Process Waste Water Background
Process wastewater from gasification processes includes all wastewater streams generated or captured during normal operations and equipment purges/wash-downs during maintenance activities. The combined streams include, but are not limited to: cooling tower blowdown; blowdown from circulating water systems in the gasification block; blowdown from the steam cycle and/or regeneration waste water from the demineralizer system in the power block; rainwater collected in both the gasification and the power blocks; equipment purges and water wash-downs during maintenance procedures; and un-recycled condensed water from the process.1

Water is primarily required for the plant’s steam cycle as boiler feedwater (BFW) and cooling water (CW), as well as for process operations, such as syngas emissions control. While the steam cycle in an integrated gasification combined cycle (IGCC) plant typically produces less than 50% of the power plant’s total power output, its water consumption is not proportionately lower (compared with a similarly sized conventional steam plant), since the gasification process itself can consume considerable quantities of BFW. BFW consumers in IGCC systems, depending upon gasification technology and design, are:

  • Instrument tap purges, pump seals, and intermittent flushes
  • Direct steam injection to serve as a reactant and/or temperature moderato
  • Saturator for NOx abatement (if steam is used as a diluent)
  • Losses

Because of these BFW needs, an IGCC plant may consume as much, or more, BFW as a conventional steam plant of comparable output, even if it is well designed, operated, and maintained.2 On the other hand, the steam cycle CW requirement will be proportionately lower than the conventional steam plant due to its reduced share of the total plant power output. Also helping to reduce water consumption, coal gasification processes recover most of the water associated with the raw feed coal via condensation during syngas cleanup. This is not practical for combustion-based plants due to their low-pressure operation.

The other large water requirement, process water, is used to cool and clean the syngas to remove fly ash, halogens and trace organic and inorganic components. The concentration level of specific contaminants depends upon the fuel characteristics and the type of gasifier employed in the design. The quantity of water required depends on the capacity of syngas treated, the degree of gas cooling required, and the contaminants to be removed.

Coal-fueled plants also often use wastewater to control the dust and bulk density of the solid waste. The net process water bleed stream is usually of higher quality than the cooling-water blowdown. In fact, some plants use process water effluent as part of the cooling-water makeup.3

IGCC plants normally consume between 6 to 9 gpm of water per MW of electricity generated, depending upon the specific design. In contrast, a PC plant, utilizing a wet limestone desulfurization process for SO2 control, consumes about 10 to 11 gpm of water per MW of electricity generation.4 In other words, the water required to operate an IGCC plant is approximately one-half to two-thirds that needed to operate a PC plant with flue gas desulfurization (FGD); the comparison can be extended to fluidized bed combustion (FBC) plants as well. Approximate estimates are shown in Table 1.

In summary, an IGCC plant generally produces fewer water effluents than the PC and FBC plants. The amount of process water blowdown is about the same for these plants. However, the steam cycle in IGCC power plants yields much lower amounts of wastewater blowdown since less than 50% of the total power generated comes from the steam cycle.

Table 1. Water Consumption Estimate—IGCC vs. PC and FBC Plants5

Water Consumption, gallons/MWh 600 – 660 570 - 625 360 – 540

Aqueous Effluents Characterization
Process wastewater potentially contains small amounts of dissolved solids and gases and is treated to remove the contaminants before being recycled to slurry preparation or being discharged to a water outfall. Dissolved gases are driven from the water via flashing (sometimes under vacuum) or steam stripping with low-pressure steam (which provides heat and a sweeping medium to expel the gases from the water). The flash gas is sent to the Claus plant or sulfuric acid decomposition furnace. Removal of solid contaminants, such as trace metals, may require additional wastewater treatment using other equipment, such as a mechanical vapor recompression (MVR) system. Most of the treated process water is recycled to the plant, and only a relatively small amount is discharged as a blowdown to a pond. Reuse of the water within the gasification plant minimizes water consumption and water discharge.

Based on the water requirements described above, coal gasification plants have two principal water effluent streams that are similar to those in direct-fired power plants. The first is wastewater from the steam cycle, including blow-downs from the boiler feed water purification system and the cooling tower (if direct cooling is not used). The amount of this wastewater effluent depends on the hardness of the raw water and the power generated by the steam cycle. These effluents contain salts and minerals that have been concentrated from the raw feed water. Gasification processes, with the exception of moving-bed gasifiers, such as Lurgi and British Gas/Lurgi, purify and recycle raw process streams, and the net discharge process water is normally only a blowdown.

The second aqueous effluent is process water blowdown. These streams are typically high in dissolved solids and gases including trace metals, trace organics, and the following commonly found ionic species: chloride, fluoride, sulfide, formate, nitrogen species, cyanide, thiocyanate, and bicarbonate.6 Almost half of the chlorides and all of the fluorides in the syngas should end up in the blowdown. Under the reducing conditions that exist in a gasifier, ammonium (NH4+) and ammonia (NH3) are likely to dominate the nitrogen-containing aqueous species found in both untreated and treated process water, which differs from a direct-fired power plant whose oxidizing environment virtually ensures that the dominant species is the NO3- ion.

Blowdown streams are typically recycled to the coal feed preparation area, to the scrubber after entrained solids have been removed, to a zero discharge water system, or to a wastewater treatment system. However, recycling of water has its limitations, as dissolved salts accumulate to levels incompatible with the process or its metallurgy. Make-up water is added as process water is blown down to wastewater treatment. Zero-discharge process water systems have no wastewater discharges, however, these systems must address disposal of salts resulting from brine evaporation. Purification removes most of the organic compounds before the water is recycled.

Finally, as with all coal-fueled plants, a secondary effluent stream is run-off from the coal and slag storage areas and the process area. TECO Energy, the owner/operator of the Polk plant indicates that control of this effluent can involve significant effort and cost.7

Waste Water Treatment
While IGCC wastewater control technology varies significantly,8,9 essentially all the necessary control technologies are commercially available and have found wide use in various industries, such as chemicals, pulp and paper, oil, and steel. The more complex the gasification process, the more complex is the wastewater-processing scheme. On this basis, the moving-bed technologies (Lurgi and British Gas/Lurgi) typically require the most complex wastewater-processing scheme, while the entrained-flow gasifiers require a relatively simple processing scheme. In either case, wastewater-processing facilities have been developed and are currently in operation. Extensive data have demonstrated the satisfactory performance of these systems at the South Africa Coal, Oil and Gas Corporation (SASOL)10, the Cool Water IGCC, the LGTI project11, and the Polk and Wabash River plants. Some of these facilities utilize a zero water effluent design, as opposed to the blowdown approach mentioned above. For example, the Cool Water IGCC system utilized a simple evaporation pond to accomplish zero discharge.

One method of treatment for process water offers an additional opportunity to recover sulfur. Process water taken directly from high temperature and pressure systems can be “flashed” in a vessel at low or negative pressure to release dissolved gases. The flash gas is routed to the sulfur removal unit with the raw synthesis gas, and the water is either recycled to the system or it is blown down to a conventional wastewater treatment unit before discharge. Gas condensate, also known as sour water, may also be steam-stripped to remove ammonia, carbon dioxide, and hydrogen sulfide. The stripper overhead can be routed to the sulfur recovery unit or incinerated, subject to permit limitations for NOx and SO2 emissions. The sour water stripper recovers water suitable for recycling to the process as make-up. A portion of the recovered water from the sour water stripper may be discharged to a conventional wastewater treatment system.

Wabash River IGCC
At the Wabash River plant, process wastewater is steam stripped to remove dissolved gases before recycling to slurry preparation or being discharged. An ammonia stripper is used to remove ammonia and remaining trace components. Water leaving the treatment system is purified sufficiently to allow reuse or discharge within permit limits. Holding tanks were also constructed for discharges that are not within acceptable limits.

Polk Power IGCC
Polk’s zero-discharge water treatment system, though in operation now for many years, is competitive with systems being implemented at the newest plants (see discussion about Edwardsport IGCC below). The process water (grey water) blowdown stream goes to a vapor compression concentrator followed by crystallization of the brine into a salt consisting mostly of ammonium chloride. The clean condensate from this system is recycled to the process. The size of the blowdown stream which must be treated in this manner is determined by one of two factors: 1) process water balance and distribution – is the water consumed by the process (the gasifier) more or less than the water coming in with the coal, purges, etc., and 2) salt (chloride) build-up in the process water loop. This buildup, which also sets the blowdown rate for wet scrubbing systems in conventional direct-fired plants, is almost entirely a function of the chloride in the coal. The plant also operates an ammonia stripper to purge the system of cyanides and ammonia that are produced in the gasifier. So, although the plant has no process water discharge, this comes at a price of operating several treatment systems12

Edwardsport IGCC
The Edwardsport IGCC Plant water supply system is designed to produce all the water needed at the site through two radial groundwater collection wells.

The original Edwardsport front-end engineering and design (FEED) study assumed two deep injection wells (injection into saline aquifers) for the purposes of grey water handling. However, the permit for injecting wastewater underground was denied due to a ruling by the U.S Environmental Protection Agency (EPA) that the project’s grey water does not qualify as a Resource Conservation and Recovery Act (RCRA) Subtitle C-exempt Bevill waste. The alternative solution that was chosen is treatment of the wastewater by evaporation and crystallization using Veolia HPD® technology. Usable distilled water is recovered, and the hazardous solid stream requiring disposal is minimized. The considerable advantage in eliminating liquid hazardous waste and recovery of water (the system is considered to be a zero liquid discharge process) is accompanied by the disadvantages of energy penalty that will impact the IGCC plant heat rate, and the significant capital cost of the brine concentrator plant.

The Edwardsport FEED study notes that a permit modification to the existing National Pollutant Discharge Elimination System (NPDES) permit for Edwardsport Station has been required. The existing ash ponds at the site are to be converted to settling ponds, with the ability to manage any contamination issues from site runoff water or neutralization waste prior to discharge. Also, an allowance for potential modifications to the discharge canal was made.

  1. Wabash River Coal Gasification Repowering Project, Final Technical Report, prepared for U.S. DOE/NETL, by Wabash River Energy Ltd., August 2000.
  2. McDaniel, J., Personal communication (Draft report review comments), Teco Energy Inc., March 8, 2002
  3. Ibid.
  4. Andries Brink, “The SASOL Experience with Purification and Reuse of Synfuel Wastewaters,” In Proceedings: Opportunities in the Synfuel Industry (Syn Ops 88), Bismarck, ND, August 28-31, 1988.
    Simbeck, D., et al., “Coal Gasification Guidebook: Status, Applications, and Technologies,” Report prepared for EPRI by SFA Pacific, Inc., TR-102034, Dec 1993.
  5. D.R. Simbeck, N. Korens, F.E. Biasco, S. Vejtosa, and R.L. Dickenson, “Coal Gasification Guidebook: Status, Applications, and Technologies,” Palo Alto, California: Elective Power Research Institute, December 1993. TR-102034.
  6. Orr, D. and D. Maxwell, “A Comparison of Gasification and Incineration of Hazardous Wastes, Final Report,”DCN 99.803931.02, March 30, 1999.
  7. McDaniel, J., Personal communication (Draft report review comments), Teco Energy Inc., March 8, 2002
  8. Effluent Limitations Guidelines, Pretreatment Standards, and New Source Performance Standards for the Iron and Steel Manufacturing Industry Point Source Category: Proposed Rule. Federal Register, 40 CFR Part 430, Vol. 65, No. 249, December 27, 2000, pp. 81964-82083, United States Environmental Protection Agency.
  9. “Supplemental Technical Development Discount for Effluent Limitations Guidelines and Standards for the Pulp and Paper Industry,” Office of Water (4303), Washington, D.C., EPA-821-R-97-011, 1997.
  10. Andries Brink, “The SASOL Experience with Purification and Reuse of Synfuel Wastewaters,” In Proceedings: Opportunities in the Synfuel Industry (Syn Ops 88), Bismarck, ND, August 28-31, 1988.
  11. “Wabash River Coal Gasification Repowering Project,” Final Technical Report to U.S. DOE, Office of Fossil Energy, National Energy Technology Laboratory, Report Number DE-FC21-92MC29310, August 2000.
  12. McDaniel, J., Personal communication (Draft report review comments), Teco Energy Inc., March 8, 2002


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