Environmental

Catalysts used in selective catalytic reduction (SCR) systems in utility boilers provide high NO_x removal efficiencies that routinely exceed 90%. A major co-benefit of applying SCR to coal-fired power plants is that the SCR catalyst also oxidizes the vapor phase mercury from an elemental form to a soluble ionic form, which can be readily captured in a downstream flue gas desulfurization process. Mitsubishi Heavy Industries and Cormetech have developed an advanced SCR catalyst technology with high mercury oxidation activity capable of achieving 95% oxidized mercury over a wide range of operating conditions.

Luminant used remnants of the ill-fated Twin Oaks and Forest Grove plants (which were mothballed more than 30 years ago) to build the new two-unit 1,600-MW Oak Grove Plant. Though outfitted with equipment from those old plants, Oak Grove also sports an array of modern air quality control equipment and is the nation’s first 100% lignite-fired plant to adopt selective catalytic reduction for NO_x control and activated carbon sorbent injection technology to remove mercury. For melding two different steam generators into a single project, adopting a unique and efficient “push-pull” fuel delivery system, assembling a tightly integrated team that completed the project on time and within budget, and for completing what was started almost four decades ago, Oak Grove Power Plant is awarded POWER magazine’s 2010 Plant of the Year award.

With commercial operation of Madison Unit 3, Cleco Power now claims bragging rights for owning the largest 100% petroleum coke–fired circulating fluidized bed power plant in North America. For using readily available fuel in an environmentally attractive manner, adopting fuel-flexible combustion technology, balancing the utility’s generation portfolio, and adopting an innovative fuel-handling system design, Madison Unit 3 is the winner of POWER’s 2010 Marmaduke Award for excellence in operation and maintenance. The award is named for Marmaduke Surfaceblow, the fictional marine engineer and plant troubleshooter par excellence.

In April, Solvay Chemicals Inc. commissioned a new facility that uses an innovative process to recover and transform sodium carbonate waste streams into a market-grade sodium bicarbonate used in air emissions control.

A federal judge recently dismissed a lawsuit in which the plaintiffs alleged that defendants’ production of chemicals and electricity had “added to the ferocity of Hurricane Katrina.” The judge’s reasoning reveals the inherent limitations of courts unilaterally initiating policies to address climate change issues.

It’s no surprise that China leads the world in recent power capacity additions. What may surprise you is the precise mix of options this vast country is relying upon to meet its ever-growing demand for electricity. As a result, this ancient civilization is fast becoming the test bed and factory for the newest generation and transmission technologies.

Regenerative activated coke technology (ReACT) is an integrated multipollutant control approach that removes SO_x, NO_x, and Hg from coal-fired plants by adsorption with activated coke to attain emissions levels found at natural gas–fired plants. One big advantage of this technology is that it uses only a fraction of the water used by conventional wet flue gas desulfurization. A recent license agreement brings this technology to the U.S.

Circulating fluid bed (CFB) dry scrubbing technologies provide distinct advantages over conventional spray dryer absorber scrubbers for removing SO₂ from flue gases. The CFB also competes well against wet limestone flue gas desulfurization processes typically favored for large boilers firing high-sulfur coals. With high SO₂ removal rates in a dry treatment process, the CFB scrubber appears to be the best of both technologies: a water-stingy scrubber with high SO₂ removal rates.

When it is completed, later this summer, the UK’s Drax Power Station biomass facility will become the largest dedicated cofiring project of its kind in the world. As U.S. coal-fired generators come under increasing pressure to cut emissions and take advantage of incentives to promote power generation from renewables, Drax offers an example of what is possible.

Today’s coal-fired power plants face the twin challenges of improving their wet flue gas desulfurization (FGD) systems’ emission control capabilities in order to comply with environmental regulations while at the same time cutting their operational and maintenance costs. Smart strategies for retrofitting existing FGD systems can help plant personnel meet both of these objectives.

At the opening ELECTRIC POWER 2010 plenary session, both the keynote speaker’s address and discussion among the Power Industry Executive Roundtable participants pointed to the renewed appeal of natural gas and proposed cap-and-trade legislation as being potential game-changers for the U.S. power industry.

The U.S. Environmental Protection Agency is expected to propose an emissions standard for mercury and other hazardous air pollutants emitted by coal- and oil-fired electric generating units in March of 2011. The anticipated rule would require emission control to meet the various standards using maximum achievable control technology, as determined by the prescriptive requirements of the Clean Air Act. In response to the expected rule-making, utilities will be required to make technology decisions in order to ensure compliance. One cost-effective approach to compliance may be the use of “co-benefits” from air quality control systems (AQCSs) already in service that are designed to remove other pollutants.

In an unusual two-option proposal that drew clashing views from green groups and power plant operators, the Environmental Protection Agency has proposed regulating coal combustion ash either as a nonhazardous waste subject to tougher management and disposal requirements or as a "special" hazardous waste that would have similar controls but still be eligible for recycling and reuse in products such as Portland cement.

Less than 24 hours after the unveiling of sweeping Senate legislation to reduce U.S. greenhouse gas emissions, the Environmental Protection Agency released a final Clean Air Act rule that defines emission thresholds for greenhouse gas permitting requirements for power plants and other large stationary sources.

Facing a difficult uphill slog in a sharply polarized Senate, Sens. John Kerry and Joseph Lieberman have unveiled long-awaited draft climate change and energy legislation that includes billions of dollars in incentives for the nuclear, natural gas, and coal industries aimed at attracting enough bipartisan support to overcome an all-but-certain filibuster led by the Senate Republican leadership.

I recently had the privilege of moderating the Power Industry Executive Roundtable, part of the annual ELECTRIC POWER Conference & Exhibition opening ceremonies. Usually, the power industry executives have predictable views of important issues, but not this year.

In 2006 and 2007, POWER ran a three-part series on the formation of SO₃, O&M issues caused by SO₃, and sorbent injection control for SO₃ control. Three years later, many plants still struggle with their SO ₃ mitigation systems or remain undecided on which mitigation path to follow. This article explores the advantages of dry sorbent injection technology.

Could the transformation of carbon dioxide (CO₂) into carbonates and oxides solve the problem of greenhouse gas emissions (GHG) from fossil-fired power plants? Some companies are betting that such processes could make everyone happy and even create new profits. Buzz has been growing about this approach, though the concept has been around for many years.

While the Environmental Protection Agency appears to have initially proposed to regulate power plant coal ash as hazardous waste, there are indications the Obama administration is preparing new federal rules that will at a minimum require utilities to convert coal ash impoundments from wet to dry storage to prevent leaks—a change that would cost tens of millions of dollars but also potentially increase regulated utilities’ rate base and earnings, a Wall Street firm says.

Highlighting a sharp division within the public power community, two senior House Democrats blasted the American Public Power Association for endorsing Sen. Lisa Murkowski’s effort to strip the Environmental Protection Agency of its Clean Air Act authority to regulate greenhouse gas emissions, with the lawmakers saying they have been informed that “numerous” APPA members oppose the endorsement.

In a move that could cost the state’s electricity generators an estimated $8.5 billion, New York regulators [have] issued a draft policy that would require the installment of closed-loop cooling systems at two dozen large power plants in the state, including oil, coal, nuclear and natural gas generators, to reduce fish kills and other harmful effects to wildlife in the water bodies that supply the plants’ cooling water.

Biomass has many advantages as a fuel for boilers: It’s inexpensive, readily available in many regions, CO₂ neutral, and its use warrants government subsidies. The fuel also presents unique concerns to the designers, owners, and operators of biomass plants, especially in the design of the control system.

Short of replacement, what are your options when your original electrostatic precipitator fails to meet your current emissions and opacity requirements? The management of Big Stone Plant chose the unconventional, yet economic approach of building a pulse jet fabric filter inside the casing of the old electrostatic precipitator. The upgrades restored plant availability and prepare the plant to meet the next regulated reductions in particulate matter emissions.

Concentrated sulfuric acid is often used to prevent calcium-based scale formation on condenser and heat exchanger tube surfaces in power plant evaporative cooling water systems. Unfortunately, the chemical’s price has jumped more than 300% over the past three years. If the rising cost of water treatment has you under the budget gun, here are some alternative strategies that can reduce or even eliminate your sulfuric acid usage.

Tampa Electric will soon complete a comprehensive selective catalytic reduction project on all four units at its Big Bend Power Station that will make Big Bend among the cleanest coal plants in the U.S. The project — the centerpiece of the company’s 10-year, $1.2 billion air quality improvement program — is on schedule to meet all of its air quality improvement goals by mid-2010.

Adding a selective catalytic reduction (SCR) system to an operating coal-fired plant may be an expensive and time-consuming project, but the environmental benefits are without question. However, once construction is complete and operations staff assume control of the SCR, proper measurement tools are required to monitor the catalyst performance life cycle.

In one of the most far-reaching of numerous new air regulations expected from the Obama administration, the Environmental Protection Agency (EPA) has proposed to tighten the primary federal standard for ground-level ozone, the principal constituent of smog, to within a range of 60 to 70 parts per billion, saying the tougher standard is needed to protect human health.

The Energy Department’s top fossil energy official said [in December that] he might seek exemption or relaxation of “new source review” requirements for certain U.S. coal-fired power plants that are boosting efficiency through retrofits if the plants are also good candidates for subsequent installation of carbon capture and storage systems.

The U.S. isn’t the only country evaluating and implementing elements of smart grid technology. In fact, it could be argued that other nations are much farther along the path to a comprehensive, technically advanced system for integrating renewables, managing load, and creating a more flexible power grid.

Last fall, the U.S. Environmental Protection Agency (EPA) issued a rule creating a mandatory national system for reporting greenhouse gas (GHG) emissions. The agency requires regulated entities to begin monitoring GHG emissions January 1, 2010, and to submit their first annual emissions reports March 31, 2011. This is a key step toward federal regulation of GHG emissions (a step that may have major implications regarding "major sources" and permitting requirements for new sources). It’s also an opportunity for power producers to implement their inventory management plans.