blowdown. The H2S content of the CO2 sold during field blowdown in the later years may not exceed 20 ppmv.

Other sulfur compounds, such as mercaptans and carbon disulfide, are not required to be removed in the sulfur recovery system. These compounds are present in relatively low concentrations such that the removal accomplished during NGL recovery will produce a CO2 stream that will meet the 175 ppmw total sulfur allowed in the reinjectant and later, the 35 ppmw total sulfur allowed in the CO2 to sales. The sulfur compounds in the NGL will be removed as part of the NGL treating process. The H2S removed will be converted to a molten sulfur product for sales.

The conversion of H2S to liquid sulfur product, as required by New Source Performance Standards (NSPS) and by the Texas Air Control Board (TACB), must be 96%. The subject process selection study used this basis.

RECOVERY ALTERNATIVES

Numerous sulfur recovery process options were initially screened to arrive at the five that were evaluated: two Redox processes, two variations of selective amine with Claus, and one modified Ryan-Holmes with H2S removed from the NGL by amine, followed by Claus.

The five are:

LoCat II-A redox process treating the low-pressure gas
SulFerox-A redox process treating the low-pressure gas
Selective amine/Selectox-The low-pressure gas is contacted with Flexsorb SE Plus to produce a lean acid gas that feeds a recycle Selectox unit, a direct oxidation version of the Claus process.
Two-stage selective amine/Claus-The low-pressure gas is contacted with Flexsorb SE+ to produce a lean acid gas that is enriched by contacting again with Flexsorb SE + to produce a rich acid gas suitable for feed to a Claus unit.
Ryan-Holmes/amine/Claus-The H2S is allowed to pass through the plant until it reaches the Ryan-Holmes unit, that is changed from propane recovery to ethane recovery so that H2S is put into the NGL. The NGL is treated with amine to produce an acid gas suitable for feed to a Claus unit.

LOCAT II

The LoCat II process, licensed by ARI Technologies Inc., is an iron redox process in which the low-pressure sour CO2 stream is contacted with an aqueous solution of ferric iron to achieve direct oxidation of the H2S to elemental sulfur.

A co-current static mixer is used for contacting. After gas-liquid separation, the solution is depressured to release most of the absorbed CO2 that is recompressed and returned to the treated gas stream.

Then the solution is blown with air to reoxidize the iron prior to the iron returning to the static mixer contactor.

A small portion of the solution passes through a settler where solid sulfur particles are removed. These are filtered and washed on a belt-filter, reslurried, and melted to provide a liquid sulfur product.

Small amounts of mercaptans and hydrocarbons, including aromatics, are absorbed by the solution. Most mercaptans are converted to disulfides that, along with the hydrocarbons, are removed from the solution by the reoxidation air and sent to a catalytic oxidizer (incinerator) for volatile organic compounds (VOC) and odor control.

Chelating agents keep the iron in solution. All equipment wetted by the solution must be stainless steel because the chelates attack and dissolve carbon steel, yet the solution is not corrosive to the skin.

The LoCat process has been widely used for 13 years. LoCat II is a new lower cost and improved version of the old LoCat process.

The LoCat II design proposed for this application uses the new oxidizer design and new static mixer contactor. Iron concentrations and solution circulation rates are in the same range as used for the older process. The LoCat II process is a viable process for this application.

SULFEROX

The SulFerox process, licensed by Dow Chemical USA and/or Shell Oil Co., is also an iron redox process. The basic process concept is very similar to LoCat II. The major differences are a much higher iron concentration, a much lower solution circulation rate, and a much lower oxidation air rate.

The low-pressure sour CO2 is contacted in a co-current static mixer. After gas-liquid separation, the bulk of the solution is recycled back to the static mixer to maintain the desired high liquid/gas ratio. A small portion of the solution is depressured to release absorbed CO2 which is recompressed.

The solution is regenerated by blowing with air. The solution and air overflow the regenerator vessel into the regenerator surge tank where vent air, solution and sulfur are separated.

The air goes to a catalytic oxidizer (incinerator) for VOC and odor control. The regenerated solution is pumped back to the static mixer contactor. The sulfur is filtered and washed on a rotary drum filter, then reslurried and melted.

The SulFerox process was first commercialized in mid-1990. Shell's Denver City plant, completed in 1992, is an EOR application very similar to the Welch plant. SulFerox is a viable process for this application.

SELECTOX

The Redox systems require managing complex chemical reaction systems, solids settlers, slurry pumps, and filters. Amine and Claus sulfur systems are less complicated and more familiar in the gas plant environment. An amine/Claus system may be preferable if economical and if the process satisfies the sulfur recovery and turndown criteria.

A selective amine process removes H2S from the low-pressure sour CO2, without co-absorbing excessive amounts of CO2. Exxon Chemical Co.'s amine Flexsorb SE Plus is used because its high selectivity and high capacity for H2S provides the lowest circulation requirement and the smallest amine system. Even so, the resulting acid gas is too lean for a conventional Claus sulfur plant.

A Selectox unit was chosen to process the lean acid gas. Selectox is a direct oxidation process, constructed in standard skidded units. Acid gas is preheated, mixed with air, and sent to the Selectox reactor where a special catalyst selectively oxidizes H2S to SO2 and catalyzes the Claus reaction to form sulfur.

The reaction is limited thermodynamically. Two standard Claus reactors are added to bring the total sulfur recovery up to about 96% maximum. Depending on the year of operation and the corresponding resultant acid gas concentration, the recovery may be less than 96%. The effluent from the last condenser is reheated and sent to a catalytic incinerator where all remaining sulfur compounds are converted to SO2 before being released through a vent stack. Hydrocarbons are also destroyed in the incinerator.

For this plant, the "recycle" Selectox process would be used because the acid gas is usually more concentrated than the 4-5% H2S limit for once-through Selectox. A recycle blower dilutes the incoming acid gas with off-gas from the Selectox condenser. This dilution limits the temperature rise in the Selectox reactor to an acceptable level. The recycle feature allows a wide range of operation, including 10:1 turndown on both flow and sulfur rates.

The selective amine/Selectox process has the disadvantage that significant quantities of CO2 are lost with the H2S in the lean acid gas. Also, the sulfur recovery with Selectox is lower than the other processes due to equilibrium limitations with the lean acid gas.

The guaranteed recovery for the high-range 9 long tons/day case was less than 96%. The recovery met the standards set by NSPS but not the 96% minimum recovery for all operating conditions as originally requested by the TACB. Therefore, additional process improvements, at higher cost, are required.

ACID GAS

The selective amine with acid gas enrichment and Claus uses the same selective amine system, as described previously, to produce a lean acid gas. Then a second selective amine system, using the same Flexsorb SE Plus solvent, treats the lean acid gas to produce an "enriched" acid gas suitable for a conventional Claus sulfur recovery unit.

The unit will have sulfur recoveries of at least 96% as required. The Claus tail gas is sent to a thermal oxidizer (incinerator), with heat recovery where all remaining sulfur compounds are converted to SO2 before being released through a stack. Hydrocarbons are destroyed in the reaction furnace and in the incinerator.

The sweet CO2 exiting the top of the enrichment contactor is recompressed and returned to the treated gas stream. Therefore, the CO2 losses are only a small fraction of the losses through the Selectox system.

The acid gas enrichment system has a design feature that allows control to almost constant H2S concentration in the enriched acid gas as the sour CO2 flow and sulfur content decrease with time.

RYAN-HOLMES

The fifth process allows the H2S to remain in the sour CO2 stream until it reaches the Ryan-Holmes NGL recovery system. The Ryan-Holmes is modified to separate H2S from the CO2 and recover H2S, along with ethane and additional propane, in the NGL stream. The modification requires additional refrigeration, more additive circulation, and larger towers.

The NGL is contacted with a proprietary amine solvent, for example Ucarsol CR Solvent 301 from Union Carbide, in a liquid-liquid contactor to remove H2S and CO2 from the NGL. The produced acid gas is suitable for a conventional Claus sulfur recovery unit.

The operation of the Claus unit and incinerator is the same as described previously.

Preliminary information showed that the Ryan/Holmes modifications would be very expensive, and it was expected that this option would have the highest installed and operating cost of the five processes. This option was therefore dropped from further detailed consideration.

However, this "pass through" option is considered generally competitive for such applications and may actually be favored for a different set of project parameters and economic criteria. The value of increased NGL product can be a significant factor.

ECONOMICS

Table 1 details the capital cost estimates for the three most attractive process options and for all six cases: low and high-volume flow with 9, 18, and 27 long tons/day sulfur content.

Based on capital cost only, a Redox option is lowest for both the low and high-volume cases at 9 long tons/day sulfur. As sulfur tonnage increases above 9 long tons/day, the amine/Claus option becomes most attractive.

Tables 2-4 provide estimated operating and maintenance costs for the three most attractive process options.

All competing processes were evaluated at 9 long tons/day sulfur production and at the maximum gas rates for both the low and high-flow ranges. The process evaluation showed that the Redox process has little sensitivity to gas rate when compared to the selective amine based processes. However, the Redox process costs are very sensitive to sulfur loading.

Table 5 compares the process at 9 long tons/day.

The processes were also evaluated at 18 and 27 long tons/day sulfur and both low and high flow. The Redox processes are very sensitive to sulfur rate when compared to selective amine processes.

The comparative evaluated costs (Fig. 1) show that the redox processes are very sensitive to sulfur production, primarily because of the high cost of chemicals that are directly proportional to sulfur production.

In contrast, the selective amine processes are sensitive to gas flow rate, with operating costs going up proportionately somewhat slower than gas flow rate.

These curves show that both gas flow and sulfur production must be considered when making a process selection.

OTHER CHARACTERISTICS

The sulfur product quality varies. The selective amine processes produce a bright yellow Claus sulfur. The redox processes generally produce an off-color sulfur, usually of lower value than Claus sulfur, which may be hard to sell.

As for the sulfur recovery efficiency, the redox processes recover nearly 100% of the H2S removed from the CO2 stream as elemental sulfur. The selective amine process recovery is about 97% maximum of the H2S as elemental sulfur. Although on-stream performance factors may reduce the theoretical redox efficiency somewhat, in either the redox or amine/Claus processes actual recoveries are predicted above the NSPS and the Texas Air Control Board requirements.

In regard to sulfur emissions and odor concerns, the redox processes convert mercaptans to polysulfides that are also malodorous. A vent air incinerator provides for odor control. It may be necessary to blow a small amount of air through the sulfur in the storage tank to control sulfur odor. This air would be incinerated also.

The selective amine processes usually produce some CO2 COS, and CS2. The COS and CS2 are destroyed in the tail gas incinerator as is most of the CO. Small amounts of H2S are dissolved in the molten sulfur. The very small part of that H2S that comes out of the sulfur during the storage time is usually dispersed to the atmosphere through natural circulation air vent stacks in the pit. Local regulations or concerns may require the vent air to go to the incinerator.

For turndown efficiency, the selective amine processes are sensitive to the residual H2S specification in the CO2 stream. For example, the amine circulation would be reduced about 20% when 100 ppmv H2S is allowed instead of 20 ppmv. The selective amine processes are sensitive to CO2 flow also. Amine circulation would be reduced another 20% if the CO2 flow was only half of design rate.

These reductions would save a small amount of pump horsepower, but the main effect would be a reduction in regenerator reboiler heat in proportion to amine circulation.

The redox processes are not very sensitive to either residual H2S ppm or CO2 flow rate. H2S specification and CO2 capacity are attained by providing the correct contactor length and diameter.

RECOMMENDED RECOVERY

At the base case of 9 long tons/day sulfur, amine/Claus is recommended at the low gas flow range and redox is recommended at the high gas flow range. These recommendations are based on the least evaluated cost that accounts for capital and operating costs, as well as differences in operability.

The redox processes were penalized for extra manpower required for the complicated chemistry control, slurry handling, and filter operation. The selective amine processes were given credit for 4 more days/year of operation. The credit assumes that the sour reinjection gas would be flared causing loss of NGL products and requiring purchase of replacement CO2 for injection.

The amine/Claus and amine/Selectox are significantly different on evaluated cost because of the larger loss of CO2 through the Selectox unit. The two-stage amine system in the amine/Claus recovers most of the CO2 and recompresses it back into the treated gas.

HIGH SULFUR PRODUCTION

Sulfur production is very important in process selection. Amine/Claus is the recommended process at low gas flow for all sulfur rates above 8 long tons/day. Amine/Claus displaces redox at high gas flow when sulfur production exceeds about 14 long tons/day.

The amine/Claus process can recover 96% or more of the H2S as product sulfur that meets NSPS and TACB requirements for all cases investigated. Claus process improvements or tail-gas cleanup systems may be needed in the future, at higher sulfur capacities, or at other facility locations to meet higher recovery levels. These would introduce step changes in the Sulfur Removal Cost Comparison curves shown in Fig 1.

The magnitude of the step changes would depend on the degree of clean up required. Some possible choices are cold bed adsorption, and Super Claus extensions to the Claus unit, or addition of a SCOT-type (Shell/Claus offgas treating) tail-gas cleanup unit.

OPERATIONS OVER TIME

The initial H2S specification of 100 ppmv would allow a 20% reduction in the size of the selective amine portion of the amine/Claus process. The reduced size amine system could easily make 26 ppmv H2S during field blowdown assuming that the blowdown rate is at least 20% lower than maximum design rate.

Both sulfur production and CO2 rate change dramatically with time. The redox processes and selective amine processes are affected differently by these changes. A net present value analysis should be done to verify the most economical process selection considering changes in various operating cost elements with time.

The final choice of process and equipment size must be done with consideration of realistic gas and sulfur rates.

SYSTEM IMPLEMENTATION

A single train would be installed for the expected gas volume composition range. In the low gas flow range and sulfur tonnage above 8 long tons/day, use amine/Claus. For the high gas flow range and sulfur tonnage below 15 long tons/day, use redox.

No plant expansion is required with the plan. In the fourth year, gas rates exceed the capacity of any half-sized equipment for the low or high gas flow range.