Wisconsin Public Service is seeking an exemption from air pollution control permit requirements for research and testing of activated carbon injection (ACI) and dry sorbent injection (DSI) systems at the Unit #8 boiler at its Pulliam power plant.
A search by Energy Central of the Wisconsin Department of Natural Resources air permitting website shows this application, filed in October 2011, as still pending. A November 2011 DNR memorandum written as part of this permitting said: “The proposed demonstration project will be conducted to determine the effectiveness of DSI and carbon-based sorbent injection on Unit P8 SO2 and mercury emissions without causing a significant PM emissions increase. Knowledge gained from this project will be used to optimize the performance of the DSI and ACI systems for upcoming regulations, develop compliance strategies and to determine any permitting issues. This project may result in the installation of a full scale DSI system for the control of SO2.”
In 2010, the utility obtained a research and testing exemption to evaluate the effect of ACI on mercury emissions. The testing demonstrated effective control of mercury emissions and little effect on particulate emission rates. The first two phases of this new project will involve testing the use of DSI as a means of SO2 reduction and using the existing ACI system to determine DSI impact on mercury.
Wisconsin Public Service is proposing to conduct DSI testing using Trona, a naturally occurring mineral mined in Wyoming, and sodium bicarbonate, a material made from Trona.
- For Phase 1, the injection location for DSI will occur at the air heater outlet, as this location is expected to benefit mercury control.
- For Phase 2, the injection location for DSI (Trona only) will occur at the air heater inlet, as this location is expected to benefit SO2 control. An important part of the testing will be to determine if DSI can replace SO3 for conditioning the fly ash for efficient electrostatic precipitator (ESP) operation.
- For Phase 3, the DSI injection location and sorbent type would be determined while additional ACI test equipment along with sorbent enhancement additive (SEA) chemical feed equipment would be brought in to further improve the mercury control. Only one DSI product (Trona or sodium bicarbonate) will be injected at a time into the boiler.
The DNR sent a November 2011 letter to the utility that said it has to complete at least one stack test for particulate matter, including backhalf, using appropriate U.S. Environmental Protection Agency methods at the most efficient sorbent rate to demonstrate compliance with the particulate emission limitation. Emissions of NOx, SO2, CO2, and opacity will be continuously monitored while these tests are conducted, although only the SO2 and opacity data will be relevant to these tests. Some mercury testing may be done.
The testing would conclude within 12 months of the receipt of the final decision letter and can’t exceed 578 hours of actual testing. If the testing is successful and Wisconsin Public Service decides to use this system on a continuous basis, it may need to submit permit application forms for a construction permit to obtain approval to operate on a continuous basis, the agency letter noted.
Wisconsin Public Service is a unit of Integrys Energy Group (NYSE:TEG). The Integrys annual Form 10-K filing from Feb. 29 shows Pulliam as a four-unit coal plant with a total of 328.4 MW.
Utility identifies Weston Unit 3 as DSI possibility
A March 7 filing by Wisconsin Public Service (WPSC) at the state Public Service Commission has a heavily-redacted update of the utility’s clean-air plan, including its plan to meet the Cross-State Air Pollution Rule, with and without the current federal appeals court stay on that rule. The plan doesn’t mention DSI at Pulliam, but does say the utility is looking at the possibility of a quick DSI installation using Trona at the coal-fired Weston Unit 3 if CSAPR is again put back in play by the court.
“On July 6, 2011, the Cross State Air Pollution Rule (CSAPR), was issued by the Environmental Protection Agency (EPA) to replace the Clean Air Transport Rule (CATR),” said the filing about the justification for the Weston Unit 3 DSI planning. “CSAPR requires power plants in the states covered by the rule to reduce SO2 emissions 73% and NOx emissions 54% by 2014 compared to 2005 emission levels. These reductions will occur in two steps for SO2, beginning in January 2012 and 2014, respectively. Nearly all of the NOx reduction will occur in an initial step beginning in January 2012, with a second small reduction occurring in 2014. Compared to CATR, WPSC will receive significantly fewer allowances under CSAPR, and the required reductions in SO2 and NOx emissions will be imposed sooner. In January 2011, WPSC’s CATR allocation for SO2 was estimated to be approximately 19,500 allowances annually through 2014. The CSAPR SO2 allocations released in July 2011 reduced WPSC’s allocation by approximately 17% to 16,137 tons in 2012 and by approximately 57% to 8,402 tons in 2014. The WPSC NOx allocations were less significantly affected by CSAPR.”
Permitting for DSI also pursued at Weston
The DNR website shows that the utility applied Jan. 19 for DSI at Weston. Said a March 9 DNR letter: “WPSC-Weston proposes to temporarily use dry sorbent injection prior to the baghouse (that controls emissions from Boiler B03) while using the existing activated carbon injection system for up to 12 months to determine the following: 1. The technical feasibility of dry sorbent injection to reduce sulfur dioxide emissions, and 2. The impact that dry sorbent injection has on mercury emissions while also using activated carbon injection.”
A March 9 letter from the DNR to the utility laid out similar conditions as with the Pulliam DSI, including conclusion of the testing within 12 months after permitting approval.
The Integrys Form 10-K shows that Weston Units 1-3 have a combined capacity of 458.9 MW, while the co-owned Unit 4 is 382.5 MW.
WPL pursues DSI work at two Edgewater units
Also, the DNR database shows that Wisconsin Power and Light applied in May 2011 for an air pollution control permit to research and test a duct sorbent injection system in boilers #4 and #5 at the Edgewater coal plant. Wisconsin Public Service co-owns Edgewater Unit 4. Wisconsin Power and Light is a unit of Alliant Energy (NYSE:LNT).
“The first phase of the testing is to examine the use of the liquid flue gas conditioning chemical ATI-2001 as an alternative to SO3 conditioning by Unit 4,” said a July 2011 DNR letter about this project. “WPL’s expectation is that the use of ATI-2001 will allow for a fuller utilization of carbon in the fly ash, coupled with the use of the existing calcium bromide application system, thereby enhancing mercury collection. ATI-2001 has been utilized at WPL’s Columbia Energy Center to positive results. ATI-2001 is proposed to be injected into the cold side of the air heater discharge in front of the electrostatic precipitator at a ratio ranging from 1 gallon of ATI-2001 to 18 tons of coal to 1 gallon of ATI-2001 to 36 tons of coal.”
The July 2011 letter added: “In the second and third phases of testing, WPL will test the use of DSI as a means of SO2 reduction. In the second phase, WPL will conduct DSI testing using Trona, a naturally occurring mineral mined in Wyoming, as the sorbent. WPL would continue to utilize urea for NOx control and calcium bromide for control of mercury emissions during this testing, as well as ATI-2001 from phase 1 of these tests. … During phase three of testing, WPL will substitute sodium bicarbonate for Trona following the same test protocol as for Trona and utilize the same injection ports.”
WPL will conduct testing of DSI on Edgewater Unit 5 in a similar fashion to that of phase 2 and 3 of the Unit 4 tests, with the first phase of tests being conducted using Trona and the second using sodium bicarbonate. WPL will not use ATI-2001 on Unit 5 as a flue gas conditioner, but WPL does anticipate continuing to utilize activated carbon and calcium bromide during these tests.
DSI seen as a cost-effective lifesaver for coal plants
DSI, which is a cheaper though somewhat less effective emissions control option for coal-fired power plants than the more common wet or dry scrubbers, may play a key role in compliance with the U.S. Environmental Protection Agency’s Mercury and Air Toxics Standards (MATS). The U.S. Energy Information Administration noted that fact in a brief “Today in Energy” news item posted to its website on March 16.
EPA finalized the MATS rule in December 2011. The rule requires that all U.S. coal- and oil-fired power plants greater than 25 MW meet emission limits consistent with the average performance of the top 12% of existing units —known as maximum achievable control technology (MACT). The rule applies to three pollutants: mercury (Hg), hydrochloric acid (HCl), and filterable particulate matter (fPM) and has a compliance deadline in 2015, though that can be extended on a case-by-case basis.
While DSI systems do not control for mercury, they can, when combined with a particulate control filter, meet this standard for two of the three controlled pollutants, EIA noted.
DSI and flue gas desulfurization (FGD), both wet and dry, are technologies that will allow plants to meet the MATS for HCl and other acid gases. As of 2010, 54% of U.S. electric generating capacity already have FGDs installed, EIA pointed out. A number of the remaining, uncontrolled plants will need to determine the effectiveness of installing FGD or DSI to comply with the MATS rule.