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Is It Time to Rethink SO2 Control Technology Selection?

Issue 11 and Volume 111.

By Jim Dickerman, P.E. and Melissa Sewell, Chemical Lime

The decision to install SO2 control equipment can be an expensive one in terms of capital costs, operational costs, potential delays in project completion, as well as system performance. Due to the rapidly changing environment surrounding this decision, it may be time to rethink the standard approach to SO2 control technology selection.

The first flue gas desulfurization (FGD) systems in the United States were installed in response to the 1971 Clean Air Act, which enabled the U.S. Environmental Protection Agency (EPA) to establish SO2 emission limits for utility boilers. Most of the original FGD systems were calcium based wet scrubbing systems; about half of the early systems were lime and the other half limestone. Many of the original FGD systems, particularly the limestone systems, were plagued with operational issues that included scaling, plugging and low SO2 removal efficiency – generally less than 90 percent. As a result, a number of research and development programs were sponsored by the Electric Power Research Institute (EPRI) and the EPA to develop a better understanding of the limestone FGD systems’ process chemistry. This work resulted in significant advances in understanding limestone FGD operations, which has led to better process designs as well as improved overall system performances.

In 1990, the Clean Air Act was amended and the current “cap and trade” regulations were established as part of EPA’s Acid Rain Program. A system of emission allowances was established and a two-phase emission control scenario was implemented. Every utility boiler in the country was allotted a certain amount of SO2 it could emit in a given year. This allowed the owner/operator a choice in determining how to achieve the emission limit – either by adding emission controls, burning lower sulfur fuels or buying emission allowances from a utility that emitted less than its allotted amount.

Utility boilers were grouped into two tiers: the so-called Phase I and Phase II units. Boilers in Phase I were the largest SO2 emitters and had to comply first. Of the nearly 100 boilers classified in Phase I, about 80 percent elected to meet the emission standard by managing their fuel sulfur levels. The remaining 20 percent elected to install FGD controls. The technology choice was relatively evenly split; half of the FGD systems installed used lime as a reagent and the other half used limestone.

CAIR Regulations

Figure 1 presents a summary of the Phase I and Phase II emission caps versus the actual annual SO2 emissions reported to the EPA from the utility industry. This figure shows the bank of credits generated during Phase I, while the annual emissions from the utility industry were less than the allotted amount. This bank is being eroded during Phase II as the annual utility SO2 emissions exceed the allotted limits. Also shown is the projected reduced emissions cap that will occur in 2010, when the Clean Air Interstate Rule (CAIR) goes into effect. CAIR regulations are a large factor behind the many retrofit- FGD projects occurring today.

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FGD systems installed in the 1990’s were second- and third-generation systems. For the most part they achieved greater than 90 percent SO2 removal rates with vastly improved system reliabilities as compared to previous-generation FGD systems. A combination of well-performing emission control systems coupled with the use of low sulfur coals resulted in annual emissions that were less than the allotted amount during Phase I.

The limestone systems installed during this time were mostly forced oxidation systems (LSFO), which demonstrated the ability to achieve similar performance and reliability as lime systems. Although capital costs for limestone systems were higher than lime systems by 10 percent to 15 percent, their lower operating costs have given them a lower life-cycle cost advantage. This has resulted in virtually all wet FGD systems in the United States since the early 1990s being limestone-based.

During this same period, significant technology developments were being made with “dry” FGD systems – spray dryer absorber (SDA) and circulating dry scrubber (CDS) technologies. The dry systems gained favor as a lower capital cost alternative to wet systems for controlling SO2, particularly for boilers burning lower sulfur coals. The early dry FGD systems suffered from a combination of low SO2 removals and lower reagent utilizations than wet systems; but even so, the dry systems have proven to be the choice for many low sulfur coal-fired boilers due to their lower lifecycle costs. Over the past decade, significant process improvements have been made to the dry systems such that process guarantees of 95 percent SO2 removals are being offered for spray dryer systems and up to 98 percent for circulating dry scrubbers. Even with these improvements dry scrubber applications still have typically been limited to boilers firing coals with sulfur concentrations of less than 2 percent. At higher sulfur levels, wet scrubbers typically became the defacto technology selection.

The development of SO2 control regulations has been focused on emission control systems for the largest and highest emitting boilers; typically those over 500 MW that burn high sulfur coal. However, the CAIR regulations that will soon go into effect will require emission controls on smaller boilers that burn low- and medium-sulfur coals to attain the significantly reduced emission cap. The need for emissions controls for smaller boilers burning lower sulfur coals is one factor that may cause utilities to reevaluate the selection of SO2 emission control systems.

Massive Effort

Over the next five years, more than 100,000 MW of FGD capacity is slated for installation in the United States. The recent FGD selections basically have been made along the lines of coal sulfur levels; that is, dry systems (either spray dryer or circulating bed absorbers) are being selected for boilers that burn a low sulfur coal and wet LSFO systems are being selected for boilers that burn coals with 2 percent or greater sulfur levels. Virtually no wet lime systems have been selected; they are currently not being requested by the utility industry. As a result, FGD vendors are generally not offering wet lime FGD systems.

The massive ongoing effort to reduce SO2 emissions is mirrored by a similar effort in China. These emissions control activities have sent demand soaring for the labor and services of engineering firms that build emission control equipment and have resulted in large capital cost increases in FGD systems. For example, Allegheny Energy Inc. reported the cost of installing scrubbers at two facilities has increased from $888 million to over $1.2 billion. And NRG Energy said its cost estimates for emission control spending by 2010 have increased from $275 million to over $900 million. American Electric Power Co. also said it would defer some installations until after 2010 when it expects costs will be lower1.

In a technical paper presented at POWER-GEN International in Orlando in November 2006, Sargent and Lundy reported that 2003/2004 FGD project costs were typically $175–$225/kW, whereas in 2005/2006 they ranged from $275–$400/kW and higher2. In an effort to control project capital cost increases and stay within an appropriated budget, some utilities have decided to outsource portions of their FGD systems to third parties.

Capital Cost Increases

The large capital cost increases seen over the past couple of years are due to a combined effect of increases in the cost of raw materials needed to build corrosion resistant vessels, increased demand for key system components such as ball mills and pumps, a labor constrained work force and a full workload for many system vendors. This last factor has allowed vendors to selectively bid on those systems that offer the most favorable terms. In addition to these factors are ever-tightening SO2 emission standards. These require more robust system designs with higher liquid pumping rates, which increases capital costs and parasitic power requirements. A movement also exists toward more stringent water discharge standards (even zero discharge), which is adding still more complexity and further increasing the costs of LSFO FGD systems.

Tighter SO2 emission control regulations are taxing the ability of LSFO systems to meet future control requirements. Many LSFO systems being installed today are designed to achieve 98 percent SO2 removal without additives. These designs generally require high liquid pumping rates, large recycle pumps and an increased gas pressure drop – all of which increases system costs. Additionally, the movement toward tighter water balances results in additional complex and expensive water treatment processes as part of many new FGD systems. Achieving high SO2 removal rates require a consistently good quality, high calcium limestone, whose cost has also increased recently due to increased demands. High SO2 removal rates can also be achieved by using organic additives such as adipic acid, or DBA. However, additives also increase FGD operational costs and can negatively affect water treatment systems.

At Coal-Gen 2007 in Milwaukee, Sargent & Lundy presented results of a detailed economic comparison of LSFO and dry scrubbing technologies performed for the National Lime Association (NLA)3. This evaluation compared the economics of a lime spray dryer (SDA) and circulating dry scrubber (CDS) to a wet limestone FGD with forced oxidation (LSFO). Comparisons also were made based on multiple coal sulfur levels and two system sizes (400 MW and 500 MW). A graph from that paper is included here as Figure 2, which shows the effects of each of the three technologies on electricity’s overall cost. As can be seen, both dry technologies have a lower impact on electricity costs than the LSFO system for coal sulfur contents of less than about 2.8 percent sulfur. The conclusion from this study was that for coal sulfur contents of 3 percent or less, a wet LSFO system would result in higher overall costs than the dry technologies.

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Reducing Project Scope

The combination of the large cost increases in wet LSFO system costs, the ever-tightening environmental regulations and the move to control smaller boilers burning lower sulfur coals should improve the overall economic attractiveness of wet lime FGD systems. High FGD capital costs are causing many utilities to consider ways to reduce their project scopes. This includes outsourcing the reagent preparation and dewatering steps. Although outsourcing such activities can significantly reduce capital costs, it will increase an LSFO system’s operating costs and shrink the operational cost differences between lime and limestone wet scrubbing systems.

As utilities look to control spiraling capital costs while achieving compliance with more stringent SO2 control regulations, it seems apparent that wet lime FGD systems will re-emerge as a technically and economically viable technology alternative. A comparative evaluation of wet lime and limestone FGD systems conducted by Sargent & Lundy in 2003 showed that wet lime systems have approximately 90 percent of the capital cost of an LSFO system and that wet lime systems become favored for smaller boiler sizes.4 This evaluation was based on achieving a 95 percent SO2 removal. As SO2 removal requirements increase, it is likely that the capital cost differences between an LSFO system and a wet lime FGD system will further increase. This is due to more moderate operating conditions required by a lime FGD system to achieve a given emission reduction, as it uses a more reactive reagent. Several of the wet lime systems built in the 1990’s have shown the ability to achieve greater than 98 percent SO2 removals at much lower liquid pumping rates than required for an LSFO FGD system.

In the past, a disadvantage of a wet lime system was the cost and complexity of producing wallboard quality gypsum. Although several wet lime FGD systems produce wallboard quality gypsum today, their external oxidation systems have added cost and complexity to the FGD operations. A simpler in-situ oxidation wet lime system is now in operation, which produces gypsum similar to an LSFO system. However, now that the gypsum market is becoming fully supplied, less of a premium is being placed on gypsum production. That is because much of the gypsum that will be produced from FGD systems will end up in landfills. Further, producing a high quality sulfite byproduct with nominally 40 percent surface water may be an attractive feature, since the sulfite byproduct from a lime FGD system can be fixated to result in extremely low leachability levels. This may eliminate the need for some water treatment systems currently required to treat water discharges from LSFO FGD systems with tight water balances.

Rethinking the Choice

FGD system operations have developed significantly over the past decades to achieve high SO2 removal levels with high system reliabilities. Today, the systems of choice are dry FGD systems for low sulfur coals and wet LSFO systems for coals with sulfur contents greater than 2 percent.

Increased demand for wet FGD systems coupled with tighter environmental regulations has led to significant cost increases for LSFO technology. Wet lime FGD systems can achieve compliance with tighter environmental regulations at more moderate operating conditions than LSFO systems and can do so at a lower capital cost. The overall operational costs between an LSFO and a wet lime FGD system will be site-specific and should be evaluated as part of making a future FGD technology decision.

References

1. Market Watch article, October 5, 2006.

2. “The Real Cost of WFGD Retrofit Projects”. Thomas Meehan and Peter Kelly, Sargent & Lundy. Paper presented at POWER-GEN International, Orlando, Fla., November 29, 2006.

3. “Comparison of Wet and Dry FGD Technologies for Use with Low- and Medium-Sulfur Coals”, William Siegfriedt and Rajendra Gaikwad, Sargent & Lundy. Paper presented at Coal-Gen 2007, Milwaukee, Wis., August 1 – 3, 2007.

4. Wet Flue Gas Desulfurization Technology Evaluation. Project No. 1311-0000. Sargent & Lundy. Prepared for National Lime Association, January 2003.

Authors: Jim Dickerman and Melissa Sewell are chemical engineers dealing with new business developments for flue gas treatment applications for calcium products for Chemical Lime Co. They can be reached at [email protected] or [email protected].