Final Notes from Site Visit at WVPA’s Wabash River Power Station on February 25, 2009

EPA conducted a site visit at the Wabash Valley Power Association’s (WVPA’s) Wabash River

Power Station (Wabash) located in Terre Haute, IN on Wednesday, February 25, 2009 to learn 

about the operations at the plant, specifically the integrated gasification combined cycle (IGCC) 

unit. Table 1, located at the end of these notes, identifies the site visit participants.

Attachment 1 contains an overall water balance diagram for the plant. The presentation that the 

WVPA personnel gave during the site visit is provided as Attachment 2 to these notes.

Plant Overview

• PSI Energy originally brought Unit 1 on line in the 1950s as a standard coal-fired 

combustion generating unit, and converted (“repowered”) Unit 1 into an IGCC 

system in 1994. At the time of the site visit, Wabash Valley Power Authority 

(WVPA) owned the combined cycle portion of Unit 1 (i.e., the gas turbine, heat 

recovery steam generator (HRSG), and steam turbine, but not the gasification 

system). The gasification system has been owned by several entities since 1994 

and is currently owned by SG Solutions (SGS). 

• The IGCC system began as a demonstration project, but has been operated 

commercially since 1996. The gross capacity of Unit 1 is 296 MW (192 MW gas 

turbine, 104 MW steam turbine). The net capacity is 262 MW.

• The gasification plant is located next to the Wabash River plant and comprises 

approximately 20 acres.

• The steam turbine associated with the combined cycle portion of the unit is 

located inside the Duke Energy plant.

• Cooling water intake and cooling water discharge for the combined cycle unit are 

handled by Duke Energy.

Unit 1 IGCC Operations

• The gasification technology used at Wabash is the Global Energy E-GASTM coal 

gasification process.

• The current plant configuration consists of a single train, with one two-stage 

gasifier supplying one combustion turbine.

• During the demonstration phase of the unit (1995-1999), 2,500 tons/days 

bituminous coal with up to 3.5% sulfur was burned. Since August 2000, 2,000 

tons/day petroleum coke (pet coke) with up to 6% sulfur is burned. The pet coke

is a cheaper fuel, but generates more ash. The plant holds approximately 70 days 

of pet coke on site.
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• Pet coke is received via rail and slurried in the rod mill. It is then combined with 

95% pure oxygen in slurry mixers and injected into the first stage of the gasifier, 

which operates at 2,600ο

F and 400 psi.

• Ash is transformed to a molten form and flows to the quench station as a 

slag/water slurry. This slurry flows into a dewatering bin equipped with an 

inclined plate separator. The slag settles out in the bin and is returned to the slurry 

preparation area, while water overflows to a storage tank and is returned to the 

gasifier quench in a closed loop system.

• Dewatered slag is loaded into a truck or rail car for transport to market or its 

storage site. The slag can be temporarily stored on site at a storage slab located 

adjacent to the Slag Hopper Building. Additionally, the slag can be transferred to 

a location in Clinton, Indiana where it is deposited in a prepared cell in a qualified 

manner as per Indiana Department of Environmental Management guidelines.

• Pet coke slag is finer than coal slag. Plant personnel have experimented with the 

amount of oxygen to add stating that a reducing environment converts the ash to a 

glassy, “encapsulated” substance. Personnel also noted that this substance passes 

leaching tests and none of the slag is stockpiled on site.

• The syngas flows to the second stage of the gasifier, where additional slurry is 

injected. Syngas leaving the gasifier flows to the high temperature heat recovery 

unit (HTHRU) to produce high-pressure saturated steam. The syngas is cooled 

from 600◦C to 100◦C, and the resulting condensate is referred to as sour water. 

Approximately 1,500 pounds of steam are transferred to the heat recovery steam 

generator (HRSG).

• After cooling in the HTHRU, particulates (“char”) are filtered from the syngas

and recycled to the first stage of the gasifier where the carbon in the particulates is 

converted into more syngas. Plant personnel stated that 99.9% of the carbon is 

converted to syngas.

• The syngas is cooled and scrubbed with sour water to remove chlorides. The 

syngas passes through a catalyst that hydrolyzes carbonyl sulfide (COS) to 

hydrogen sulfide (H2S). The syngas is then processed through 

methyldiethanolamine (MDEA) based absorber/stripper columns, where the acid 

gas is removed and the clean syngas (approximately 35◦C) is transferred to the 

combustion turbine to generate additional power.

• The acid gas stream is transferred to a sulfur recovery process where sulfur that is 

99.999% pure is recovered and marketed. Plant personnel stated that one rail car 

is filled with this sulfur by-product every 22 hours.

• Sour water collects in the low temperature heat recovery unit (LTHRU) holding 

tank. Approximately 60% of the sour water is recycled back to the rod mill as 

slurry water. The remaining sour water is transferred to the wastewater treatment 

system.
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Unit 1 Wastewater Generation and Treatment

• Sour water consists of the combined condensate and scrubber blowdown streams, 

as well as the sour water return from the sulfur recovery unit.

• The sour water is sent to a CO2 stripper, where steam is used to remove carbon 

dioxide from the water. Some of this stripped water is then recycled to the coal 

slurry process. The remainder is sent to a second steam stripper to remove the 

ammonia present in the water.

• The cleaned water leaving the ammonia stripper is transferred to a mechanical 

vapor compression system, consisting of an evaporator (referred to by the plant as 

the zero liquid discharge (ZLD) system). The concentrated brine from the ZLD 

process is sent to a rotary drum dryer to remove the water from the salts. Plant 

personnel stated that the rotary drum dryer needs increased maintenance due to 

the corrosive salts being handled.

• Salts (which are contaminated with selenium and arsenic) are transferred offsite 

as hazardous waste one to two times per week. The material is currently disposed 

with Veolia, who makes a stabilized cement product.

• The distillate from the ZLD is the portion of the wastewater that is discharged 

from the plant. Plant personnel stated that the ZLD system was incorporated into 

the process after the initial start up; therefore, the process was not designed to 

reuse the distillate. Additionally, the distillate could not be used in the combined 

cycle process because it was owned by Duke Energy.

• Plant personnel stated that they do sometimes use the distillate for coal slurry 

make-up water, but because the distillate is at a high temperature, it has to be 

cooled in sumps before it is returned to the slurry process.

• In addition to the distillate from the ZLD system, the following wastewaters are 

also associated with the operation of the IGCC unit:

• Air separation unit blowdown;

• Slag handling wastewater;

• Blowdown from the heat recovery steam generator;

• Petroleum coke pile runoff pond effluent;

• Raw water filtration backwash;

• Demineralizer system reject; and

• Cooling tower blowdown.

• These waste streams are transferred to the plant’s wastewater treatment pond. The 

water from this pond is transferred via internal Outfall 102 to the Duke Energy 

ash pond, which discharges to the Wabash River.

• Although WVPA is required to get a new permit because of the purchase of the 

combustion turbine and combined cycle portions of the plant, Wabash River is 
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still currently transferring the wastewater to the Duke Energy ash pond.

• Plant personnel stated that when they stop transferring the water to the Duke 

Energy ash pond, the wastewater from the wastewater holding pond will be 

transferred to the plant’s storm water pond and then discharged to Wabash River 

via the new Outfall 001.

• Wabash River expects to begin discharging from the new outfall in late fall 2009.
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Table 1. Site Visit Attendees

Name Organization (Representing) Telephone E-mail

Terry Hogan WVPA 317-696-5666 T_hogan@wvpa.com

Jarod Klaas WVPA 317-481-2838 J_klaas@wvpa.com

Jeff Bell WVPA 317-481-2920 J_bell@wvpa.com

Richard Payonk ConocoPhillips 812-535-6062 Richard.j.payonk@conocophillips.com

Mary Henderson SG Solutions (SGS)/ConocoPhillips 812-535-6075 M_henderson@sgswabash.com

Donna Hill UWAG 205-257-5234 dbhill@southernco.com

Sean Ramach US EPA Region 5 312-886-5284 Ramach.sean@Epa.gov

Ron Jordan EPA/Office of Water 202-566-1003 jordan.ronald@epa.gov

Deb Bartram ERG (Contractor to EPA) 703-633-1669 deborah.bartram@erg.com