Detroit Edison has determined that the most cost-effective mercury reductions at its coal-fired power plants will occur as a co-benefit through the combination of wet flue gas desulfurization (FGD) and selective catalytic reduction (SCR) systems on Monroe Units 1-4.
The most cost-effective mercury reductions on the remaining coal-fired units operating without wet FGD will be achieved with the installation and operation of activated carbon injection (ACI) systems. Also, the company has determined that using reduced emission fuel (REF), which is coal with chemical additives, improves the performance of both FGD and ACI in meeting the required mercury reductions in the most cost-effective manner, wrote William Rogers, employed by DTE Energy Corporate Services LLC as a Senior Technological Specialist–Environmental Strategies.
Rogers was one of several DTE Energy (NYSE: DTE) and Detroit Edison officials supplying testimony filed Sept. 28 with the Michigan Public Service Commission as part of an annual Power Supply Cost Recovery (PSCR) case. Notable is that the PSCR case begun in September 2011 is still ongoing and lately has featured arguments about expenses to Detroit Edison customers from the REF program.
The utility said new emissions controls testing has been so successful that it now expects to keep open for the time being several coal-fired generating units that it once planned to close.
The purpose of his testimony was to explain Detroit Edison’s mercury control requirements, strategy for compliance, and to explain how the use of REF at the St. Clair and Belle River power plants, combined with ACI, supports compliance with mercury rules at the lowest reasonable cost to the customer, Rogers wrote. The use of REF at Monroe, combined with FGD, supports compliance with mercury rules at the lowest reasonable cost, he added. He also explained how the company plans to use dry sorbent injection (DSI) technology to comply with EPA’s Mercury and Air Toxics Standards (MATS).
Besides MATS, mercury reduction needs at Detroit Edison are driven by 2009 regulations known as the Michigan Part 15 Air Pollution Control Rules. These rules require every regulated coal-fired power plant in Michigan to comply on and after Jan. 1, 2015.
At the giant Monroe plant, FGD and SCR have been and are being installed primarily for SO2 and NOx reductions required by separate rules from Michigan Part 15 Rules and EPA’s MATS. FGD and SCR on Monroe Units 1-4, along with fuel blending and combustion controls on other units, cost-effectively meet the SO2 and NOx reductions required by current regulations. If further reductions are required in the future, equipment installations on additional units may be a cost-effective solution for compliance, Rogers noted.
Since the FGDs were put into service on Monroe Units 3 and 4, mercury emissions have been frequently measured and compared to Michigan Rule 1503 and EPA’s MATS mercury limits. While the Monroe Units 3 and 4 FGDs consistently meet Michigan Rule 1503 mercury standards, additives have been required to maximize vapor phase mercury oxidation, which would increase mercury removal by the FGD for continuous compliance with EPA’s more stringent MATs standards and assure compliance with Rule 1503 requirements. These are the same additives that are used in REF.
ACI testing shows it’s a viable option for mercury reductions
Several partial- and full-scale tests of ACI have been conducted at Detroit Edison power plants. Also, the company participated in tests conducted at power plants owned by other companies. These tests have demonstrated ACI to be the most efficient, cost-effective method for significant capture of mercury from power plants without wet FGD. Tests have demonstrated, however, ACI efficiency and costs vary depending on the type of coal burned and the power plant’s equipment configuration, Rogers pointed out. These differences influence which type of powdered activated carbon (PAC) is most effective and the required injection rates.
Detroit Edison’s testing has demonstrated that both Michigan Rule 1503 and MATS standards can be achieved on St. Clair Units 1-6 and Belle River Units 1-2 using ACI. Because those plants burn mostly subbituminous coal from the Powder River Basin, those ACI systems require a more expensive chemically-treated PAC to achieve the required mercury removal.
The required injection rates for ACI have been projected based on several ACI tests conducted at St. Clair Units 1 and 3. Detroit Edison conducted additional tests on those units in 2010 and 2011 demonstrating that while consuming REF, compliance-level mercury removal can be achieved using the lower cost standard PAC instead of the chemically treated BrPAC, and at much lower injection rates. This is to be expected since one of the components of REF is an effective agent for oxidizing vapor phase mercury, Rogers wrote.
MATS establishes numerical emission limits not only for mercury, but also particulate matter (a surrogate for certain non-mercury metals) and HCl (a surrogate for certain acid gases), Rogers added.
FGD has been proven to meet the MATS acid gas limits, but it requires significant capital investment. This larger capital investment may not be justified on some Detroit Edison coal units, Rogers noted. There is another technology, DSI, that has been used in the industry primarily to reduce SO3 emissions at units that burn higher sulfur coals. The company conducted extensive DSI testing in 2011 and 2012 to determine if it could be technologically and economically feasible on some of the company’s coal-fired units to reduce HCl emissions to levels in compliance with MATS limitations.
“The testing results were very positive,” Rogers reported. “Tests demonstrated DSI to be technologically and economically feasible to reduce HCl emissions to MATS compliance levels on certain Detroit Edison units burning expected coal types and coal blends.”
Detroit Edison relying on REF for some of its emissions cuts
Karthik Krishnamurthy, Supervisor-Fossil Fuel Resources, provided more information about Detroit Edison’s coal- and REF-procurement program. Krishnamurthy said a long-term forecast of coal prices assumes the company’s continued reliance on low sulfur western (LSW) coal. For 2013, over 85% of all coal consumed is projected to be LSW coal procured from the PRB in Montana and Wyoming. The balance of the company’s coal comes from Central and Northern Appalachia.
REF is being consumed at St. Clair Units 1-4 and 6, with a targeted annual REF burn of about 1.8 million tons. Monroe has been consuming REF at all four units since November 2011. REF is being tested at Belle River. The PSCR forecast assumes testing will be successful at Belle River and both units will begin consuming REF in 2014.
Shipments of coal for consumption at Belle River and St Clair will be sold at Detroit Edison’s Midwest Energy Resources Co. (MERC) rail-to-lake vessel transshipment facility on western Lake Superior to unregulated DTE Energy subsidiaries for treatment with the REF additives. All rail shipments of coal for consumption at Monroe will be sold FOB mine and all vessel delivered western coal for consumption at MPP will be sold FOB vessel at Detroit Edison’s MERC facility. “Notwithstanding these sales, the coal always remains under the supervision and control of Detroit Edison and MERC (no Fuels Company employees are involved in any process other than operation of the Fuels Companies separate equipment and facilities) and Detroit Edison’s and MERC’s books and records are maintained separately from the Fuels Companies,” Krishnamurthy noted.
Emissions retrofits now look better than further coal retirements
Robert Palmer, Manager of Asset Optimization in the Fossil Generation Organization of Detroit Edison, also offered Sept. 28 testimony that concentrated on equipment installations and power plant retirements.
A projected capacity decrease in 2013 is associated with the retirement of the Dayton and Conners Creek diesel peakers, Palmer wrote. A projected capacity increase in 2014 is associated with the 26.3-MW Ludington Unit 4 upgrade that is partly offset by a decrease associated with increased auxiliary power usage from FGD scheduled for installation in late 2013 and early 2014 on Monroe Units 1 and 2. Monroe Unit 1 will have a 12 MW decrease in net demonstrated capacity (NDC) in December 2013 and Monroe Unit 2 will experience a similar 12 MW decrease in NDC in May 2014 when it returns from its scrubber tie-in outage.
A projected capacity decrease in 2015 is associated with planned retirement of Harbor Beach (-103 MW) and Trenton Channel Units 7 and 8 (-210 MW) which are partially offset by the scheduled Ludington Unit 5 upgrade (+26.3 MW). Projected capacity increases in 2016 and 2017 are associated with the Ludington Units 1 and 2 upgrades.
Detroit Edison had indicated in a prior PSCR case that a projected capacity decrease in 2015 was associated with possible retirements of Harbor Beach, River Rouge Units 2-3, St. Clair Unit 7 and Trenton Channel Units 7-9, which were to be offset by the assumed addition of a combined cycle unit and the Ludington Unit 5 upgrade. Modified environmental rules and DSI/ACI testing performed by the company indicate that River Rouge Units 2 and 3, St Clair Unit 7 and Trenton Channel Unit 9 can cost-effectively comply with the MATS rules utilizing DSI for acid gas emissions reductions and ACI for mercury emissions reductions, Palmer reported.
Operation of River Rouge Units 2-3, St Clair Unit 7 and Trenton Channel Unit 9 beyond 2015 will also allow the deferral of the assumed need to build a new combined-cycle power plant. The company has assumed for PSCR planning purposes the retirement of Trenton Channel Units 7-8 in 2015. However, the ultimate retirement remains uncertain, Palmer added.
The GenerationHub database shows that these are all coal units, broken down by nameplate capacity as:
- River Rouge Unit 2 (293 MW) and Unit 3 (358 MW). All other units at the plant are gas- and oil-fired.
- St. Clair Unit 7 (545 MW). Other coal units are at this plant.
- Trenton Channel Unit 9 (536 MW), Unit 7 (120 MW) and Unit 8 (120 MW). These are the only operating units at the plant.
In November 2010, Detroit Edison made a request to the Midwest ISO for Harbor Beach retirement. The request was updated in December 2011 to request a retirement date of Jan. 1, 2012. The company received a response to this request on June 8. In that letter MISO declared Harbor Beach a System Security Resource (SSR) and stated that the earliest date the plant would be allowed to retire would be Dec. 31, 2015. That date was based on the schedule for transmission upgrades being done in the thumb of Michigan by ITC Transmission, Palmer wrote.
The GenerationHub database shows Harbor Beach with a 121-MW (nameplate) Unit 1 that is coal fired, and units IC1 and IC2, which are each 2-MW (nameplate) oil-fired facilities.
In December 2011, the Connors Creek (239 MW) and Marysville (84 MW) generating plants and Unit 5 at the St. Clair plant (250 MW) were retired. Marysville and St. Clair Unit 5 involved coal-fired capacity, while Conners Creek was a coal plant that was converted to natural gas about a decade ago.