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 ( W abash ) 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 th ese notes , identifies the site visit participants.

The presentation that the WVPA personnel gave during the site visit is provided as Attachment 1 to th ese notes. [ QUESTION FOR WVPA: Please provide a copy of the presentation.] Attachment 2 contains an overall water balance diagram for the plant.

Plant Overview

**•** PSI Energy originally brought Unit 1 on line in t he 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 turb ine, 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 demon stration 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 (petcoke) with up to 6% sulfur is burned. The petcoke is a cheaper fuel, but generates more ash. T he plant holds approximately 70 days of petcoke on site.Page 2

**•** Petcoke 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 2,600 ο 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 in to a truck or rail car for transport to market or its storage site. [ QUESTION FOR WVPA: Please state where slag is stored on site and where it is ultimately transferred.]

**•** Petcoke slag is finer than coal slag. Plant personnel have experimented with the

amo unt 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 sta ge 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 t he 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 s yngas is cooled and scrubbed with sour water to remove chlorides

. The

syngas pa sses through a catalyst that hydrolyzes carbonyl sulfide (COS) to hydrogen sulfide (H 2 S) . 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 wit h 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.Page 3

Unit 1 W astewater Generation and Treatment

**•** Sour water consists of t he combined condensate and scrubber blowdown stream s , as well as the sour water return from the sulfur recovery unit

.

**•** The sour water is sent to a CO 2 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 dr yer 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 w aste 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 syst em 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 perso nnel 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 still currently transferring the wastewater to the Duke Energy ash p ond.Page 4

**•** 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 stormwater 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.Page 5

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 [need address]

Richard Payonk ConocoPhillips 812

- 535

- 6062 Richard.j.payonk@conocophillips.com

Mary Henderson SG Solutions (SGS)/ConocoPhillips 812

- 535

- 6075 [need address]

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