Whether you are planning new assets or improving operational efficiency at existing plants, getting environmental monitoring right is important to unlock value and boost profitability because it is impossible to succeed in a regulated environment if you cannot control emissions and capture real-time operational data. Good controls in combination with accurate data are the key to promoting compliance, avoiding penalties, increasing uptime and lowering total cost of ownership (TCO).
Environmental monitoring sometimes is viewed as a recently introduced cost of business. But environmental monitoring has been a mandated part of many industrial production processes since the enactment of the Air Pollution Control Act of 1955. Moreover, the federal government recently renewed an environmental justice interagency working group tasked with developing proposals that could lead to more stringent EPA rulemaking, permitting, community programs, and compliance and enforcement decisions. The ongoing focus on health and environmental concerns, particularly in urban areas, suggest that regulation and monitoring requirements are likely to become more stringent in the years ahead, not less.
How We Got Here
The U.S. Congress enacted its first significant air-pollution legislation, the Air Pollution Control Act, in 1955. The Clean Air Act (CAA) followed in 1963. This second legislation marked the beginning of more aggressive environmental monitoring and enforcement. While the CAA authorized research and technical assistance, it also included specific pollution control requirements for power plants, steel mill, and other stationary sources.
The Clean Air Act Amendments of 1970 for the first time required the EPA to establish minimum national air-quality standards while allowing states to oversee enforcement. Under the amendments, state governments were required to submit state implementation plans (SIPs) to the EPA for approval before this transfer of enforcement responsibility could occur.
Subsequent acts and amendments on the federal level have added many more provisions for reducing air pollution from local, interstate and international sources. Federal legislation is primary because these statutes preempt state and local legislation under the supremacy clause of the U.S. Constitution. However, U.S. environmental law sometimes allows the state to enact regulations if the state provisions are more stringent than the corresponding federal legislation.
California plays a unique environmental policy role among the states because the California Environmental Protection Agency (Cal/EPA) was established three years before the CAA Amendments were enacted at the federal level. In California, actual rule making and oversight are tasked to the California Air Resources Board (CARB), which is a department within Cal/EPA. Under the 1970 Act, states can apply to the EPA to adopt the CARB standards.
Because California has a unique climate, geography and automobile culture, the CARB has occasionally enacted rules that are more restrictive on emissions than federal standards. Starting in the early 1990s, several Eastern and Western states requested permission from the EPA to switch to stricter emission standards being followed in California. By 2007, 11 states had adopted the California regime with six other states considering similar action. States are also adopting California's goal of reducing passenger car greenhouse gases to 1990 levels by 2020.
The State of California has 12 Air Quality Monitoring Districts (AQMDs). The AQMDs are county or regional governing authorities with primary responsibility for regulating stationary sources of air pollution in their defined areas.
Key EPA Regulations and State Administrative Codes
The Code of Federal Regulations (CFR) and more specifically by Title 40, Protection of the Environment, applies to refineries, factories, power plants and other large industrial sources. Sources that operate in California or a state that adopts California standards are probably also subject to laws, rules and regulations administered by the CARB.
Note: EPA regulations, state administrative codes and other air quality mandates prompt many legal challenges. Current law allows individuals and state and local governments to sue the EPA to overturn proposed and enacted regulations. As a result, numerous regulatory challenges are usually underway at all times in the federal and state court systems. Decisions in these cases can significantly affect monitoring requirements and enforcement mechanisms. For example, In October 2013, the Supreme Court agreed to hear a utility industry challenge to the administration's new regulations for stationary sources, while at the same time confirming the EPA's ability to regulate greenhouse gases. This case will be argued in the first half of 2014 with a decision likely the following summer.
The next few pages contain a review of the regulatory landscape and the key provisions that are typically of most concern to managers of these facilities. This section also identifies types of monitoring solutions that promote compliance and facilitate continuous process improvement.
- EPA 40 C.F.R. Part 60.18 and SCAQMD Rule 1118, Control of Emissions from Refinery Flare
- EPA 40 C.F.R. Part 63, National Emission Studies for Hazardous Air Pollutants from the Portland Cement Manufacturing Industry
- EPA 40 C.F.R. Part 60, Power Plant NOx Emissions from NH3 Slip
- EPA 40 C.F.R. Part 60.100, Subpart J and EPA 40 C.F.R. 60.100a Subpart Ja Amendments for New Source Performance Standards for Petroleum Refineries
- EPA 40 C.F.R. Parts 59, 80, 85, and 86, Control of Emissions of Hazardous Air Pollutants from Mobile Sources
- California Air Resources Board AB32 Global Warming Solutions Act
- Texas Commission of Environmental Quality (TCEQ) Title 30 Part 1 Chapter 115, Control of Air Pollution from Volatile Organic Compounds
EPA 40 C.F.R. Part 60.18 and AQMD Rule 1118, Control of Emissions from Refinery Flare Analysis
EPA 40CFR60.18 and AQMD Rule 1118 limit the emissions of volatile organic compounds (VOCs) into the atmosphere by large combustion plants and other sources. The AQMD adopted Rule 1118, Control of Emissions from Refinery Flares, in 2005. The rule regulates VOC, sulfur dioxide (SOx), and nitrogen dioxide emissions, benzene and volatile organic compound emissions from flares and related process units. It is progressively reducing these emissions to zero by requiring plant operators to implement flare recovery systems.
If you operate a large source such as a petroleum refinery, sulfur recovery plant or hydrogen production plant, you must comply with the EPA and/or California rules by maintaining a minimum heating value at the burner tip. Using auxiliary fuel, steam or air to promote mixing typically creates this heating value. Compliance entails destroying more than 98 percent of VOCs in flue gases while producing no visible emissions, except for periods of less than 5 total minutes during any two consecutive hours.
Emissions consists of hydrocarbon and sulfur components, including carbon monoxide (CO), carbon dioxide (CO2), nitric oxide (NO), nitrogen oxides (NOx), sulfur dioxide (SO2), oxygen (O2), hydrochloric acid (HCI), hydrofluoric acid (HF), ammonia (NH3), water (H2O), and other chemicals.
You can use continuous gas analysis to monitor for regulated molecules in flue gases. Because of cooperation between plant operators and local AQMD, suppliers are producing online analytical systems for automatically measuring waste gas in flares. But note that analysis requires a reliable, complete system that is designed for the application.
Online analytical systems are able to extract samples and prepare them for analysis. Suppliers provide different versions of these systems for monitoring and recording data at refineries and related flaring operations.
In some configurations, you can use these systems to quantify, control and minimize flaring and flare-related emissions. The systems can measure the heat value of individual hydrocarbons as well as higher heating value (HHV) contents exceeding 3,000 BTUs. Other devices can determine the total sulfur dioxide concentration of flares with measuring ranges from the low parts per million (PPM) to more than 50 percent. These measuring devices are very robust and remain quantitative even under upset plant conditions. However, you must maintain the sample transport system above 230 °F from the source to the analyzer.
EPA 40 C.F.R. Part 63, National Emission Studies for Hazardous Air Pollutants from the Portland Cement Manufacturing Industry Analysis
If you operate a Portland cement plant, you are subject to this mandate. The EPA received permission to regulate Portland cement plants as part of the CAA of 1999. Rule making and revision has been ongoing with the EPA issuing an update to Part 63 in January 2011. The rule requires continuous analysis of flue gas in existing or new kilns, clinker coolers, raw material dryers and raw miles. Kilns, clinker coolers and raw material dryers subject to emission controls before September 9, 2010, must continue to meet specified limits until September 9, 2013. For sources commenced or reconstructed before December 2, 2005, monitoring is required for all operational modes.
The air pollutants most associated with cement manufacturing (regulated and non-regulated) include particulate matter, NOx, SO2, CO, CO2, hydrocarbons, HCl, HF, mercury (HG), heavy metals and other substances. Some of these pollutants are present at significant mass rates or measurable concentration levels in the flue gases associated with specific processes. Where this is the case, you can do gas analysis at the stack to demonstrate compliance for the entire plant and satisfy federal, state and local authorities.
While monitoring represents an overhead expense, years of data suggest that it also has a positive impact on clinker quality, fuel use and regulated environmental emissions. Analytical systems used in monitoring allow you to assess the combustion processes and detect malfunctions early in the production process while there is still time to deploy appropriate countermeasures. Plus, stable control of all cement-manufacturing processes is an effective way to avoid fines that would otherwise be levied for releasing prescribed materials.
EPA 40 C.F.R. Part 60, Power Plant NOx Emissions from NH3 Slip Analysis
Environmental provisions in the Clean Air Act of 1990 require power plants to reduce NOx emissions. Selective catalytic reduction (SCR) and selective non-catalytic reduction (SNCR) processes are able to reduce NOx emission by injecting ammonia into the combustion flue gas, which ideally reacts with the NOx to form H2O and nitrogen gas (N2)).
If you operate one of these sources, you must monitor at the outlet for excess ammonia gas (NH3) to determine the efficiency of the SCR and SNCR processes. This monitoring process is referred to as NH3 slip.
The flue gas sample at the measurement point is hot and wet. In coal-fired plants, it is also laden with dust (although this not usually a problem in gas-fired plants). The SNCR process typically uses ammonia (NH3) or urea (CO(NH2)2) to reduce NOx emissions. The ammonia is introduced into and mixed with the flue gases in the hot combustion zone to affect the reduction.
Depending on the type of reducing agent and additives, among other issues, the SNCR process usually operates from 800 °C to 950 °C (1472 °F to 1742 °F). The harsh conditions at the sample point coupled with the highly reactive nature of NH3 make reliable extractive low-level analysis difficult. Because of these challenging conditions, one supplier introduced an in situ, tunable-diode laser analyzer, which has been able to cope with these conditions and measure NH3 and water vapor in the combustion flue gas just after the power plant reduction process.
To optimize SCR performance for reduced NOx emissions and increased power plant efficiency, you must measure and control NH3 slip at less than or equal to two parts per million (PPM). Historically extractive systems have been used to measure NH3 at much higher levels. Some extractive NH3 analysis systems are not a direct NH3measurement, but require multiple converters (modified NOx analyzers) with high maintenance compared to in situ, tunable-diode laser NH3 slip monitors. These modified NOx analyzers have not been able to reliably measure NH3 in the one to two PPM range in the duct just after the SCR. Some power plant operators have used extractive analyzers with ion mobility spectroscopy (IMS) technology in this application. But the in situ tunable-diode laser has demonstrated an alternative that is just as reliable with more affordable installation and maintenance cost.
Extraction sampling provides a point-source measurement, which is a less accurate reflection of actual conditions in the duct. An in situ type analysis system, on the other hand, never leaves the process, which means the NH3 concentration is not affected by sample transport. Further, there is no sample handling system components to fail because of heat, dust, water or usage. The system's average measurement offers superior evidence of compliance since the NH3 concentration is highly stratified in the duct of a coal-fired power plant. If a tunable-diode laser is employed, it is also possible to measure the true average NH3 concentration in the duct.
EPA 40 C.F.R. Part 60.100, Subpart J and EPA 40 C.F.R. 60.100a Subpart Ja Amendments for New Source Performance Standards for Petroleum Analysis
EPA subpart J and subpart Ja include monitoring rules for flue-gas components. Operators of large combustion plants often see these requirements as an impediment to business, but there is evidence that using gas analysis for emission monitoring can yield insights into the production process, and that such analysis provides an opportunity for improving boiler control and deNOX and deSOX plant performance.
In response to industry action, both EPA subparts have been subject to intensive study. The EPA began reviewing the Petroleum Refinery New Source Performance Standards (NSPS) subpart J in 2005. It finalized a revision to subpart J and issued a new NSPS subpart J in 2008. Subpart J limited green house gases (GHGs) produced by petroleum refineries and associated equipment, including flares, process heaters, fluid catalytic cracking units, fluid cokers, delayed cokers and sulfur-recovery plants. The final standards reflect demonstrated improvements in emissions control technologies and work practices that have occurred since the original standards were issued
To address an error in the flare gas minimization requirements, the agency issued subpart Ja. The final amendments to subpart Ja include separate performance standards for new, modified or reconstructed fuel gas combustion units (flares) at petroleum refineries. ("New" applies to modified or reconstructed flares.) Flares constructed, modified or reconstructed on or before June 24, 2008, must comply with subpart J, as amended.
The NSPS also contains an alternative compliance option for refinery flares located in the South Coast Air Quality Management District (SCAQMD) or the Bay Area Air Quality Management District (BAAQMD). An affected flare subject to 40 CFR part 60, subpart Ja may elect to comply with SCAQMD Rule 1118 or both BAAQMD Regulation 12, Rule 11 and BAAQMD Regulation 12, Rule 12 as an alternative to complying with the requirements of subpart Ja.
According to the EPA, a flare is a combustion device that uses an uncontrolled volume of air to burn gases. It includes the foundation, flare tip, structural support, burner, igniter, flare controls (including air injection or steam injection systems), flame arrestors and the flare gas header system. For an interconnected flare gas header system, the flare includes each individual flare serviced by the interconnected flare gas header system and the interconnected flare gas header system.
Some flare piping changes and upgrades are allowed without triggering a reclassification under subpart Ja, but the specifics of these guidelines are outside the scope of this paper.
Subpart J require a reliable, complete system that is especially designed for measuring CO, CO2, NO, NOx, SO2, O2, HCl, HF, NH3 and H2O in flue gases in prescribed facilities. Subpart Ja, which applies to new process units, includes emissions limitations for particulate matter, NOx, SO2, CO, H2S, and Total Sulfur.
Refiners are subject to potential claims as part of the Clean Air Act's New Source Performance Standards, National Emission Standards for Hazardous Air Pollutants and the New Source Review process. Permitting and installation requirements and enforcement settlements often require operators to install advanced leak detection, repair monitoring programs and improve flare efficiency.
Operators can avoid these complications by installing a continuous emission monitoring system that reliably covers all requirements. Suppliers offer advanced solutions that enable you to select measuring ranges, capture and prepare samples, and conduct gas analysis. Different versions of these systems support modification, so you can meet evolving requirements without having to replace effective equipment.
40 C.F.R. Parts 59, 80, 85, and 86, Control of Emissions of Hazardous Air Pollutants from Mobile Sources Analysis
This rule is intended to reduce emissions from benzene and other hydrocarbons such as 1,3-butadiene, formaldehyde, acetaldehyde, acrolein and naphthalene. Mobile source air toxics (MSATs) are produced by gasoline, passenger vehicles and portable fuel containers such as gas cans. MSATs are singled out because of they are known human carcinogens, and mobile sources are responsible for the majority of emissions.
The rule significantly lowers MSAT emissions by lowering benzene content in gasoline, reducing exhaust emissions from passenger vehicles operated under 24 °C (75 °F) and reducing emissions that evaporate from and permeate through portable fuel containers. The rule is being phased in between 2010 and 2015.
Refineries are currently required to meet an annual average gasoline benzene content standard of 0.62 percent by volume (vol%). This requirement applies to reformulated and conventional gasoline produced nationwide. The program also includes a nationwide averaging, banking and trading program.
In addition to the 0.62 vol% standard, refiners must also meet a maximum average benzene standard of 1.3 vol%. A refinery's or an importer's actual annual average gasoline benzene levels may not exceed this maximum average standard.
The final rule adds benzene alkylation to the four operational or technological changes that the 2007 rule allows as a benzene control technology. This action also allows refiners to request EPA approval for other benzene-reducing operational changes or technologies in exchange for early credits.
ASTM Method D3606-99 outlines how to use gas chromatography to measure benzene in gasoline. Complete turnkey solutions for implementing this type of monitoring are easily implemented.
California Air Resources Board AB32, Global Warming Solutions Act Analysis
The California Global Warming Solutions Act of 2006 is intended to reduce GHG emissions to 1990 levels by 2020. Under the act, the CARB is directed to implement early actions for reaching this goal while also working on a long-term plan for further emission reductions.
On January 1, 2010, CARB began to enforce early measures, which included new regulations, market mechanisms. A year later, CARB completed its major rulemaking for reducing GHG and adopted a cap-and-trade program covering major sources such as refineries, power plants, industrial facilities and transportation fuels. These enforceable regulations established emission limits that will decline over time until the 2020 goal is achieved. Sources that participate in the cap must surrender allowances and offsets equal to their emissions at the end of each compliance period.
The program is presently voluntary with three levels of participation: opt-in covered entities; voluntarily associated entities; and other registered participants. The program targets CO2, methane (CH4), nitrous oxide (N2O), fluorohydrocarbons, and sulfur hexafluoride (SF6).
If you are subject to AB32, you can perform most emission calculations based on heat value, published factors and flow, but some emission sources need online monitoring. You also might need to calculate a BTU measurement for combustion using variable heat content fuel.
Here is a quick breakdown of the industries that are most likely affected by California's plan to lower GHGs:
- Cement plants;
- Petroleum refineries and hydrogen plants with CO2 emissions greater than or equal to 25,000 metric tonnes per calendar year;Individual electric generating facilities with a nameplate generating capacity greater than or equal to 1 megawatt (MW) and CO2 emissions greater than or equal to 2,500 metric tonnes per calendar year;
- Retail providers and marketers as defined by the ct's provisions;
- Individual cogeneration facilities with a nameplate generating capacity greater than or equal to 1 megawatt (MW) and CO2 emissions greater than or equal to 2,500 metric tonnes per calendar year;
- Other stationary combustion sources with facilities CO2 emissions greater than or equal to 25,000 metric tonnes per calendar year
Suppliers provide full turnkey solutions for monitoring the emission requirements detailed under this act.
Texas Commission of Environmental Quality (TCEQ), Title 30, Part 1, Chapter 115, Control of Air Pollution from Volatile Organic Compounds Analysis
In Texas, the Beaumont and Port Arthur area, specifically Hardin, Jefferson and Orange Counties, has significant concentrations of sources industries. Texas implemented this administrative code to ensure ozone attainment compliance in the specified areas and their surrounding communities. The previsions of the code have different requirements based on type of plant, equipment and emission.
The code requires continuous, online monitoring of highly reactive volatile organic compound (HRVOC) in flares and cooling towers and maintaining these emissions within allowed levels. Operators have annual emission limits. Along with monitoring, they must control and/or reduce emissions according to a plan supervised by local regulators.
Monitoring flares entails providing real-time measurements of selected HRVOCs and BTU values. For cooling tower, monitoring must measure the total VOC content in the water continuously and with laboratory speciation. A solution that uses continuous online measurement to provide speciation for HRVOCs in the water is acceptable.
A continuous flame ionization detector that measures total VOC content as methane-plus or ethane-plus satisfies the regulatory requirements. Operators can also use on-line process gas chromatography if the solution can selectively measure the specified HRVOC components. This approach is an attractive option for many situations, since it greatly reduces the laboratory burden and, in some configurations, has the added benefit of also providing flare monitoring.
Industrial operators must implement effective monitoring solutions to comply with the many federal, state and local emission regulations that directly affect their facilities. These regulatory requirements are only likely to become more stringent in the future as governments continue to search for ways to reduce airborne toxins and GHGs.
Fortunately, the private sector offers affordable, effective solutions for monitoring and controlling emissions. In some cases, these technologies can actually improve operational efficiency while lowering costs. At the same time, operators should carefully evaluate available solutions to determine their real-world monitoring effectiveness and TCO. Most environmental monitoring regimes require, at a minimum, 95 percent uptime (18 days per year on average).
Only well-designed systems can achieve this level of performance without requiring constant intervention, adjustment and complex maintenance. Fortunately, suppliers offer standard, turnkey designs that greatly reduce overhead, support and utility costs without compromising performance.