New regulations are coming for underground storage tank (UST) owners and operators in Ohio. The Bureau of Underground Storage Tank Regulations (BUSTR), a division of the State of Ohio’s Fire Marshal’s office, has issued a second draft of its revised rules in the Ohio Administrative Code (OAC) at 1301:7-9-01 et. seq. The draft rules are currently being prepared for filing with the Joint Committee on Agency Rule Review (JCARR) in March/April 2017 with an anticipated effective date of July 2017, according to BUSTR.
The proposed rule revisions are intended to align with new federal UST regulations issued by the U.S. Environmental Protection Agency, which became effective October 2015, and also to comply with the bureau’s own five-year rule review requirement. The proposed amendments and rule changes include the following:
Compliance with New Federal Rules
- Certain types of UST systems that were previously exempt or deferred from state and federal regulations are now required to comply with certain BUSTR rules. These include airport hydrant fuel distribution systems, UST systems with field constructed tanks, and UST systems that solely store fuel for emergency generators.
- Six new terms were added; five to align with federal changes and one (“sole source aquifer”) to accommodate the rescission of OAC 1301:7-9-09 (“Rule 9,” see below). Eleven existing terms were amended, either for clarification or to align with federal changes.
- Rules were amended to implement new federal requirements for: 1) periodic checks of UST system and release detection components, 2) compatibility of release detection components and UST systems with tank contents, 3) methods of UST release detection, 4) retrofitting of older single-wall UST systems, 5) qualifications of persons performing work on UST systems, 6) records retention for UST system components and release detection records, and 7) requirements for release detection on airport hydrant and field-constructed systems. Numerous standards were updated relating to the construction and operation of UST systems to match corresponding federal standards.
- Rule 9, regarding USTs located above sensitive areas, was rescinded because these areas generally correspond to federally designated sole source aquifers, and more accurate geographical information now exists for owners and operators to use in determining whether an UST site is located above a sole source aquifer.
- The definition of “free product” and “suspected release” were revised in OAC 1301:7-9-13 (“Rule 13”) to match the federal version, and references were changed from “sensitive area” to “sole source aquifer” to accommodate rescission of Rule 9.
Permitting, Registration, and Closure
- The annual registration application deadline is being changed from July 1 to June 30. Registration requirements were added for compartments of a manifolded UST and for previously (but no longer) exempt UST systems. BUSTR also added a requirement to modify a registration within 30 days when there is a change of product.
- Clarified that partially exempt UST systems do not require a permit, a certified UST installer, or a certified UST inspector for tank-related activities.
- Clarified changes to the installer license renewal process.
- Clarified timeframes in OAC 1301:7-9-12 (“Rule 12”) for initiating closure assessments, added closure sampling requirements for piping runs, and revised the closure action levels table to reflect current science.
- Added Class A operators to the Class B retraining requirements, but makes retraining discretionary on the part of the State Fire Marshal instead of mandatory.
- Extended the validity of inspector certifications from two to three years, and simplified and streamlined the license renewal process.
Corrective Action, Chemicals of Concern (COCs), and Petroleum Contaminated Soils (PCS)
- The applicability section of Rule 13 was revised to allow ongoing corrective actions to continue under a previous rule version.
- Added “Biodiesel blended fuels” to the list of middle distillation products; added three new chemicals of concern (1,2,4-trimethylbenzene, 1,2-dibromoethane, and 1,2-dichloroethane); and revised action levels throughout Rule 13 to reflect current science.
- Updated public notice requirements for certain advanced corrective actions; owner/operators are now required to submit proof of notification within 90 days.
- Revised the list of re-use chemicals of concern and the action levels for petroleum contaminated soils (PCS) to incorporate most recent science, and clarified that if PCS above action levels are returned to the excavation, the cavity must be lined.
If you would like to learn more about how the new regulations may impact your operations or would like further information regarding the new BUSTR rules, contact Ron Wells (email@example.com), Tom Maher (firstname.lastname@example.org), or Andy McCorkle (email@example.com), or call (800) 365-2324.
When environmental regulations for coal-fired power plants change, effluent treatment methods currently being used may not be able to meet the new standards. Many power plant operators find that one of the new factors they must face is the EPA’s revised Effluent Limitations Guidelines (ELGs), issued in September 2015.
Recently at a mine-mouth coal-fired plant with a nominal capacity of 1,600 megawatts (MW), designers had done what they thought necessary to comply with regulatory expectations – they designed for zero discharge of process water. For blowdown water from the cooling tower, they made plans to discharge in a way that would meet National Pollutant Discharge Elimination System (NPDES) limits for the permitted outfall.
Process water is recycled internally for other plant processes, including the air quality control system (AQCS), which incorporates the flue gas desulfurization (FGD) system. However, as the wastewater continuously cycles through the two FGD absorber units, a buildup of chlorides and other constituents occurs. The level of total dissolved solids (TDS) in the purge water is controlled by blowdowns triggered by the TDS levels, and makeup water is then added to the system.
The FGD wastewater can contain TDS in excess of 31,000 parts per million (ppm), total hardness of 30,000 ppm, chlorides of 20,000 ppm, and total suspended solids (TSS) of 10,000 ppm. The blowdown wastewater is purged from the system whenever the chloride concentration in the water exceeds 20,000 ppm of chlorides.
The purged high chloride FGD wastewater is then disposed of by mixing it with fly ash and gypsum coal combustion residual (CCR) material in a pug mill. That mixture was originally disposed of at an off-site landfill, located about 20 miles away.
One seemingly small change caused this design to tip off-balance: the decision by the power plant to start its own landfill on site for disposal of the fly ash mixture. This action opened up the plant to the responsibility of managing the landfill leachate – water from precipitation flowing through the landfill, picking up contaminants along the way. The plant’s operators began pumping the leachate from the on-site landfill back to the plant’s recycle basin for re-use as make-up water. However, they found that internal recycling of wastewater is not sustainable at that location, as it results in the cycling up of chlorides and other factors that increase pipeline corrosion.
As a result, from 2014 to 2015, the chloride concentration in the recycle basin increased to three times the previous year’s concentration. The design for chlorides concentration for the recycle basin was set at less than 500 mg/L, but the data show levels approaching 3,000 mg/L within two years. These concentrations seemed likely to go on increasing unless measures were taken to manage the problem.
Problems such as these have been found at many coal-fired power plants. At the root of the problem is the fact that the water-management systems were set up to support the efficient combustion of coal to produce power. However, environmental regulations concerning water use and disposal have become more restrictive. This change has put an increasing operational focus on efficient water management to lessen the discharge of water from the plant and reduce materials of concern in that wastewater.
Thus environmental regulations, such as those intended to support zero liquid discharge (ZLD), now have an increased effect on operations, moving water management up on the priority lists of power plant operators.
One of the most common issues at many coal-fired power plants is the one seen in the story above – that, in many cases, the plant’s operators do not have a comprehensive plan for water use. They lack detailed, accurate data on which parts of the plant use water, how much those parts use, and what constituents the processes add to that water.
Many plants combine their wastewater inputs into a central flow and then treat the water that comes from that single pipe. In such cases, a more focused and cost-effective plan could be developed by segregating flows so that each stream receives only the level of treatment it needs. Segregation of wastewaters can generate substantial opportunities for recycling part of that water flow and limiting the most costly treatment and disposal methods to only the streams that need it.
For example, consider pump seal water. Many plants use clean water around the outside of the seals to reduce the possibility of the pumped fluid escaping. The pump seal water that drips out is gathered and then generally is just placed into the plant’s overall wastewater flow. Since this water is virtually clean, it would make more sense to capture this water separately so it can be treated at low cost, rather than being part of the larger, more complex wastewater flow.
Comprehensive analysis of the many water flows within a plant may be able to point to similar opportunities to segregate wastewater streams so that not all water needs to be treated with expensive methods. Specific data on water use at various points within the plant can help guide the choice of treatment approaches. At the plant described above, an astute review of the wastewater components saved the owner millions of dollars that would have been required for a new treatment plant. Instead, the plant managers were advised to use low-cost techniques for reducing the chlorides in their wastewater flow.
It is important to remember that as the plant’s operations change, the effects on the wastewater stream must be considered. The above-mentioned power plant was impacted by just such a change – the new landfill’s leachate forming a new source of chlorides to be managed.
Each coal-fired plant is different – the type of coal, equipment, and other factors such as local geology – so the following steps may be useful in finding an appropriate solution:
Analyze the current situation: One of the first steps for preparing for the new ELGs is to collect data on the flow and composition of wastewater streams and characterize typical wastewater flows.
Develop plans: Review various limiting strategies, such as reusing wastewater to reduce discharges, and then use mass balance and chemistry modeling tools to evaluate reuse, treatment, and discharge strategies to meet these new limits.
Choose management options: The choice for selecting the appropriate management tool depends on yet another wide range of factors that are better understood after carrying out the first two steps. The toolbox can include:
- Discharge to a Publicly Owned Treatment Works (POTW)
- Evaporation Ponds
- Flue Gas Injection
- Deep Well Injection (depending on factors such as geology – experience has found that the tight rock formations of Pennsylvania, for example, are less useable for this purpose than the more appropriate geologic formations of other locations, such as Florida)
- FGD wastewater treatment system (WWTS) Effluent Reuse/Recycle
- Settling Ponds
- Constructed Wetlands, Phytoremediation, and other Natural Based Systems
- Vapor-Compression Evaporation
- Physical/Chemical Treatment
- Physical/Chemical with Added Biological Treatment
- All the above can be components of a Zero Discharge approach
Other approaches utilities should consider include measures such as using existing evaporation (from cooling towers and FGD absorbers), using blowdown water for conditioning of fly ash, and other water reuse and conservation measures to reduce the amount of wastewater requiring treatment.
Working with a qualified professional with experience in each of these technologies can lead to wiser choices around which systems may be best, given the site-specific factors.
If you have any questions regarding your plant, please contact the post author, Ivan A. Cooper, P.E., BCEE, a principal based in CEC’s Charlotte, N.C., office, at firstname.lastname@example.org; (704) 226-8074.
Accelerated Remediation Catalysis (ARC) – An Emerging Water Treatment Technology for the Treatment of a Wide Range of Dissolved Phase Organic and Inorganic Contaminants
The Accelerated Remediation Catalysis (ARC) system is a process that can be applied to reduction or oxidation. For reduction, hydrogen gas and an inexpensive, proprietary catalyst are used to perform a chemical reduction of appropriate contaminants. The application of shear forces that can be achieved by using certain pumps is also a feature that dramatically accelerates reaction times.
On the reduction side, there is data supporting the degradation of 1,4-dioxane (1,4-D), perfluorocarbons (PFCs), chlorinated hydrocarbons, and oxyanions (nitrate and perchlorate). With respect to metals and metalloids such as selenium, these species are precipitated and collected for disposal. ARC is also applicable to oxidative processes for appropriate organics like petroleum hydrocarbons, as well as metals/metalloids that precipitate under high redox conditions. In this application, the oxygen is provided by dilute hydrogen peroxide or peracetic acid with a different catalyst.
To help reduce start-up costs, the ex-situ process uses common tankage, pumps, valves, and process controls that can be obtained from standard vendors. If the process handles low levels of contaminants, it can be constructed of common thermoplastics such as polyvinyl chloride (PVC), polyethylene, and fiberglass.
ARC can operate in either batch or continuous mode. In batch mode, the reaction tank is filled at start-up and the total reaction time is allowed to reach the predetermined level to assure destruction of the constituents of concern (COCs). After this point has been achieved, the process switches to continuous mode, and the reaction tank functions as a single-stage plug flow reactor. The process can be made to be continuous at start-up by simply filling the reactor tank with clean water. The overall retention time for completion of most reactions has been on the order of 10 to 15 minutes. Using reduction, hydrogen used in the catalyst vessel is generated electrochemically at the site, reducing the need to handle compressed gas. Depending on the COC, the reaction will either cause manageable gas evolution, or precipitate out of the water and be recovered by a variety of methods. The insoluble catalyst can be recovered by filtration and recycled back to the reactor vessel.
Case studies where ARC has been used for chemical reduction include:
- The conversion of 1,4-dioxane to ethanol. Water with 100 μg/l of 1,4-dioxane was reduced to <1 μg/l.
- The complete destruction of perfluorocarbons to non-detectable concentrations with a fluorine residue of low concentration, as the initial concentrations of perfluorocarbons are generally low.
- Chlorinated ethenes are easily reduced to ethene and ethane.
- Trihalomethanes have been reduced from a typical 80 μg/l level to <10 μg/l in 10-15 minutes.
- Perchlorate levels as high as 100 mg/l are reduced to chloride.
- Nitrate is reduced to nitrogen gas.
- Selenium in the form of selenate can be reduced to selenite and removed as a precipitate. Selenate was reduced from 200 mg/l to <1 mg/l.
- Chlorobenzene at ppm levels is reduced to benzene that is then collected on the low-cost catalyst.
The ARC system can be designed for a wide range of process flow rates. Design of the system is only limited by the required retention time for the reaction. In essence, the system was brought into focus because of the emerging contaminants issue, and it is applied to pump-and-treat systems. This is important because the nature of 1,4-dioxane and PFCs makes in-situ treatment challenging. It is expected that there will be both an increase in the use of pump-and-treat systems and a need for more efficient water treatment technologies, especially since conventional methods of treatment (such as those that use carbon) are limited.
Additionally, because of the low concentrations of reactants in the process, there is typically no detectable heat gain in the reaction vessel. Therefore, cooling of the process is generally not required prior to releasing the treated effluent. Then there are other applications in traditional wastewater treatment, such as removal of selenium from scrub water at coal-fired power plants. The ARC system’s inherent simplicity allows it to be easily scaled so that dealing with the large flow rates encountered in industrial settings is feasible. While the endpoint for ARC treated water is generally to be discharged, a supplementary feature called Advanced Regenerative Process (ARP) can be added as a further polishing step so that beneficial reuse, including human consumption, is an option.
ARC targets those applications where more complicated and expensive systems, such as conventional Advanced Oxidation Processes (AOP), are being used. The chemical usage, energy, and safety features of AOP systems, combined with their operational footprint, suggest they will eventually be replaced by better remedial options like ARC. There are other developing technologies that have similar objectives to displace AOP systems, such as resin-based operations, but ARC presents distinct advantages in cost, efficacy, physical layout, and scalability.
For additional information, please contact Chris Hortert at (800) 365-2324 (email@example.com); Steve Koenigsberg at (949) 262-3265 (firstname.lastname@example.org); or Thom Zugates at (602) 644-2163 (email@example.com).
Update — EPA issues final New Source Performance Standards for Oil and Gas with significant new compliance requirements
On June 3, 2016, U.S. Environmental Protection Agency (EPA) finalized amendments to the Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution (Quad O) and a new subpart at 40 CFR 5360a et seq. (Quad Oa) for post-September 18, 2015, affected facilities. As noted in a previous CEC blog on this topic, U.S. EPA received nearly one million comments following the initial proposal. The new Quad Oa rule establishes emission standards for both methane and volatile organic compounds (VOC) at natural gas and oil well sites, production gathering and boosting stations, natural gas processing plants, and compressor stations. There are several new requirements for oil and natural gas production-related activities in these new federal rules, and it is important to understand how these rules might impact ongoing compliance activities under existing state rules and permit requirements already in effect. In this update, we focus on two of these new requirements due to their history and interrelatedness.
It is clear in reading both the proposed and final rules that U.S. EPA has expanded its understanding of oil and natural gas operations, particularly with respect to upstream E&P. Notably, the requirement for a professional engineer (PE) to evaluate and certify closed vent system design brings a new level of scrutiny borne out of a consent decree with a major oil and gas producer, and placed into practice in both the September 2015 Compliance Alert and the ongoing enforcement initiative targeting “energy extraction activities.” Not only is this new requirement intended to bring industry resources to bear on what the Agency views as a significant issue, but it also attaches professional liability to any subsequent violations attributed to closed vent system design. Further, with additional attention being focused on closed vent system design, the next obvious move on the Agency’s part was either construction practices (which are in many cases guided by industry consensus standards) or the operator’s preventative maintenance program.
From an air pollution control perspective, one focus of an upstream E&P maintenance program is to minimize or eliminate fugitive emissions from production facility equipment. As addressed by the industry during the comment period, there is an economic incentive to minimize losses of otherwise saleable products. Rather than dictate the contents of a preventative maintenance program, the Agency has instead required operators to survey for and repair fugitive emissions at well sites. While not a maintenance program per se, the new rule will require operators to engage in some routine maintenance and communication planning to ensure that fugitive leaks discovered during a survey are repaired and verified within the allotted timeframe.
Many producers operating in the Utica and Marcellus plays already had some form of fugitive emissions survey requirements in effect, as does Colorado. In other states, this will be the first time operators will have to grapple with leak detection and repair programs. This new requirement will have a disparate impact on upstream E&P operators that do not have the resources to employ full-time environmental staff or purchase the equipment needed to perform these required fugitive leak surveys in-house.
A summary of the new requirements discussed above is provided here. In the meantime, if you have questions on any aspects of the NSPS for the oil and natural gas source category, please contact the post authors: John McGreevy (firstname.lastname@example.org), Kris Macoskey (email@example.com), or Ben Blasingame (firstname.lastname@example.org).
For those interested in exploring this topic further:
Final NSPS OOOO and OOOOa rule from the Federal Register
U.S. EPA National Enforcement Initiatives
CEC’s previous blog: EPA Receives Nearly One Million Comments on Proposed New Source Performance Standards for Oil and Gas
On June 3, 2016, U.S. Environmental Protection Agency (EPA) published a proposed Information Collection Request (ICR) for the oil and natural gas industry in the Federal Register for notice and comment. Once the comment period ends and EPA provides responses to all significant comments, the amended proposal will be sent to the Office of Management and Budget (OMB) for review and approval. If approved, and U.S. EPA is issued a valid OMB control number, U.S. EPA would begin collecting information from oil and natural gas companies. The Agency envisions the collection process to begin in October 2016.
The purpose of the ICR is to collect detailed information to support regulation of existing oil and natural gas stationary sources. This is in contrast with recent regulatory efforts, which have focused (primarily) on new or modified sources. The information from the proposed ICR will be used to develop a pathway for the phase-in of new standards, rather than making those standards become effective for all affected sources at once.
Based on the proposal, the ICR will be divided into two parts. The first part will be sent to all oil and natural gas operators and requires information with respect to the company and its operations. The second part requires more detailed information with respect to specific sources and could involve a significant time investment from environmental and operations teams to complete. In addition, the second part of the ICR may require information that many organizations would consider confidential. Companies with confidentiality concerns may want to involve their legal teams in this process.
Also, keep in mind that this ICR will be issued under U.S. EPA’s authority under Section 114 of the Clean Air Act. This means that the Agency has the legal authority to require all responses to the ICR be certified by a responsible official and establish a deadline for providing a response.
For those interested in reading more about the proposed ICR, the U.S. EPA has a dedicated website here. Civil & Environmental Consultants, Inc. will be following the ICR approval process closely, and plans on updating this post as events unfold. In the meantime, if you have any questions with respect to the ICR or other recent federal air pollution regulatory activity, please contact John McGreevy at 888-598-6808 or email@example.com.
EPA Receives Nearly One Million Comments on Proposed New Source Performance Standards for Oil and Gas
On September 18, 2015, the U.S. EPA proposed amendments to the Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution (Quad O) and a new subpart at 40 CFR 5360a et seq. (Quad Oa) for post-September 18, 2015, affected facilities. By the end of the comment period in December, U.S. EPA had received nearly one million comments. The proposed Quad Oa sets standards for both methane and volatile organic compounds (VOC) at natural gas and oil well sites, production gathering and boosting stations, natural gas processing plants, and natural gas compressor stations. In this blog, CEC focuses on the Quad Oa requirements for natural gas and oil well sites.
Quad Oa establishes the following requirements and definitions for fugitive equipment leaks:
- For the first time, operators of well sites will be required to control fugitive methane and VOC emissions.
- A fugitive emission is defined as “any visible emission from a fugitive emissions component observed using optical gas imaging.”
- A “fugitive emission component” is essentially any component that could leak methane or VOC.
- A leak detection and repair (LDAR) plan that includes a site map and a defined walking path for monitoring surveys will be required.
- An initial monitoring survey must be conducted within 30 days of the first well completion or modification.
- Following the initial survey, the LDAR monitoring frequency will be performance-based, meaning that the sites with a higher percentage of leaks will have to monitor more frequently than other sites.
- Each leak must be repaired or replaced within 15 calendar days unless doing so is technically infeasible or unsafe.
- Operators may resurvey the repaired leak with either Method 21 or optical gas imaging (OGI). The leak is repaired when the Method 21 reading indicates < 500 ppm above background or OGI shows no leak.
- Operators must maintain records specific to each monitoring survey.
These new fugitive emission requirements generated a huge volume of comments. On review of comments from trade organizations including American Petroleum Institute (API), Gas Processors Association (GPA), Interstate Natural Gas Association of America (INGAA), Independent Petroleum Association of America (IPAA), and Pennsylvania Independent Oil and Gas Association (PIOGA), we found that the majority fall into four general categories, as summarized below.
1. Leak Detection Methodology
The trade organizations stated that EPA should not dictate a specific technology for detecting leaks and that EPA should allow for any of the six or more other technologies or techniques, rather than requiring the use of OGI for leak detection. The trade organizations caution that the motivation to innovate these technologies will be greatly reduced if the rule precludes other methods from being used to detect leaks. As such, many commenters stated that the final rule should allow flexibility for leak detection including Method 21 and other future EPA-approved technologies.
2. Monitoring Frequency
The majority of the trade organizations are opposed to performance-based monitoring frequencies. The primary concern with such programs is that they oblige the operator to count and tag every component so that percentages of leaking components can be calculated. Industry’s perspective is that due to economics and safety concerns, the incentive to repair leaks is present regardless of a performance-based monitoring frequency. The potential for different facilities being monitored at different frequencies is expected to significantly complicate recordkeeping requirements without significantly improving the results. In addition to being a burdensome and costly requirement, commenters pointed out that EPA’s assumed fugitive emission reduction rates for inspection frequencies are not supported by well-documented data. Rather than performance-based monitoring, the trade organizations generally agree that LDAR monitoring should occur at a fixed annual frequency.
3. Focus on Gross Emitters
In the preamble to the rule, EPA references studies that demonstrate a majority of leaks from this industry (more than 80 percent in one study) come from a small segment of sources referred to as “gross emitters.” The EPA requested comment on a program focused on these “gross emitters.” The trade organizations are in agreement that the proposed rule should focus on emissions from these sources (such as thief hatches on condensate storage tanks) and not on the trivial leaks that can be detected by OGI. By drawing attention to these large potential sources, EPA enabled industry to point out the irrelevance of performance-based LDAR programs that would effectively equate a single super-emitter with an insignificant valve leak when determining the percentage of leaking components.
4. Initial Monitoring Timing
All of the trade organizations’ comments reviewed by CEC indicated their disapproval of the requirement that an initial monitoring survey be performed within 30 days. API pointed out that within the first 30 days of startup, extra temporary equipment will be on site. GPA discussed that the first 30 days after startup is a frenetic time when temporary construction staff and heavy equipment are on site. GPA and INGAA identified the discrepancy between the proposed Quad Oa and other existing rules for other industries. GPA pointed out that EPA allows for a 180-day initial startup window for fugitive emission monitoring in the synthetic organic chemicals manufacturing industry under NSPS subpart VV and VVa. INGAA stated that MACT standards at 40 CFR 63 subparts JJJ, KKKK, and ZZZZ allow 180 days or longer to complete the initial performance test. The degree of the extensions for the initial survey varied: IPAA and PIOGA requested a 60-day window while API, GPA, and INGAA requested 180 days.
CEC estimates that hundreds of comments are focused on these four topics alone. In addition to these four issues, other topics included:
- inconsistencies between existing state programs and the proposed federal rule,
- flawed aspects with the EPA’s cost-benefit analysis,
- a request for an expansion of available exemptions, and
- the need for additional definitions and clarifications.
For those interested in exploring the comments, they can be found at the following link to the main docket of the proposed rule: https://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2010-0505-4776
The EPA anticipated being finished with their review of the comments by the spring of 2016. CEC will be following the final rule development closely. In the meantime, if you have questions on any aspects of the NSPS for the oil and natural gas source category, please contact the post authors, Ben Blasingame (firstname.lastname@example.org) or Kris Macoskey (email@example.com). Both individuals can also be reached at 800-365-2324.
The next submission period for the U.S. EPA’s Chemical Data Reporting (CDR) requirement under the Toxic Substances Control Act (TSCA) is from June 1, 2016, through September 30, 2016, and will cover the 2012 – 2015 reporting years. The previous CDR submission was in 2012 for the 2010 and 2011 reporting years.
Manufacturers and importers of TSCA inventory-listed chemical substances that exceed either the reduced reporting threshold (2,500 lbs/yr for certain chemical-specific TSCA Actions) or the standard reporting threshold (25,000 lbs/yr for all other listed chemicals) for any calendar year from 2012 through 2015 must prepare a CDR for each chemical exceeding the respective thresholds and submit to U.S. EPA. Note that a CDR must be submitted covering all four reporting years if a facility exceeds an applicable threshold in any year.
For chemicals that are imported to the U.S., note that only the primary importer of a chemical (generally the entity responsible for payment of import tariffs) has the TSCA CDR responsibilities. A facility that purchases an imported chemical from the primary importer (or other down-stream entity) is not responsible for preparation of a TSCA CDR for that chemical.
The report must be filed electronically using the U.S. EPA’s Central Data Exchange (CDX) and must include production quantities for calendar years 2012, 2013, 2014 and 2015, as well as the following information for 2015:
- Manufacturing Related Data
- Chemical ID,
- Production quantity,
- Number of workers on site who are likely to be exposed to the chemical,
- Maximum concentration, and
- Physical forms and relative production of each form.
- Processing Related Data
- Types of processes / use (up to 10),
- Industrial function categories,
- Percent of production,
- Number of sites, and
- Number of workers off site who are likely to be exposed to the chemical.
- Consumer and Commercial Use Related Data
- Product categories,
- Whether the product is intended for use by children,
- Percent of production,
- Concentration range, and
- Number of commercial workers who are likely to be exposed to the chemical.
For the 2016 submission, calendar year 2015 is the principal reporting year, which requires the presentation of enhanced manufacturing / processing and use data.
Whether a chemical substance is covered or not covered by TSCA can be determined by searching the U.S. EPA’s Substance Registry Services (SRS) web page.
Note that the current TSCA list includes more than 60,000 chemicals.
Chemicals applicable to CDR submission are identified as “TSCA Inv” in the chemical-specific search tables.
Common chemical substances (by industry sector) included on the TSCA inventory that may be subject to CDR requirements include:
- Primary Metals – Steel, Slag, Baghouse Dust, Copper, Zinc, Manganese and Chromium;
- Secondary Metals – Mill Scale, Zinc Oxide and Ferro Manganese;
- Aggregates – Lime, Hydrated Lime, Bentonite and Kaolin;
- Power – Coal Ash;
- Paper – Secondary Treatment Sludge;
- Refineries – Gasoline and Diesel Fuel;
- Industrial Gases – Hydrogen, Oxygen, and Nitrogen; and
- Miscellaneous – Glass, Tanning Waste and Cement.
TSCA includes a number of important exemptions from CDR reporting, including:
- Byproducts that are disposed (i.e., not released to commerce) need not be reported;
- A chemical present as an impurity (unintentionally present in another chemical substance) is exempt from reporting;
- Polymers have a full reporting exemption;
- Naturally occurring chemical substances have a full reporting exemption; and
- Certain listed forms of natural gas and natural gas liquids have a full reporting exemption.
In addition, partial exemptions are available for certain petroleum process streams and for other common chemical substances (e.g., limestone, hydrogen, oxygen, nitrogen).
Additional information on the TSCA CDR program is provided on the U.S. EPA’s Chemical Data Reporting web page.
If you have any questions about the 2016 TSCA Chemical Data Reporting, please contact Dennis Ritter at firstname.lastname@example.org or 412-429-2324.