EPA`s Sec. 112(r) Risk Management Program

Issue No. 17
EQ
environmental quarterly
A Trinity Consultants Publication
FALL 2013
Regulatory UPDATE
2 Complying with EPA’s Risk Management Program
8 Federal Court Vacates GHG Permitting Deferral for
Biogenic Sources
12 Developing a Boiler NESHAP Compliance Strategy
14 Developing a Boiler NESHAP Energy Assessment Strategy
16 ISO 50001, Energy Management System – The Other Boiler MACT Option
technology
11 Dispersion Modeling Notes
21 API Releases SANGEA 4.1 for Standardized GHG Emissions Reporting
COMPANY NEWS
10 Trinity’s Rocky Mountain Team
11 Trinity Expands into Canada
20 Trinity’s Consultant Helps Ensure Clean Drinking Water in Fiji
Addressing Industrial Risk with
EPA’s Sec. 112(r)
Risk Management
Program
Complying with EPA’s Risk
Management Program
By sharon killian, Principal Consultant — New Orleans, LA • jon hill, Managing Consultant — Raleigh, NC
Recent industrial accidents that have resulted in loss
of lives and significant property damage have increased
visibility of OSHA’s Process Safety Management
Program and EPA’s Risk Management Program, both
of which relate to safe operations of industrial sites.
It is imperative for industrial companies to be diligent
in their obligations in order to maintain compliance
and protect employees and the community.
that appropriately match their size and the risks they
pose. As a result, different facilities covered by the
regulations may have different requirements depending on their processes. Program Level 1 has the least
stringent requirements of the three levels, whereas
Program Level 3 has the most stringent requirements.
The goal of EPA’s Risk Management Program (RMP)
is to prevent major chemical accidents from causing
disasters by establishing a prevention and response
program. The RMP program, developed under Section
112(r) of the 1990 Clean Air Act Amendments and
promulgated under 40 CFR 68, regulates the storage
and/or processing of toxic and flammable substances.
It requires affected facilities to develop and submit
Risk Management Plans. These plans must be submitted to EPA and renewed/updated every five years or
more often, if needed.
Program Level 1
(epa.gov/emergencies/docs/chem/Chap-02-final.pdf)
applies to processes that would not affect the public
in the situation of a worst-case release (in accordance
with 40 CFR 68, processes “with no public receptors
within the distance to an endpoint from a worst-case
release”) and with no accidents with specific offsite
consequences within the past five years. Program 1
imposes limited hazard assessment requirements and
minimal accident prevention and emergency response
requirements.
RMP Applicability Determination
Program Level 2
(epa.gov/emergencies/docs/chem/Chap-02-final.pdf)
applies to processes not eligible for Program 1 or
subject to Program 3. Program 2 imposes streamlined
accident prevention program requirements, as well
as additional hazard assessment, management, and
emergency response requirements.
To determine RMP applicability, the first step is to
determine whether the facility uses any of the listed
chemicals in quantities that exceed the program
applicability thresholds. (epa.gov/osweroe1/docs/
chem/Appendix-A-final.pdf) (Note that states which
have received delegation of the Clean Air Act Section 112(r) program from EPA may have additional
requirements for the federally listed chemicals, and/or
additional listed chemicals.)
RMP Program Levels
The next step is to determine which “Program Level”
applies to the process. EPA has classified affected RMP
processes into three distinct “Program Levels” to ensure
that individual processes are subject to requirements
2 Environmental Quarterly | Fall 2013
Program Level requirements include:
Program Level 3
(epa.gov/emergencies/docs/chem/Chap-02-final.pdf)
applies to processes not eligible for Program 1, and
either subject to OSHA’s Process Safety Management
(PSM) standard [29 CFR 1910.119], or classified in one
of ten specified North American Industrial Classification
System (NAICS) codes. The ten NAICS codes apply
to pulp mills, certain chemical manufacturers, and
petroleum refineries. They do not apply to chemical
distributors. Program 3 imposes OSHA’s PSM standard
as the accident prevention program as well as
additional hazard assessment, management, and emergency
response requirements.
In determining program levels for a facility process(es), keep in
mind the following:
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The program levels apply to individual processes and generally indicate the risk management measures necessary to comply with this regulation for the process, not the facility as a whole. The eligibility of one process for a program
level does not influence the eligibility of other covered processes for other program levels.
Any process can be eligible for Program 1, even if it is subject to OSHA PSM or is in one of the ten NAICS codes.
Program 2 is the default program level. There are no “standard criteria” for Program 2. Any process that does not meet the eligibility criteria for either Programs 1 or 3 is subject to the requirements for Program 2.
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Only one Program level can apply to a process. If a process consists of multiple production or operating units or storage vessels, the highest Program level that applies to any segment of the process applies to all parts.
For Program 1 processes, based on their limited potential for
serious offsite consequences, facilities are not required to implement a prevention program, an emergency response program,
or a management system. Facilities with processes in Program 2
and Program 3 must address each of the three RMP Plan components as described below for those processes.
RMP Plan Components
> Hazard Assessment – evaluation of the potential effects of an accidental release, including an estimate of potential release quantities and a determination of downwind effects
Fall 2013 | Environmental Quarterly 3
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Prevention Program – intended to prevent accidental
releases of regulated substances, including safety precautions and maintenance, monitoring, and employee measures to be used at the source
Emergency Response Program – provides for specific actions to be taken in the event of an accidental release, including procedures for informing the public and local agencies responsible for responding to accidental releases, emergency health care, and employee training measures.
Hazard Assessment
The hazard assessment consists of:
> an inventory of listed substances
> a five-year history of releases
> an off-site consequence analysis (OCA)
The OCA is the centerpiece of the hazard assessment; it is an
estimate of risk to people and the environment beyond the
facility’s fenceline that can result from a chemical release.
The OCA answers four basic questions:
1.
2.
3.
4.
What hazardous substance(s) could be released?
How much of the substance(s) could be released?
How large is the hazard zone created by the release?
How many people could be affected?
The RMP regulations require that an Off-site Consequence
Analysis (OCA) be conducted for the worst-case release of the
regulated chemical(s). The first step is to identify the appropriate release scenarios based on a facility’s process safety information as well as operational knowledge. The release scenarios for
a given RMP-subject process are generally identified as part of a
process hazard analysis (PHA).
Typically, a worst-case release scenario is first evaluated, whereby
the entire contents of a chemical storage vessel are released
over a 10-minute time period. An example of a worst-case
release scenario could be the rupture of the largest ammonia
tank in an ammonia process with the total loss of the contents.
Next, a typical OCA will also include an alternative release
scenario where safety procedures may make total releases less
likely, and where modeled meteorological conditions are based
on actual site location, not simply a worst-case assumption.
A facility can use EPA’s chemical- and release rate-specific lookup
tables or other, more refined emergency air dispersion models
to calculate the distance out to which impacts may exceed the
4 Environmental Quarterly | Fall 2013
toxic endpoint. The RMP rule does not specify which model
should be used other than the model should be one that 1)
is publicly available, 2) accounts for the required modeling
conditions, and 3) is recognized by industry as acceptable. The
advantage of using an air dispersion model is that it may be
more accurate than EPA’s methodology for predicting the mixing
of pollutants in air and the distance to end­point.
In order of complexity, possible analytical approaches include:
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EPA look-up tables
ALOHA (Aerial Location of Hazardous Atmospheres)
dispersion model
BREEZE® Incident Analyst (includes additional dense gas and fire/explosion models)
EPA’s look-up tables are contained within the RMP*CompTM
program, available on EPA’s website. These tables are easy to
use and are a quick way to assess incidents. However, the tables
are based on conservative assumptions that may indicate major
impacts at the predicted distance to the toxic endpoint for a given
chemical. In fact, hazard distances using the lookup tables may
exceed those from refined modeling by as much as 5-10 times.
If modeling is preferred, it is often performed with EPA’s ALOHA
model, which consists of both neutrally-buoyant and dense gas
models. The user inputs source release data for the chemical(s)
of interest and the program selects the appropriate model
based on the chemical phase and expected atmospheric behavior. Another option is the BREEZE® Incident Analyst program
for accidental chemical releases and consequence modeling.
It contains a full suite of industry-proven toxic dispersion, fire,
and explosion models, and powerful tools for assessing threats
to life and property due to accidental chemical releases. The
additional tools give the analyst access to additional modeling
functionality that could characterize releases in a more realistic
manner than RMP* Comp or ALOHA may allow.
Prevention Program
The Prevention Program consists of seven different elements:
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Process Safety Information
Process Hazard Analysis
Operating Procedures
Training
Maintenance (Mechanical integrity)
The goal of EPA’s Risk Management Program (RMP)
is to prevent major chemical accidents from causing
disasters by establishing a prevention and response
program.
> Compliance Audits
> Incident Investigation
EPA developed the Prevention Program by identifying these
seven basic elements that are the foundation of sound prevention practices. These elements must be integrated into the
RMP plan and implemented on an on-going basis. For example,
the hazard review must be built on the safety information that
has been compiled. The results of the hazard review should
be used to revise and update the operating and maintenance
procedures. Workers must be trained in these procedures and
then use them every day. Preventive maintenance, including
routine inspections, reduces the number of equipment failures
and down time.
Process Safety Information
The purpose of this requirement is to ensure that there is an
understanding of the safety-related aspects of the equipment
and processes at the facility. Having up-to-date safety information
about the process is the foundation of an effective prevention
program. Many elements (especially the hazard review) depend
on the accuracy and thoroughness of the information this
element requires.
Safety information should include:
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MSDSs for regulated substances
Maximum intended inventory of any vessel in which a regulated substance is processed or stored above its
threshold quantity
Storage and Process Limits - the safe upper and lower temperatures and pressures, process flows (if applicable), and compositions (if applicable) for your process
Equipment Specifications for any equipment that is used to store, move, or react regulated substances in a covered process
Codes and Standards used to design and build and operate the facility, such as electrical and building codes
Process Hazards Analysis
The RMP regulations require that a Process Hazards Analysis
(PHA) be performed to address toxic, fire, and explosion
hazards resulting from specific chemicals and their possible
impacts on employees, the public, and the environment. A PHA
is a thorough, orderly, and systematic approach for identifying,
evaluating, and controlling the hazards of processes involving
highly hazardous chemicals. A PHA is required for all processes
covered by the RMP rule.
Several different methods are available to conduct a PHA,
including the following:
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What-if method
Checklist method
What-if/checklist method
Hazard and operability study (HAZOP)
Failure mode and effects analysis (FMEA) method
Fault tree analysis
An appropriate equivalent methodology
Note that the process hazard analysis methodology selected
must be appropriate to the complexity of the process, and may
involve more than one of the available methodologies.
Whichever method(s) is used, the process hazard analysis
should address the following:
> The hazards of the process
> The identification of any previous incident that had a likely potential for catastrophic consequences
> Engineering and administrative controls applicable to the hazards and their interrelationships, such as appropriate
application of detection methodologies to provide early warning of releases
> Consequences of failure of engineering and administrative controls
Fall 2013 | Environmental Quarterly 5
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Stationary source siting
Human factors
A qualitative evaluation of a range of the possible safety and health effects of failure of controls
For a particular process, the PHA must be reviewed at least
every five years or whenever a major change in the process
takes place.
Operating Procedures
Written operating procedures describe in detail what tasks
a process operator must perform, set safe process operating
parameters that must be maintained, and set safety precautions
for operations and maintenance activities. Procedures must be
updated whenever there is a major change and before start-up
of the changed process.
The basic elements of a maintenance program include:
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Written procedures - to maintain the mechanical integrity of process equipment
Training for workers in the maintenance procedures
Inspection & testing schedules for inspecting and testing equipment based on manufacturers’ recommendations
Compliance Audits
Risk management programs should be reviewed periodically
to ensure that employees and contractors are implementing it
properly. This can be accomplished through a compliance audit.
An audit reviews each of the prevention program elements to
ensure that they are up-to-date and are being implemented. It
should also identify problem areas as well as corrective actions.
At least every three years, compliance with the prevention program requirements must be certified for each covered process.
Operating procedures must address:
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Initial start-up
Normal operations
Temporary operations
Emergency shutdown
Emergency operations
Normal shutdown
Start-up following a normal or emergency shutdown or a major change
Training
All new workers must be trained in the operating procedures
developed under the previous prevention program element.
Additionally, experienced workers who need training on these
procedures should also be trained. Any time the operating
procedures are revised, everyone must be trained using the new
procedures. At least once every three years, refresher training
must be provided on the operating procedures even if they
have not changed. Note that a specific amount of training or
type of training not required.
Maintenance Program
Preventive maintenance, inspection, and testing of equipment
is critical to safe operations. The hazard review and safety
information will have identified equipment that is critical to safe
operations. This information can then be used to develop the
maintenance program.
6 Environmental Quarterly | Fall 2013
Incident Investigation
Each incident which resulted in, or could have resulted in, a
catastrophic release of a regulated substance, must be investigated. A catastrophic release is one that presents an imminent
and substantial endangerment to public health and the environment. If the incident meets the criteria for including in the
five-year accident history section of the RMP, then an incident
investigation is warranted. The purpose of this investigation is to
find out what went wrong and why, so that it can be prevented
in the future.
The following briefly summarize the steps for investigating
incidents:
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Initiate an investigation promptly
Summarize the investigation in a report
Address the report’s findings and recommendations
Review the report with staff and contractors
Retain the report
Emergency Response Program
The final element in the RMP plan is a complete emergency preparedness and response plan. If there is at least one Program 2
or Program 3 process at the facility, the RMP program requires
that an emergency response program be developed and
implemented ONLY IF facility employees (and not local public
responders) will respond to any releases involving regulated
substances.
The Emergency Response Program consists of the following
elements:
> An emergency response plan (ERP) that includes:
• Procedures for informing the public and emergency
response agencies about releases
• Documentation of proper first aid and emergency medical treatment necessary to treat human exposures
• Procedures and measures for emergency response
> Procedures for using, inspecting, testing, and maintaining the emergency response equipment
> Training for all employees in relevant procedures
> Procedures to review and update, as appropriate, the
emergency response plan to reflect changes at the facility and ensure that employees are informed of changes
General Duty Clause
While the RMP applies specifically to facilities that use regulated
substances in excess of EPA thresholds, the RMP rule applies to
other emission sources via the “general duty” clause. This provision states that facilities have a “general duty” to identify hazards
that may result from accidental releases, to design and maintain a
safe facility, and to minimize the consequences of releases when
they do occur. This means that virtually any site may have risk
management obligations under the RMP as a result of potential
hazards associated with processes and materials.
Renewal Requirements
a letter from EPA with renewal instructions including the use of
EPA’s RMP*eSubmit website, a secure process that simplifies
the reporting process and improves data quality and security.
Employee refresher training, compliance audits, and updating
safety information, hazard review (or process hazards analysis),
operating procedures, and offsite consequence analysis should
also occur around the five year renewal data or sooner if
needed to address process changes.
Enforcement Momentum
EPA is ramping up RMP enforcement efforts. Its Office of Solid
Waste and Emergency Response (OSWER) made RMP inspections a high priority for fiscal year 2013. OSWER tasked regional
offices with conducting RMP inspections of at least four percent
of all regulated facilities, with 30 percent of those inspections
taking place at high-risk facilities. In addition, EPA is building a
more rigorous RMP inspection program in response to a March
2013 Office of Inspector General report that concluded that
EPA’s RMP inspectors and their supervisors were inadequately
trained and that the agency had limited mechanisms in place to
ensure that quality inspections were performed. Finally, political
pressure (led by Senator Barbara Boxer-CA) for increased oversight of chemicals in general is increasing in the aftermath of the
West, Texas fertilizer plant explosion on April 17, 2013.
Given EPA’s increased focus on RMP enforcement and its intention to seek larger penalties for violations, owners of RMPregulated facilities should carefully evaluate their RMP program
compliance and preparedness for EPA inspections. v
Facilities that already have an RMP must update their plans
every five years or as needed. Typically, the facility will receive
Fall 2013 | Environmental Quarterly 7
Federal Court Vacates GHG
Permitting Deferral for
Biogenic Sources
By russell bailey, Principal Consultant —Roanoke, VA
On July 12, 2013, the US Court of Appeals for the
District of Columbia (DC Circuit) vacated the 2011 EPA
temporary deferral that exempted biogenic greenhouse
gas (GHG) sources from requirements to obtain a
permit for those GHG emissions under the Clean Air
Act (CAA). The DC Circuit ruled that EPA did not
have authority under the act to treat biogenic GHG
emissions differently than other pollutant emissions
for Prevention of Significant Deterioration (PSD) and
Title V permitting. The EPA deferral had the two-part
effect of a) delaying Title V permitting requirements
for biogenic GHG emissions, and b) exempting sources
from PSD permitting requirements for biogenic GHG
emissions, until July 21, 2014.
Background
The path to this ruling is long and convoluted. EPA
subjected stationary sources to regulation for GHG via
an endangerment finding in 2009 which grouped six
gases under the definition of GHG: carbon dioxide
(CO2), methane (CH4), nitrous oxide (N2O),
hydrofluorocarbons (HFCs), perfluorocarbons (PFCs),
and sulfur hexafluoride (SF6).1 After EPA’s decision to
regulate these new gases under the CAA, EPA issued
the Tailoring Rule which limited the types of sources
and projects that the CAA would regulate based on
GHG emissions.2
Shortly after issuance of the Tailoring Rule, EPA issued
a Call for Information (CFI) regarding biogenic sources
and bioenergy ( July 15, 2010), which was followed
shortly by a petition for reconsideration from the
National Alliance of Forest Owners (NAFO) specifically
related to CO2 emissions from biomass combustion.
EPA granted the petition and proposed to defer
applicability of the CAA to biogenic CO2 emissions for
three years to allow further consideration of the issues
8 Environmental Quarterly | Fall 2013
surrounding biogenic CO2.3 EPA then issued a final
biogenic deferral.4
Between the proposed and final deferral rules, the
Center for Biological Diversity (CBD) and other groups
filed a challenge to EPA’s granting of the NAFO petition
for reconsideration. That CBD petition led to the
July 2013 ruling vacating the biogenic deferral rules.
The Deferral Rule
The deferral rule is simple and quite short, impacting
only one paragraph in each of the state and federal
sections for the PSD and Title V programs (40 CFR 51,
52, 70, 71). Looking at 40 CFR 52 for example,
For purposes of this paragraph, prior to July 21, 2014,
the mass of the greenhouse gas carbon dioxide shall not
include carbon dioxide emissions resulting from the combustion or decomposition of nonfossilized and biodegradable organic material originating from plants, animals,
or micro-organisms including products, by-products,
residues and waste from agriculture, forestry and related
industries as well as the nonfossilized and biodegradable
organic fractions of industrial and municipal wastes,
including gases and liquids recovered from the decomposition of non-fossilized and biodegradable organic
material).
For the three year period of deferral, biogenic emissions
did not count for CAA purposes. The practical impact
of this deferral is disputed, with varying claims in the
court case regarding actual facilities where the deferral
See http://epa.gov/climatechange/endangerment/
75 FR 31514, June 3, 2010.
3
76 FR 15246, March 21, 2011.
4
76 FR 43490, July 20, 2011.
1
2
rule resulted in different requirements. The potential impact
is clear. Consider two examples.
June 28, 2011. The court ruling agreed with key adversarial
comments in that document.
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New 50 MW biomass power plant. Traditional pollutant emissions are all less than 250 tpy, the site has a 250 tpy PSD major source threshold, and PSD would not be triggered but for potentially GHG. Biogenic GHG emissions would be approximately 500,000 tpy, which is well beyond the 100,000 tpy GHG trigger level for a new facility. With the deferral, the project does not trigger PSD for any pollutant. Without the deferral, the project would trigger PSD for GHG as well as CO, NOX, PM/PM10 / PM2.5 at minimum.
The 2-1 ruling rejected the legal doctrines upon which EPA
issued the deferral rule.
1.
De minimis
2.One-step-at-a-time
3. Administrative necessity
4. Absurd results
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Existing pulp mill undergoing an expansion project to increase liquor firing rate on the recovery boiler. With the deferral, any CO2 emissions from liquor firing are excluded, while without they must be counted towards the 75,000 tpy GHG trigger level for an existing facility.
Similar examples could be developed across a range of industries,
from landfills with landfill gas emissions, to wood products
industries, to bio-energy industries.
The Court Decision
Despite the brevity of the actual rule, there were many challenges
to and comments on the rule, as evident by the nearly 200 page
Summary of Public Comments and Responses document issued
The latter three doctrines were also used for the Tailoring Rule.
The Tailoring Rule was upheld, but without considering these
doctrines on their merits. Here, the court did consider each on
the merits. EPA’s one-step-at-a-time doctrine was vacated based
on EPA’s inability to explain in the rulemaking how the deferral
rule was a step on the road to full compliance with the statutory
mandate. The administrative necessity doctrine was rejected
since EPA rejected a “middle ground option” arbitrarily and
capriciously. The absurd result doctrine was rejected for relying
upon the Tailoring Rule absurd results rationale, since the Tailoring
Rule and deferral rule have different objectives.
The Path Ahead
EPA and intervenors have several options, including a request
for rehearing or en banc rehearing, as well as a request for a
remand. As of publication, the court has yet to issue the mandate
and thus the ruling is not yet in effect. The original deadline to
Fall 2013 | Environmental Quarterly 9
file for rehearing or rehearing en banc was August 26, 2013, but
via order on that day the court has extended the deadline until 30
days after the Supreme Court decides whether to hear a pending
challenge to EPA’s decision to regulate CO2 (UARG v. EPA, 12-1146).
In the same August 26 order, the court denied environmental
petitions request to issue the mandate at that time. The Supreme
Court is expected to issue a decision on whether or not it will
hear the CO2 challenge by approximately October 7, 2013,
which would translate to an early November deadline for the
biomass case filing.
Assuming the ruling stands, facilities that used the exemption are
likely to be required to obtain retroactive PSD permits. In an
analogous fashion, electric utility units that did not trigger CAA
§112(g) due to the Clean Air Mercury Rule (CAMR) were required to obtain 112(g) permits after CAMR was vacated by the
courts. Similarly, facilities that used the deferral to determine that
they were not subject to Title V permitting requirements will
likely need to revisit their emission calculations and determine
if a Title V permit is required. Lastly, going forward, all facilities
will need to assess the total GHG impact from future projects,
including biogenic VOC. v
Trinity’s Rocky Mountain
Team is Fast Out of the Gate
and processing, building materials, manufacturing, non-ferrous
metal mining and refining, and energy generation. He has BS
and MS degrees in Chemical Engineering and a BS in Biology.
In addition to George, the Denver team includes:
L to R: George, Ashley, Kim, Roshini, Dhesikan, and Hari Krishna.
Trinity Consultants recently opened a new office in Denver,
serving Colorado and Wyoming. The office has enjoyed
early success serving the needs of the booming oil and gas
industry as well as companies from the manufacturing, utilities,
aggregates, mining, and food and beverage sectors. Leading
the office is George Iwaszek, a semiconductor industry veteran
who relocated from Trinity’s Albuquerque office. George has
extensive experience in air dispersion modeling, emissions
quantification and inventories, regulatory applicability analysis,
and air permitting, and has assisted companies in numerous
industries including petroleum refining, natural gas extraction
10 Environmental Quarterly | Fall 2013
> Kim Ayotte – a Trinity veteran with extensive experience in Colorado and Wyoming permitting for air and water quality
> Ashley Jones – an air dispersion modeling guru and expert project manager for permitting in aggregates, utilities, and surface coating
> Roshini Shankaran – an expert in permitting oil and gas facilities in the Rocky Mountain region, who excels in PSD permitting, BACT analysis and air dispersion modeling
> Hari Krishna Bharadwaj – a recent college graduate with a BS and MS in Chemical Engineering who has experience in preparing NSR permit applications and holds a Method 9 certification
> Dhesikan Venkatesan, EIT – a Ph.D. candidate in Environmental Engineering with extensive experience in air permitting for oil and gas facilities, including off-shore
For assistance in the Rocky Mountain region, contact George at
[email protected] or call (720) 638-7647. v
Joining with Church & Trought, Inc.,
Trinity Expands into Canada
A Trinity Consultants Company
A recent merger with Toronto-based Church & Trought, Inc.
(CTI), marks the establishment of Trinity Consultants’ first office
in Canada. Founded in 1990 by John Trought and Alan Church
(retired), CTI is one of the leading air quality specialty firms in
Ontario. CTI serves clients across Canada and internationally
in a broad range of industries including adhesives, automotive,
cement, chemicals, electronics, food processing, forest products,
manufacturing, mining, petrochemical, real estate, secondary
lead and aluminum smelting, and waste processing. Co-founder
John Trought, as well as principals Lou Locatelli and Gary
Markotich, and their team, will continue to serve clients under
the Trinity banner.
Trinity has been exploring options
for entering the Canadian market for
several years. According to President/
CEO Jay Hofmann, “Our merger with
Church & Trought enables us to better
serve clients in Canada with a local
team who has intimate knowledge of
Canada’s regulatory framework. Trinity
brings to the partnership the resources
Toronto Office Manager,
to fuel growth in Canada, leveraging
Lou Locatelli
the expertise of our new Toronto
team.” The Trinity Toronto office will be a part of the North/
West region under the direction of Managing Director, John
Iwanski. For more information, contact John at (630) 495-1470
or [email protected]. v
Dispersion Modeling Notes
As documented on EPA’s Support Center for Regulatory
Atmospheric Modeling (SCRAM) website, EPA has been
actively working around AERMOD, including its postprocessors, database, and guidance:
3.
1.
4. The LowWind Beta options included in AERMOD V12345 have not yet been peer-viewed
An updated version of LEADPOST has been released, fixing a bug with outputting monthly contributions to maximum 3-month concentrations when total source group not directly input into program
2. The NO2/NOX In-Stack-Ratio (ISR) database has been updated based on the database submissions from the States of Oklahoma and Alaska
The BETA u-star adjustment option in AERMET V12345 has not been approved as an alternative model for regulatory application, although it is based on a
peer-reviewed study
Trinity’s modelers and BREEZE software team carefully track
regulatory modeling developments. For more information
on any of these issues, please contact Qiguo Jing, Ph.D, at
[email protected]. v
Fall 2013 | Environmental Quarterly 11
Developing a Boiler NESHAP
Compliance Strategy
By jose orsini, CEA, Managing Consultant — Dallas, TX • aimee andrews, Managing Consultant — Raleigh, NC
2.
The deadlines for the National Emission Standards for
Hazardous Air Pollutants (NESHAP) for industrial, commercial, and institutional boilers and process heaters
at major sources (40 CFR 63, Subpart DDDDD) and
boilers at area sources (40 CFR 63, Subpart JJJJJJ) loom
ahead. Affected units at area sources of hazardous air
pollutants (HAPs) must be in compliance by March
21, 2014 and units at major sources of HAPs must
be in compliance by January 31, 2016. Facilities
with sources affected by these rules should develop
compliance strategies and plans to achieve compliance
prior to the rule compliance deadlines.
If a facility has units that are subject to the boiler
NESHAP and has not started developing a strategy
and plan for compliance with this regulation, the
following steps may be helpful for developing a strategic
plan for compliance with the rule requirements.
1. Review and digest the regulations. Find
resources that help explain the rule requirements
such as the Table 1 summary of the rule requirements.
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Environmental Quarterly | Fall 2013
Consider external resources needed to support the compliance process. If additional equipment is needed, contact control equipment or monitoring
equipment vendors. Does the facility need consulting assistance to help evaluate rule requirements
or outside assistance for the energy assessment? (for more details, see Developing an Energy
Management Strategy) Can you utilize resources from government entities (e.g. Department of Energy)? Does the facility need to hire a stack
testing company?
3. Assess the applicability and coverage of the
regulations. Confirm the source classification for
the facility (major source or area source of HAPs). Inventory the boilers that are onsite and determine their construction dates, fuels, control devices, and
use profiles (limited, seasonal, or year-round). Document the specific rule provisions applicable to each unit.
4.
Assess the feasibility of complying without capital expenditures or changes. For units with emission limits, compile existing data, including fuel analyses and past stack test data. Evaluate available compliance options, including any alternative monitoring options. Assess the feasibility of the fuel sampling option and arrange to conduct test fuel sampling to see if your fuel conforms to the standards. Assess the feasibility of complying through
a performance test and arrange any engineering studies, as needed, to assess whether fuels can comply with the fuel analysis option and/or if the unit can comply with the emission limits.
5.
If changes are needed at the facility, begin a
strategic assessment. Identify the options available for compliance with each emission limitation, including
changes to control equipment, monitoring options, boiler shutdown or replacement, fuel switching, and other alternatives. A different compliance method may be determined for each pollutant (i.e. stack testing for pollutant A, fuel analysis for pollutant B, CEMS for pollutant C). Conduct an economic analysis and a risk analysis for each option. Based on the analyses, select a compliance option, including control and monitoring options, for each pollutant.
6. Develop a detailed action plan through the compliance date. Ensure that all required steps to compliance are included and can be completed prior to the compliance date. This should include:
> Initial notification
> Equipment procurement, construction, and operating
schedules for monitoring equipment and/or control equipment
> Air permitting for any changes (i.e. fuel switching, control equipment, etc.)
> Execute verification pre-testing as needed
> Develop monitoring plans (if required)
>
>
>
7.
Schedule performance test and submit performance test notification
Conduct initial tune-up and energy assessments
(if required)
Once performance test and other initial compliance
activities are completed, submit notification of
compliance status
Create systems to manage ongoing compliance
obligations. Add tasks to the existing compliance
management system or environmental management system to include all continuous compliance requirements. This includes planning and scheduling future fuel sampling and performance tests, developing monitoring equipment
plans and scheduling maintenance activities, managing and
documenting startup and shutdown, developing program to
maintain compliance with malfunction obligations, scheduling
future tune-ups, ensuring control device maintenance activities are planned and documented, and preparing
annual compliance reports.v
Table 1. Important Boiler NESHAP Compliance Dates for Existing Units
Activity
Due Date for EXISTING Units at:
Area Sources
Major Sources
Initial Notification
January 20, 2014
May 31, 2013
Compliance Date (includes monitoring,
equipment, installation, energy assessment and
initial tune-ups, if required)
March 21, 2014
January 31, 2016
Notification of Intent to Conduct
Performance Test
60 days prior to stack tests
60 days prior to stack tests
Notification of Performance
Evaluation/ Develop Site-Specific Test Plan
60 days prior to CMS evaluation
60 days prior to CMS evaluation
CMS Performance Evaluation Results
For COMS, submit results at least 15 days
prior to performance test
For other CMS, submit results with initial
performance test results
60 days after completion of CEMS
performance evaluation
Notification of Compliance Status
60 days after performance tests -ORJuly 19, 2014 (if only subject to tune-up and
energy assessment requirements)
60 days after performance tests and/or
other initial compliance demonstrations
Initial Compliance Demonstration (including
performance tests, fuel analyses, and CMS
performance evaluation, if applicable)
September 17, 2014
July 29, 2016
Fall 2013 | Environmental Quarterly 13
Developing a Boiler NESHAP
Energy Assessment Strategy
By jose orsini, CEA, Managing Consultant — Dallas, TX • aimee andrews, Managing Consultant — Raleigh, NC
Facilities with existing affected units subject to the
area or major source Boiler NESHAP must conduct
an energy assessment as part of the compliance
requirements. The following are appropriate
considerations to meet the energy assessment
requirements.
Annual Heat Input
Capacity of Affected
Boilers (TBtu/year)
< 0.3
8
0.3 - 1.0
24
What units require an energy assessment?
Develop a list of the boilers and process heaters at
your facility that require an energy assessment. Energy
assessments are required for:
≥ 1.0
24
+ 8 hours for each
additional 1.0 TBtu/
yr (not to exceed 160
hours)
>
>
Area Sources – existing coal, biomass or oil
boilers with ratings ≥ 10 MMBTU/hr
Major Sources – all existing boilers and
process heaters
Do you have a prior energy assessment or Energy
Management System?
If you completed an energy assessment (EA) meeting
the rule requirements on or after January 1, 2008
you may use that assessment to comply with the EA
requirement. Also, if you have an Energy Management
System that is compatible with ISO 50001 that includes
the affected units, an EA is not required.
What is the required onsite duration for the
facility’s energy assessment?
In order to determine the maximum onsite technical
labor hours for the EA, you first must determine the
annual heat input capacity for all affected units. Document each affected boiler and process heater and the
maximum heat input capacity for each unit. Add the
maximum hourly heat input capacity for all affected
units and multiply by 8,760 hours per year to determine
the total annual heat input capacity. The regulation
14
Environmental Quarterly | Fall 2013
Maximum On-site
Technical Labor Hours
provides the maximum onsite duration as follows:
What is the scope of the energy assessment for
your facility?
Based on the annual heat input capacity for all
affected units, you can also determine which energy
use systems should be reviewed as part of the onsite
EA. Make a list of the energy use systems using energy
(steam, hot water or electricity) associated with the
affected boilers and process heaters. The percentage
of energy used by those systems should also be
determined.
An energy use system uses energy (steam, hot water or
electricity) provided by an affected boiler or process
heater. These systems may include process heating, compressed air, machine drive (motors, pumps,
fans), process cooling, facility heating/ventilation/air
conditioning, hot water, building envelope, lighting, or
other systems using the energy from the affected units.
Energy use systems may be segmented by production
area or energy use area, such as product X manufacturing area, product Y drying area, building Z, etc.
Only energy use systems that utilize a portion of the
energy produced from the affected units equal to or
greater than the percentage shown in the table below
must be evaluated.
Annual Heat Input
Capacity of Affected
Boilers (TBtu/year)
Evaluate boiler system(s)
and energy use systems
accounting for X% of affected
boiler(s) energy production
< 0.3
50%
0.3 - 1.0
33%
≥ 1.0
20%
Who is qualified to conduct the energy assessment?
The regulation requires that a “Qualified Energy Assessor”
conduct the energy assessment. The qualifications ensure that
the assessor has demonstrated capabilities to evaluate energy
savings opportunities for steam generation and major energy
using systems, and is familiar with boiler system operations
(including combustion management, thermal energy recovery,
insulation, steam trap and steam leak management, condensate
recovery, and steam end-use management). The assessor also
must have capabilities and knowledge that includes familiarity
with operating and maintenance practices for process heating
systems, steam system improvement opportunities, process
heating system opportunities, cogeneration systems, and
industry-specific steam end use systems.
The Qualified Energy Assessor for your facility may be someone
at your facility, a team of staff at your facility, a team including
onsite and outside staff, or an outside consultant.
What is the purpose of your energy assessment?
The assessment team will need direction on how
thorough of an assessment is desired at your
facility. Does the organization want an assessment
that meets the requirements of the regulation
and nothing more? Or, is a more thorough
review desired to identify additional energy
savings measures beyond what is required in the
regulation?
calculate efficiency credits based on implementation of energy
conservation measures identified in the energy assessment. The
energy assessment will include the establishment of a baseline
or benchmark for future comparison with the energy savings
gained from implementing the energy conservation measures
selected by the facility. If your facility might benefit from
efficiency credits, advance planning and coordination will be
necessary to ensure compliance prior to the deadline.
What is the outcome of the energy assessment?
At the end of the assessment process, a report will be prepared
identifying energy conservation measures and opportunities,
and establishing costs and simple payback on investments,
compared to potential energy savings. Under the Boiler
NESHAP, facilities are encouraged, but not required, to use
the results of the EA to increase energy-efficiency and costefficiency of the boiler and process heater systems.
What to do next?
The countdown has begun! Working through these considerations will help you to prepare a plan to meet the energy assessment deadlines, and procure any external assistance if required.
Trinity Consultants has Qualified Energy Assessors and Certified
Energy Auditors (CEA) are available to assist you. For more
information on how Trinity can assist with the energy assessment
process, please contact Jose Orsini at [email protected]
or Aimee Andrews at [email protected], or call
your local Trinity office at 800-229-6655. v
Do you want to utilize efficiency credits?
Under the major source boiler rules, there is an
option for existing units at major sources to utilize
efficiency credits for compliance demonstration
in lieu of installing controls. If your facility has
preliminary data indicating that a unit is very close
to an emission limit and would like an option
for compliance other than installing controls,
efficiency credits may be worth investigating. The
major source regulation provides a method to
Fall 2013 | Environmental Quarterly 15
ISO 50001, Energy
Management System –
The Other Boiler MACT
Option
By JERRY SKAGGS, PE, CP EnMS – Industrial Sector, Managing Consultant — Pittsburgh, PA
Boiler MACT Compliance Options
The Boiler MACT regulations for applicable Major
and Area Sources (40 CFR 63, 6J and 5D) were most
recently revised in January and February 2013. The
final energy related provisions include a compliance
requirement to either conduct an energy assessment
or implement a system conforming to the requirements of an ISO 50001 Energy Management System
(EnMS). While the advantage of an energy assessment
is a single, quick option to meet the requirements of
the regulation, it does not drive actions to continually
reduce energy consumption, increase energy efficiencies, or improve operational processes. This is because
the Boiler MACT energy assessment provision only
requires identification of energy conservation measures, and encourages facilities, but does not required
them to implement the measures. Conversely, the
implementation of an EnMS provides a structured,
organized, and focused approach to continually reducing energy use and consumption, identifying opportunities for improvement, acting on those opportunities,
and managing all aspects of energy within the bounds
of its system.
Why ISO 50001?
ISO 50001:2011 – Energy Management System or
EnMS, is based on the management system model of
continual improvement using the Plan, Do, Check, Act
cycle, which is also used for other well-known standards such as ISO 9001, ISO 14001 or OHSAS 18001.
This makes it easier for organizations to integrate energy management into their overall efforts to improve
16
Environmental Quarterly | Fall 2013
quality, environmental, or health and safety management. An EnMS provides a framework of requirements
for organizations to:
> Develop a policy for more efficient use of energy
> Fix targets and objectives to meet the policy
> Use data to better understand and make decisions about energy use
> Measure the results
> Assess how well the system works
(See Figure 1 - Energy Audit Process Flow Diagram)
> Continually improve energy management. 1
Several early adopters are reporting significant benefits and energy cost savings from the implementation
and operation of an EnMS. Proponents estimate that
the standard, which supports management strategies to increase energy efficiency, reduce costs and
improve energy performance, can influence up to
60% of the world’s energy use. Bentley, Coca-Cola,
Delta Electronics in China, Schneider Electric of France,
the Dahanu Thermal Power Station in India, and LCD
TV maker AU Optronics Corp of Taiwan, Province
of China, are just some of the organizations that have
reported benefits of using an EnMS.
The global energy management challenge cuts across borders and requires concerted efforts from all sectors. The
standards are developed with stakeholders from industry,
government, and consumers. They strive for consensus on
practical technological solutions that can be implemented
as broadly as possible. Information, communication, and
education are essential instruments for promoting a
1
http://www.iso.org/iso/home/standards/management-standards/iso50001.htm
culture of energy efficiency within a country or a company. An
EnMS consists of seven major clauses:
1. General Requirements
2. Management Responsibility
3. Energy Policy
4. Energy Planning
5. Implementation and Operation
6.Checking
7. Management Review
An EnMS can be used to manage virtually all variables affecting
energy performance that can be monitored and influenced by
the organization. ISO 50001 does not prescribe specific performance criteria with respect to energy, i.e. 10% savings. The
ISO 50001 standard for energy management systems has been
designed to be used independently, but it can be aligned or
integrated with other management systems. It is applicable to
any organization, building, or manufacturing process that wishes
to ensure its conformity to its stated energy policy and wishes to
demonstrate this to others. Such conformity can be confirmed
by means of self-evaluation and self-declaration of conformity
or by certification of the energy management system by an
external organization.
Management Standard Commonalities
The ISO 50001 standard closely mirrors other management systems standards, such as: quality (ISO 9001); environmental (ISO
14001); and health and safety (OHSAS 18001). Companies with
an existing ISO 14001, OHSAS 18001, or ISO 9001 system will
have a jump start on the implementation of an EnMS, as common elements are already in place and understood. Common
elements (with an energy focus) are:
>
>
>
A defined and documented Scope and Boundary
A policy that requires continual improvement and compliance with legal and other requirements
A method to appoint a top management representative
Fall 2013 | Environmental Quarterly 17
>
>
>
>
>
>
>
>
>
>
>
>
>
Identification of Significant Energy Uses (SEUs), much like environmental aspects and impacts
Identification of applicable legal and other requirements and a process to evaluate compliance
Development of objectives, targets, and action plans
(versus programs)
Identification of training needs, competency, training,
and awareness
Methods to internally and externally communicate related corporate objectives and methods
Identification and control of documents and records
Operational Controls
Design and Procurement processes (ISO 9001 like, with
additional requirements noted below)
Monitoring and measurement, with analysis of data for
performance and calibration
Evaluation of compliance
A system to address Nonconformance, Corrective and
Preventive Actions
Internal Audits
Management Review
ISO 50001 Unique Requirements
In addition to the common elements with other management
system standards, an EnMS introduces some new requirements
such as:
> Top management has very specific,
additional responsibilities related to the
implementation of the EnMS, including
long-term planning
> The Management Representative must have appropriate (related) skills and competence
and report not only on the performance of the EnMS,
but also on energy performance and must determine the criteria and methods to ensure the effectiveness of
the EnMS
> The policy must include additional commitments to:
• Improvements in energy performance
• Ensure availability of information and resources to achieve
objectives and targets
• Support the purchase of energy-efficient products and services
• Design for energy performance
• Regularly review and update as necessary
18
Environmental Quarterly | Fall 2013
> Conduct an Energy Review, including:
• Analyze current energy sources and past and present energy use and consumption
• Identify areas of SEU, such as facilities, equipment,
systems, processes or personnel
• Identify relevant energy variables affecting SEUs
• Determine current energy performance related to SEUs
• Estimate future energy use and consumption
• Identify, prioritize, and record opportunities for improving energy performance
> Establish an Energy Baseline and adjust as necessary, using information from the energy review
> Identify Energy Performance Indicators appropriate for monitoring and measuring and compare to the Energy
Baseline, as appropriate
> Prepare Energy Action Plans that are documented and update at defined intervals, with a statement of the method by which an improvement in energy performance is verified and the method for verifying results
> Identify Operational Controls and ensure performance of those operations and maintenance activities which are related to its SEUs, and operating and maintaining facilities, processes, systems and equipment, in accordance with
operational criteria
Figure 1. —Energy Audit Process flFlow Diagram
Data
Measurement
Plan
Energy Audit
Planning
Source: Draft ISO / DIS 50002, Energy Audits, August 2, 2013
Data
Collection
Field
Work
Analysis
Report
Closing
Meeting
Start-Up
Meeting
>
>
>
Consider and record energy performance improvement opportunities and operational control in design processes that can affect SEU energy performance and incorporate into the specification, design, and procurement activities of the relevant project(s)
Inform suppliers that procurement decisions consider energy performance; implement criteria for assessing new
equipment energy use, consumption and efficiency over the planned or expected operating lifetime; and develop energy purchasing specifications
Address actual and potential nonconformities by making corrections (in addition to corrective and preventive actions)
As noted, companies with an existing management system will
find the additional requirements of an EnMS less daunting as
they follow a rational methodology to determine:
> When, where, how and who is involved in energy
consumption
> Opportunities to improve energy efficiency or performance
> Predictions of future energy consumption
> Control of the planning (design) and purchase of energy consuming equipment
> Definition and demonstration of how energy success is
measured
> Correction of potential nonconformance issues, without a paper trail of actions, as appropriate
Facilities without an existing management system should
approach the EnMS as an opportunity to reduce overhead costs
and improve energy performance, potentially improving
profitability. Success requires a diligent and honest evaluation
of how each aspect applies to the facility.
As the “Other Option” to compliance with the Boiler MACT
Energy Assessment requirement, an EnMS offers a continuous
improvement model that creates opportunities for incremental
improvement over time and breakthrough improvements.
Trinity Consultants can assist with either approach, performing
an energy assessment for Boiler MACT compliance or implementing an EnMS including implementation, compliance review,
internal auditing, and training. For more information, contact
Jerry Skaggs at (412) 522-7654 or [email protected]. v
Fall 2013 | Environmental Quarterly 19
Trinity’s Suejung Shin
Helps Ensure Clean Drinking Water in Fiji
construction scope and key assessments
for future work including connecting five
new houses (previously without access to
water) to the current water distribution
system; repairing thirteen community
water taps; constructing four new biosand
filters to provide safe drinking water;
and completing various site assessments
of water sources and possible locations
for new pipelines to be built in future
implementation trips.
Villagers from Buca at a construction site in August 2013
Suejung Shin, a Consultant in Trinity’s Oakland, CA office,
recently spent two and a half weeks volunteering with Engineers
Without Borders, San Francisco Professionals Chapter (EWBSFP)’s Fiji Project. With a team of about 15 environmental
professionals from firms across the San Francisco Bay Area,
the EWB-SFP Fiji Project serves the villages of Buca, Loa, and
Vunikura in the Buca Bay region of
the Fiji Islands, with the end goal of
providing a safe and reliable source
of drinking water to the three villages.
Since 2008, various water supply and
water quality projects have been
undertaken such as replacement of the
in-village distribution system, upsizing
pipe, and construction of biosand filters.
This year, five travelers completed the
According to Suejung, “I was happy to
contribute to such a hands-on project
and to be able to interact with the Fijians,
whose hard work and joyful attitudes made
the construction project easy.” Suejung
joined Trinity in 2012 after completing a
Master of Engineering at the Massachusetts
Institute of Technology in Civil and
Environmental Engineering and Bachelor of
Science at Stanford University in Environmental Engineering. At
Trinity, Suejung assists clients with air permitting and compliance
along with the rest of the Oakland team. She welcomes questions
about air issues or Fiji at [email protected]. v
EWB volunteers Suejung Shin (center) and Joy Wei (left)
with some of the villagers of Buca
Children of the village Vunikura by a biosand
filter constructed in partnership with EWB
volunteers.
API Releases SANGEA 4.1 for
Standardized GHG Emissions
Reporting
By JOHN FILLO, Principal Consultant — Pittsburgh, PA
Since the early 2000’s, the American Petroleum Institute
(API) has supported the SANGEATM software tool for
petroleum, natural gas and petrochemical companies
to quantify greenhouse gas (GHG) emissions and to
standardize emissions reporting. Regulatory changes,
including mandatory reporting requirements for GHG
emissions, prompted API to sponsor a major overhaul
of the software including current calculation methodologies. As announced in the Summer 2012 issue of
Environmental Quarterly, API chose Trinity Consultants
to develop its SANGEA-4 software. The free Beta
version 4.0 was released in 2012 and the final version
SANGEA 4.1 is now available.
21
Reporting Rule (MRR) for GHG emissions. The new
software includes emission factors for criteria pollutants that enable users to quantify emissions for both
GHG and criteria pollutants in one tool. SANGEA can
also be used to track energy consumption and normalize emissions on a production basis (e.g., ton GHG/bbl
of product). The information from SANGEA may be
used for API GHG benchmarking studies and to comply with Federal GHG emission mandatory reporting
rules for the petroleum and aligned industries.
SANGEA-4 is a desktop database program with a userfriendly interface that can be used to manage various
types of emission sources throughout a large entity for
corporate performance and/or regulatory reporting
requirements. In order to build a solution that would
promote long-term software usability and easy maintenance, the new product replaces a spreadsheetbased application with a Web-based product that
uses a Microsoft .NET framework and Access database
files for source information storage.
The reporting entity hierarchy applied by existing SANGEA
users is retained in SANGEA 4.1, including the reporting
entity, location group, location, and source set up
process, with extended steps to incorporate more
source specific requirements under multiple protocols.
Sources are configured for a specific location. Multiple
locations/ location groups can be created under one
SANGEA 4.1 working file (i.e., a Microsoft Access database file), which allows companies to report emissions
by business operation groups, geographical regions,
or regulatory reporting entities. Figure 1 provides a
typical reporting entity hierarchy structure that can be
established in SANGEA 4.1.
SANGEA 4.1 provides calculation methodologies in
various modules based on API’s Compendium 2009
and corresponding subparts of U.S. EPA’s Mandatory
SANGEA 4.1 integrates two GHG reporting protocols
with numerous source types. Table 1 shows the available source “modules.” Within each module, wizards help
Environmental Quarterly | Fall 2013
Figure 1. SANGEA 4.1 Reporting Entity Hierarchy
Entity
Location
Group
Business or
Location
Segment 1
Location
EPA MRR
Reporting Facility
Facility 1
Facility 2
Sub-Basin A
Reporting
Entity
Sub-Basin B
Sub-Basin C
Business or
Location
Segment 2
Sources
& Fuels
Fuel 1
Fuel 2
Facility A
Source 1
Facility B
Source 2
Facility C
Source 3
users set up emission sources and multiple calculation methods
for the protocols. The software guides users to specify source
parameters that are needed for GHG emissions calculation and/
or reporting requirements. These source parameters are stored
in the source database for future emission inventory reports.
SANGEA 4.1 also offers a “User Defined Sources” module under
the API Compendium 2009 that allows users to define sources
that are not already established in SANGEA.
SANGEA 4.1 is available from API for organizations in the petroleum and other applicable industries. Ms. Adefemi, Senior
Statistical Analyst at API stated that, “The objective of sponsoring
SANGEA-4 is to provide a user-friendly GHG reporting tool to
the Oil & Gas industry and to encourage consistent reporting
of GHG emissions. In 2014, API will continue its annual survey
on GHG emissions and criteria pollutants. SANGEA-4 will
assist the industry in recording and benchmarking consistent
and comparable data, and also in analyzing the industry’s
environmental footprint.” Many large oil and gas companies have adopted SANGEA for corporate GHG reporting
requirements. To purchase a copy of this software, visit
api-sangea.org.
SANGEA-4 development is led by T3, a division of Trinity
Consultants that implements EH&S information management
solutions (EMIS), with commercial software development
expertise from the BREEZE software group. T3 has over
15 years experience developing custom software and implementing EMIS solutions in myriad industries. For
more information, visit tthree.com or contact John Fillo
at [email protected]. v
Table 1. Summary of Source Modules in SANGEA 4.1
SANGEA Source
Modules
API Compendium
2009
U.S. EPA MRR
Subpart
C
P
W
Y
Acid Gas Removal (AGR)
√
Combustion Control
√
There are many user-friendly editing functions in SANGEA 4.1
that allow users to easily manage sources, such as:
Dehydrator
√
√
Equipment Leaks
√
√
√
Flare
√
√
√
>
>
>
>
>
Hydrogen Plant
√
Indirect Emissions
√
Gas composition property and API gravity calculations.
Source import and export tools for Stationary
Combustion - allows users to edit many combustion sources in Excel spreadsheets then import into SANGEA 4.1. Source parameters can also be exported to spreadsheets for use in other applications such as EPA’s MRR reporting tools.
For each new reporting year, users can copy from an existing report file - this function copies all source parameters from the existing file and removes all activity data that should be updated for the new reporting year.
Default emission factors are automatically selected for specific fuels or sources and can be checked for reference at the “Tools” menu.
“Subpart W Reporting Requirement by Industry Segment” is listed for easier reference for applicable emission sources.
√
√
Liquid Loading
√
Miscellaneous
√
√
Mobile and Transportation
√
Oil and Gas Venting
√
Refinery Process Units
√
Stationary Combustion
√
Storage Tank
√
√
Sulfur Recovery Units (SRU)
√
√
User Defined Sources
*
√
√
√
√
√
* Allows users to create source types not covered under the protocols.
Fall 2013 | Environmental Quarterly 22
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Compliance Management for Fugitive
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GHG Permitting and Compliance for the
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Industry-Specific: Chemicals
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trinityconsultants.com • (800) 229-6655