General Electric Company Comments 

Submitted February 11, 2004 

On 

Proposed Amendments to 

Regulations 310 CMR 7.00 

For the Control of Air Pollution 
Contents 

General Electric Company' Comments on the Proposed 

Amendments to 310 CMR 7.00 

Introduction and Background 1 

Proposed 310 CMR 7.03(23) Temporary Boilers 2 

Proposed 310 CMR 7.06(l)(c) Visible Emission Limits 5 

Proposed 310 CMR 7.18(8)(d-g) Solvent Metal Degreasing 17 

Proposed 310 CMR 7.54 U Large Combustion Emission Units 23 

Attachments 
Introduction and Background 

GE Aircraft Engines (GEAE) is located on 225 acres, including 36 major buildings, in Lynn, 

MA. Construction on the site began in 1892, making it one of GE's oldest manufacturing 

facilities. Today, the principal activities on site are the design, development, manufacture 

and assembly of commercial and military aircraft engines and naval propulsion equipment. 

GE provides work for over 3,900 permanent employees and approximately 300 

subcontractors at Lynn. It is among the largest manufacturing facilities in Massachusetts and 

employers on the North Shore. The facility houses its own power plant that generates 

electricity for plant usage and for limited external sale. GE's presence directly and indirectly 

supports numerous local businesses and vendors. 

The Lynn site is a major source of emissions of nitrogen oxides (NOx), sulfur dioxide (SO2), 

carbon monoxide (CO), particulate matter (PM), volatile organic compounds (VOC), and 

hazardous air pollutants (HAP). The equipment and processes resulting in these emissions 

include industrial boilers; engine test cells; turbines; air heaters; aerospace parts cleaning; 

solvent degreasing; miscellaneous metal parts surface coating; site remediation; and 

numerous insignificant sources required to support manufacturing, research and development 

and design, as well as facilities and maintenance activities on-site. The power plant and test 

cells by far account for the majority of site emissions. These units are subject to various fuel 

utilization regulations, emissions control plans, and specific permits (Plan Approvals). 

Because of the diversity of activities at the GE Lynn facility, the site's operations are affected 

by many regulatory developments. Of the proposed regulations, GE has chosen to comment 

on provisions of the proposed rules covering temporary boilers (Proposed 310 CMR 

7.03(23)), visible emissions limits (Proposed 310 CMR 7.06(l)(c)), solvent metal degreasing 

(Proposed 310 CMR 7.18(8)(d-g)) and large combustion units (Proposed 310 CMR 7.54 U). 

We appreciate the opportunity to submit these comments to the Massachusetts Department of 

Environmental Protection (MA DEP). 

1 
Proposed 310 CMR 7.03(23) Temporary Boilers 

Introduction 

MA DEP's current regulations at 310 CMR 7.03(23) provide an exemption from plan 

approval requirements for temporary boilers meeting four conditions, where such boilers 

follow the other requirements of that section. This language recognizes the operational 

realities that sometimes such boilers are needed on short notice to temporarily replace a 

boiler that has gone offline.1 The MADEP has proposed to amend 310 CMR 7.03(23) to read 

as follows: 

(23) Temporary Boilers. Construction or installation of a temporary boiler at a 

facility where a boiler is no longer available for use. .. . A temporary boiler 

constructed or installed in accordance with 310 CMR 7.03(23) with an energy input 

capacity exceeding 10 MMBtu per hour is subject to New Source Performance 

Standards contained at 40 CFR Part 60, Subpart Dc - Standards of Performance for 

Small Industrial-Commercial-Institutional Steam Generating Units. 

This regulation would be a hardship to GE because it would significantly impact the 

flexibility with which GE could manage its operations. Not only does this new requirement 

subject all temporary boilers to the referenced New Source Performance Standards (NSPS), 

but it also is contrary to the express applicability provisions of the NSPS. It should not be 

adopted in this form; rather it should be amended (as illustrated below) to include the clear 

applicability thresholds inherent in the NSPS. 

Proposed Regulations 

The MA DEP's proposed temporary boiler provisions would impose the Subpart Dc New 

Source Performance Standards on older boilers that are not "new," "modified" or 

"reconstructed," and therefore would not otherwise be subject to the NSPS. For example, a 

12 MMBtu per hour boiler constructed in 1988, but not modified or reconstructed since then 

would not be subject to Subpart Dc. However, under the proposed MADEP rules, such a 

boiler would be required to comply with Subpart Dc solely by virtue of being used as a 

temporary boiler. 

The MA DEP has not disclosed why it has proposed to subject temporary boilers to NSPS 

requirements if they are not otherwise covered by that rule. Given that temporary boilers, by 

definition, operate for only a limited period of time, there does not appear to be a significant 

environmental benefit to be gained by imposing NSPS requirements only on temporary 

boilers, but not on all other exempt sources. If the goal of this provision is to clarify that 

boilers otherwise subject to the NSPS must continue to comply even if they are used as 

1

 The four conditions are: 

1. Have a maximum heat input capacity less than or equal to the boiler it is replacing; 

2. Be installed for a period not to exceed 120 days; 

3) Use the same or lower sulfur content fuel as the boiler it is replacing; and 

4) Comply with all other applicable requirements for the boiler that it replaced. 

2 
temporary boilers, the provision must be revised (as illustrated below) to accomplish that 

objective without sweeping so broadly as to include those temporary boilers that are not 

otherwise subject to NSPS. 

The NSPS Subpart Dc only applies to boilers "for which construction, modification, or 

reconstruction is commenced after June 9,1989." See 40 CFR 60.40c(a). Thus, the NSPS 

does not apply to older boilers unless they have been "modified" or "reconstructed." The 

NSPS General Provisions define "modification" as "any physical or operational change to an 

existing facility which results in an increase in the emission rate of any pollutant...." 40 

CFR 60.14(a). The definition goes on to expressly state that the following is NOT A 

MODIFICATION: "The relocation or change in ownership of an existing facility." 

Emphasis added. See 40 CFR 60.14(e)(6). Unless an otherwise exempt boiler experiences a 

change that results in an increase in emission rate, it should not be subject to the NSPS 

simply because it is used as a temporary boiler.2 

In a recent United States Environmental Protection Agency (US EPA) applicability 

determination involving a situation analogous to the temporary placement of a boiler at a 

stationary source, US EPA confirmed that the temporary use of an exempt emission unit (in 

this case, an older combustion turbine) does not cause it to become subject to NSPS if it was 

not already subject - even if it replaces a unit that was subject to NSPS. See Attachment 1. 

In a letter dated August 1, 2002, from Jeff Kenknight, US EPA, Region X, to Jordan E. 

Jacobson, Counsel, Alyeska Pipeline Service Company, US EPA confirmed the following: 

"Question 5: Do the Alyeska turbines that were manufactured before October 3, 1977 

[the applicability date for NSPS requirements for turbines, in subpart GG] become 

subject to NSPS GG if they are treated as a pool of identical turbines and moved from 

location to location between TAPS pump stations to allow for maintenance of 

turbines? 

Response 5: Assuming the maintenance does not result in a "modification" or 

"reconstruction," as those terms are defined in 40 CFR subpart A, and, assuming that 

the turbines are not otherwise "modified" or "reconstructed," as those terms are 

defined in 40 CFR subpart A, as a result of the relocation of the turbines, relocation of 

a turbine as part of a pool of identical turbines would not make the turbine subject to 

NSPS subpart GG. See 40 CFR 60.14(e)(6)." 

"Question 6: Does a turbine that is not subject to NSPS subpart GG (because it was 

not constructed, modified or reconstructed after October 3, 1977) become subject to 

NSPS subpart GG if it rotated into a location to replace a turbine that is subject to 

NSPS subpart GG? 

Response 6: A turbine that was not constructed, modified or reconstructed after 

October 3,1977, as those terms are defined in 40 CFR subpart A, does not become 

2

 Similarly, the NSPS provides a clear definition of "reconstruction," which is not triggered in any way by the 

relocation or use of a boiler as a temporary unit. See 40 CFR 60.15. This definition is triggered only by the 

replacement of components that exceed, in the aggregate, 50% of the capital cost of a new emission unit. 

3 
subject to NSPS subpart GG simply because it is rotated into a location to replace a 

turbine that is subject to NSPS subpart GG. As discussed above, under NSPS 

subparts A and GG, the turbine is the "affected facility," as defined in 40 CFR 60.2, 

and a relocation of an affected facility is not, by itself, a modification." 

GE's Proposal 

Given this clear statement by US EPA that the use of temporary replacement emission units 

does not trigger NSPS requirements absent a separate "modification" or "reconstruction" 

event, MA DEP should revise its proposed rule amendment to account for the fact that some 

temporary boilers may not be subject to NSPS, Subpart Dc, and recognize that the mere use 

of such a boiler as a temporary replacement does not trigger NSPS requirements as follows: 

(23) Temporary Boilers. Construction or installation of a temporary boiler at a 

facility where a boiler is no longer available for use.... A temporary boiler 

construction modified, or reconstructed after June 9,1989 or installed in 

accordance with 310 CMR 7.03(23) with an energy input capacity exceeding 10 

MMBtu per hour is subject to New Source Performance Standards contained at 40 

CFR Part 60, Subpart Dc - Standards of Performance for small IndustrialCommercial-Institutional Steam Generating Units. 

However, while GE believes that the proposed revision may result in temporary boilers being 

treated more stringently than permanent boilers, that result would still be preferable to an 

installation delay that might be associated with permitting such a boiler. 

4 
Proposed 310 CMR 7.06Q)(c) Visible Emission Limits 

Introduction 

The power plant at GE's Lynn facility operates four oil-fired industrial boilers and a gas-fired 

turbine, which are described in Table 1 below. The four boilers produce steam for electrical 

generation, space heating, manufacturing support, and testing. Each of the boilers is 

equipped with a soot blowing system and a continuous emission monitoring system (CEMS) 

that measures and records NOx, SOx, CO, and opacity. 

Table 1. Boiler Installation Dates and Heat Input 

Unit Year Installed Maximum Heat Input 

Boiler #1 1943 199 MM Btu/hr 

Boiler #2 1949 199 MM Btu/hr 

Boiler #3 1962 383 MMBtu/hr 

Boiler #5 1988 (construction 

commenced 1986) 249 MM Btu/hr 

Current Regulations and Operating History 

In its most recent Title V Operating Permit application submitted in December 2003, GE 

Lynn certified compliance with all applicable requirements of currently effective regulations, 

permits, and approvals. In addition to the recently issued Final Approval under 310 CMR 

7.06(l)(c), these include the following permits and regulations that apply to the powerhouse: 

• MBR-94-COM-008 - NOx RACT Emission Control Plan Final Approval 

• MBR-97-COM-016 - Comprehensive Plan Approval 

• MBR-01 -728-009 - NOx Allowance Emission Control Plan Final Approval 

• 310 CMR 7.27 and 310 CMR 7.28 - NOx Allowance and Trading Program 

• 310 CMR 7.02 - Preconstruction Approvals 

• 310 CMR 7.22 - Sulfur Dioxide Emissions Reductions for Reducing Acid Rain 

• 310 CMR 7.05 - Sulfur Content Limits for Fuels 

Over the last several years, GE Lynn has been actively engaged in evaluating and improving 

boiler operations and controls to maintain continuous compliance with the above-referenced 

applicable requirements, which include provisions relating to NOx, CO, SO2, PM and 

opacity. Combustion Components Associates, Inc. (CCA), of Monroe, CT, a firm with 

substantial expertise in these areas, has been instrumental in improving boiler performance 

and emissions. 

During 1994-95, as part of NOx RACT compliance efforts, burner controls were either 

refined or modified on all boiler units. While those changes significantly improved NOx 

5 
emissions; they also substantially lowered excess air levels, making the combustion process 

much more susceptible to opacity spikes during abrupt load variations and other combustion 

changes. In general, combustion conditions that suppress NOx formation make opacity 

control more difficult, with much smaller changes in boiler status triggering opacity spikes. 

This problem is more pronounced at high load where excess air levels are most closely 

trimmed to maintain NOx compliance. 

More recently, GE has also participated in the efforts of the Associated Industries of 

Massachusetts to identify appropriate and practically achievable opacity standards for 310 

CMR 7.06(l)(c). In addition, GE has kept up proactive continuous improvement efforts and 

preventive maintenance programs at the powerhouse. 

In 1997, GE hired Diamond Power, the manufacturer of the soot blowers used on the boilers, 

to evaluate the existing soot blowing system and to provide recommendations to reduce 

opacity. In conformance with the recommendations developed by Diamond, an automated 

soot blower control system was installed on Boilers #1, #2 and #3, and the frequency of soot 

blowing was increased from once per (8 hour) shift to twice per shift. This automation 

process allowed Diamond to optimize the timing of soot blowing activities in the various 

sections, and hence better control opacity. As a result of these improvements, peak opacity 

levels were substantially reduced, greatly enhancing the likelihood that GE Lynn's boilers 

will able to comply with the 27% opacity limit proposed in 310 CMR 7.06(l)(c) during soot 

blowing under most "normal" operating circumstances. 

In 2000, CCA again was engaged to support overall power house compliance efforts, and 

assist in developing an approach to satisfy requirements of the new 310 CMR 7.06(l)(c) rule. 

Key activities in this contract included: (1) preparing an Opacity Plan of Good Operating 

Practices (POGOP); and (2) evaluating boiler operations in order to identify and implement 

hardware and operating practices refinements that could reduce opacity. 

More recently, in response to draft revisions to 310 CMR 7.06(l)(c), which would become 

applicable requirements in the Operating Permit expected to be issued in 2004, CCA was 

tasked to expand upon its previous work. This time, CCA performed a detailed evaluation of 

opacity for the four GE boilers and updated procedures in the POGOP. The purposes of this 

evaluation were to: (1) identify conditions during which the "normal" opacity standard of 

15% specified under 310 CMR 7.06(l)(c) could not be met; and (2) propose limits that could 

be satisfied during "special" combustion conditions assuming the boiler was properly 

maintained and operated. It should be emphasized that, as part of this process, CCA also 

made various hardware refinements and identified modifications to operating practices in 

order to improve the performance of the boilers, focusing on those units with more 

problematic issues, as will be discussed below. This approach helped to ensure proposed 

opacity limits were consistent with the performance achievable by each boiler. 

CCA's development of an Opacity POGOP for GE Lynn's boilers involved review of both 

existing operating practices and boiler operating history. CCA not only examined existing 

standard operating procedures (SOPs) used by the powerhouse, but was able to draw upon its 

more than 10 years of experience in working on GE's boilers. CCA reviewed nearly two 

years of CEMS historical opacity data for each of the boilers (2001- 2003) and examined test 

6 
data collected during the various diagnostic studies and improvement projects they had 

conducted over the years. The analysis examined the operating conditions prevailing during 

each incident of elevated opacity, and assessed the extent to which such spikes were inherent 

in the special operating condition occurring. The final POGOP expanded and refined 

existing SOP practices to include procedures for addressing key operational activities likely 

to trigger opacity incidents (e.g. burner change, startup, shutdown, etc.), and also provided 

response procedures to follow in the event of an malfunction condition. 

During the period that the Opacity POGOP was being developed, CCA also was conducting 

diagnostic evaluations and customizing costly hardware refinements to improve emissions on 

the boiler units. CCA fabricated and installed a number of new hardware components to 

improve boiler emissions, including special startup burner tips, and state-of-the-art atomizers 

and flame stabilizers, all of which were customized for GE's boilers. These improvements 

were developed based on diagnostic investigations focusing on the boilers showing the most 

problematic emission behavior. CCA was on-site on several occasions specifically to 

observe and analyze boiler emissions at cold start-up, test the effect of various system 

adjustments, and identify appropriate hardware refinements. CCA also had the opportunity 

to examine and adjust boiler operation over a variety of other operating conditions to support 

its emissions optimization efforts. A listing of the key boiler projects performed by CCA 

over the last several years is presented in Table 2 below. Additional discussion of these 

activities is provided in the Executive Summary of the CCA Opacity Study and Updated Plan 

of Good Operating Practices which was previously submitted to the MA DEP. 

Table 2. Recent GE Lynn Boiler Improvement Projects Related to Opacity 

YEAR MONTH UNIT ACTIVITY 

2003 Nov - Dec #1 Split Flame atomizers designed and fabricated. 

• Should provide improved opacity/NOx characteristics. 

• Not yet field evaluated. 

2003 December #3 Provided start up atomizers of reduced capacity for cold start- ups. 

• Should improve opacity and CO characteristics during light off/warm 

up of cold boiler. 

• Not yet field evaluated. 

2003 July #5 Optimization of burner hardware. 

• Staged firing of upper burners with respect to lower burners. 

• 30% lower capacity burners in upper burners. 

• Demonstrated improved NOx margin with opacity at maximum load. 

• Improved opacity and NOx emissions during soot blowing. 

2003 April #5 Initial optimization of new Split Flame atomizers with multi-zone flame 

stabilizers. 

• Optimization demonstrated improved opacity NOx characteristics, but 

indicated further improvements could be made with fuel staging of 

upper burners. 

7 
YEAR MONTH UNIT ACTIVITY 

2003 March #5 Cold air flow testing conducted of individual burners to establish optimum 

air register settings. 

• Used as a guide in burner optimization for improved opacity/NOx 

characteristics. 

2003 March #5 Installed new multi-zone flame stabilizers for improved opacity/NOx 

characteristics. 

2003 March #2 Provided start up atomizers of reduced capacity for cold boiler start ups. 

• Demonstrated both improved opacity and CO characteristics during 

boiler warm up. 

2002 October All Conducted formal particulate testing on Boilers #1, #2, #3 and #5. 

• As part of testing reviewed and up dated optimum burner settings. 

2002 April #5 Design new Split Flame atomizers and Multi-Zone Flame Stabilizers. 

• These new designs have demonstrated reduced NOx and opacity in 

similar installations. 

2002 March #2 Further optimized Split Flame atomizers. Introduced new retaining nut 

shape for reduced carbon build up which reduced the need for burner shut 

downs and light offs for cleaning. 

• This resulted in a reduced number of opacity excursions. 

2002 February #2 Optimized new Split Flame atomizers with new multi-zone swirlers. 

• Provided better opacity/NOx characteristics. Noted some carbon build 

up on tip. 

• Began design change on retaining nut to reduce build up. 

2001 December #2 Design new Split Flame atomizers and Multi-Zone Flame Stabilizers. 

• These new designs have demonstrated reduced NOx and opacity in 

similar installations. 

2001 February #2 Optimization of burner settings for NOx emissions and opacity. 

2000 Nov-Dec All Opacity minimization plan. 

• Initial draft. This activity has carried on through the present with 

modifications to the plan and additional information requests. 

Proposed Regulations 

The US EPA cited four issues of concern when it granted conditional State Implementation 

Plan (SIP) approval of MA DEP's proposed revisions to 310 CMR 7.06(l)(c) (See the April 

8, 2003 Federal Register notice at 68 FR 16959): 1) the need for a cap on opacity during 

start up and shut down operations; 2) inclusion of an averaging period over which opacity 

should be measured; 3) specification of the criteria by which a Plan of Good Operating 

Practices judged; and 4) addition of provisions to make the Good Operating Practices 

enforceable. By letter dated May 8, 2003, the Sierra Club submitted to EPA its opposition to 

EPA's conditional approval, restating EPA's concerns mentioned above. On June 6, 2003, 

EPA withdrew its direct final rule. See 68 FR 33875. GE today is commenting on MA 

8 
DEP's response to US EPA and the Sierra Club's concerns regarding the first two concerns 

(opacity cap and averaging period), as addressed in re-proposed 310 CMR 7.06(l)(c). 

GE regrets that there appears to be no technical support for these new limits in MA DEP's 

Background Document to the Proposed Regulation. No regulatory basis is provided for the 

27 % opacity limit using six-minute averaging, nor is an analysis given to support MA DEP's 

contention that a 27 % opacity limit during a six-minute averaging period is technically 

feasible or achievable for existing facilities that are not otherwise subject to the NSPS. There 

is no economic analysis of the cost of complying with the regulations, no data are provided 

that identify what, if any, environmental benefits may be derived from the proposed 

regulation. 

GE appreciates MA DEP's efforts to create an alternative opacity standard that is highly 

protective of the environment while still being flexible and practical for industry. GE also 

supports MA DEP's inclusion of an alternative opacity standard that provides separate limits 

for startups, shutdowns and certain other operating conditions. MA DEP clearly recognizes 

that in practice, operation of industrial boilers results in some variation in emissions, 

depending on facility-specific conditions and process equipment. However, GE believes that 

the proposed opacity regulations are far more restrictive and inflexible than necessary to 

satisfy US EPA and the Sierra Club's concerns. If adopted, the 15% opacity limit will equal 

the lowest opacity standard promulgated by the New England and Middle Atlantic states. 

Further, the proposed opacity rule will apply stricter opacity limits to all industrial boilers 

than the federal NSPS imposed on new, modified or reconstructed boilers. Additionally, by 

establishing opacity limits for periods of startup, shutdown and malfunction, the proposed 

rule will impose additional regulatory burden not applied even to new, modified or 

reconstructed boilers by the NSPS. 

Comparison to the Federal New Source Performance Standards 

The federal NSPS for Fossil Fuel-Fired Industrial Boilers (40 CFR 60 Subpart Db) limits 

opacity during normal operation to no more than 20 %, except for one one six-minute period 

in each hour when opacity may average no more than 27%. The NSPS thus imposes a less 

stringent standard on new, reconstructed or modified boilers than the proposed Massachusetts 

rule will impose on all industrial boilers, regardless of age or installation date. Promulgation 

of this rule will place an uneven burden on older boilers such as those at GE Lynn, since 

three of GE's boilers were designed and built prior to the 1971 standards. Although GE has 

made a concerted and costly effort to improve boiler operation, as described above, "as built" 

advanced burner and combustion control technologies were not developed when the older 

Lynn boilers were installed in 1943, 1949 and 1962. 

EPA's first concern (as expressed in its April 8, 2003 conditional SIP approval) that there be 

a cap on opacity during start-up and shutdown is difficult to understand in light of the opacity 

provisions of the NSPS regulations. The General Provisions (40 CFR 60 Subpart A) 

specifically address this point at 40 CFR 60.11(c): 

9 
"The opacity standards set forth in this part shall apply at all times except during 

periods of startup, shutdown, malfunction, and as otherwise provided in the 

applicable standard." 

This point is emphasized further by the inclusion of nearly identical language in the NSPS 

for Industrial-Commercial-Institutional Steam Generators at 40 CFR 60.43b(g): 

"The particulate matter and opacity standards apply at all times except during periods 

of startup, shutdown or malfunction." 

Clearly the US EPA felt that the opacity standards should not apply during startup and 

shutdown for industrial facilities in general and industrial boilers in particular. Nonetheless, 

the MA DEP not only applies a cap in these operating situations, but chose to address U.S. 

EPA's concern about the need for an opacity cap during start up and shut down by allowing 

opacity as high as 27% averaged over one six-minute period in each hour. The limit itself is 

the same as that found in the NSPS for "new" mdustrial-Commercial-Institutional Steam 

Generators at 40 CFR 60.43b(f). That is an inappropriate cap for existing older units. 

The EPA's New Source Review Workshop Manual, issued as a Draft in October, 1990, 

provides in Appendix H on construction permits, at Section II.D, that "[pjermit conditions 

defining excess emissions may include alternate conditions for startup, shutdown, and 

malfunctions such as maximum emission limits and operational practices and limits." In 

fact, many permits have been issued throughout New England with different standards for 

startups and shutdowns, as have EPA-approved regulations, as discussed below. 

Other Northeastern States 

Several Northeastern states have adopted visible emissions or opacity regulations that are 

more appropriate than the visible emission limits proposed by the MA DEP. 

Vermont 

Vermont's Department of Environmental Conservation, Air Pollution Control Division 

regulations at Chapter 5-211 differentiate between units constructed prior to April 30, 1970 

and those constructed after that date. Specifically, the regulations provide that units 

constructed before April 30, 1970 are allowed to emit up to 40% opacity or Ringlemann #2, 

except for six minutes in any hour in which emissions of up to 60% opacity /Ringlemann #3 

are allowed. In addition, units constructed after April 30, 1970 may emit up to 20% 

opacity/Ringlemann #1, except for six minutes in any hour in which they may emit no greater 

than 60% opacity/Ringlemann #3. 

The EPA has approved these regulations as part of the state's SIP. See 40 CFR. 52.2381. 

10 
New Hampshire 

New Hampshire's EPA-approved SIP regulations at Part Env-A 1202 also differentiate 

between older and newer units, as well as between larger and smaller units, and provide 

exemptions for various operating scenarios. Specifically, the regulations provide as follows: 

• The visible emission standard for fuel burning devices installed prior to May 13, 1970 is 

no greater than 40% opacity/Ringlemann #2. 

• Units installed after May 13, 1970 date are limited to emissions of no greater than 20% 

opacity/Ringlemann #1, except that units with a gross heat input of 250 million BTU/hr 

may emit up to 40% opacity/Ringlemann #2 for up to two minutes in any hour. 

These standards do not apply to emissions of any unit during the building of a new fire, 

cleaning of fires, or soot blowing, which may emit up to 60% opacity/ Ringlemann #3 for 

periods aggregating six minutes in any 60 minutes. See 40 CFR. 52.1525. 

In August, 2002, New Hampshire submitted to the EPA for SIP inclusion revisions to its 

regulations currently promulgated at Part Env-A 2003, which changed the general standards 

by allowing both pre- and post- May 13, 1970 units to exceed the above thresholds for a 

continuous six minutes in any 60 minute period.3 The new regulations also provide the 

following exemptions: 

• Steam generating units subject to 40 CFR 60 may take either (1) an exemption to 

allow emissions in excess of 20% opacity for one period of six continuous minutes in 

any 60 minute period during periods of startup, shutdown and malfunction, or (2) an 

exemption to allow emissions up to 27% opacity for one period of six continuous 

minutes in any 60 minute period during periods of normal operation, soot blowing, 

grate cleaning, and the cleaning of fires. 

• Devices installed prior to May 13, 1970, having gross heat input at least 500 million 

BTU/hr and equipped with automatic soot blowers may exceed 40% opacity for a 

non-overlapping set or sets of time up to 60 minutes in any 8-hour period during 

startup, shutdown, malfunction, soot blowing, grate cleaning and cleaning of fires. 

• Fuel burning devices not covered by either of the two above exemptions may exceed 

the above-standard for one period of six continuous minutes in any 60 minute period 

during startup, shutdown, malfunction, soot blowing, grate cleaning and cleaning of 

fires. 

• Exceedances of the opacity standards are not considered violations if the source 

demonstrates (1) that such exceedances were the result of adherence to good boiler 

operating practices (such as cold startup over a continuous period of time) or (2) such 

3

 The EPA has not yet acted on this submission. 

11 
exceedances were the result of the occurrence of an unplanned incident beyond the 

control of the operator, and the operator took appropriate steps in accordance with 

good boiler operating practices. 

Maine 

Maine's EPA-approved SIP regulations at 06-096 CMR Chapter 101 on visible emission 

standards differentiate between larger and smaller units, and also provide exemptions during 

startups, shutdowns, and malfunctions. Specifically, 

• Units greater than 250 million BTU/hr may exceed 40% opacity for up to 15 minutes 

in any continuous 3-hour period. 

• Units less than 250 million BTU/hr may exceed 30% opacity for up to 15 minutes in 

any continuous 3-hour period. 

• The above standards do not apply to units greater than 200 million BTU/hr during the 

first four hours following the initiation of cold startup or planned shutdown, provided 

operating records demonstrate that the facility was being operated to minimize 

emissions. 

• The DEP may exempt emissions occurring during periods of unavoidable malfunction 

or unplanned shutdown if not caused by poor maintenance, careless operation, etc. 

See 40 CFR 52.1031. 

Most recently, in May, 2003, Maine amended its visible emissions regulation to read as 

follows4: 

• Boilers less than 1000 million BTU/hr firing #4, #5, or #6 fuel oil may not exceed 

30% opacity on a 6 minute block average basis, except for two 6 minute block 

averages/3 -hr period. 

• Boilers at least 1000 million BTU/hr firing #4, #5, or #6 fuel oil may not exceed 20% 

opacity on a 6 minute block average basis, for 90% of all 6 minute block averages on 

a quarterly basis. The remaining 10% of all 6 minute block averages may not exceed 

30% opacity. 

• Boilers firing #2 oil may not exceed 20% on a 6 minute block average basis, except 

for one 6 min block average in a 3-hour period. 

• For boilers greater than 100 million BTU/hr, the above standards do not apply during 

the first four hours of cold startup or planned shut down, through December 31, 2006 

providing operating records demonstrate that the facility was being operated to 

4

 Note that the new regulations may not have been submitted to the EPA as of yet. 

12 
minimize emissions, and that excess emissions were not caused by poor maintenance, 

careless operation and the like. 

• Boilers greater than 100 million BTU/hr may amend their air emission license to 

establish specific conditions and allowances for boiler startup and shutdown. 

The Maine standards reference state statutes that provide an additional potential exemption 

from visible emissions rule. 

"Title 38 M.R.S.A. § 590(5) addresses the Department's authority to establish 

appropriate license allowances and conditions for periods of cold start ups and shut 

downs. Title 38 M.R.S.A. § 349(9) sets forth the conditions under which the 

commissioner may exempt emissions in excess of license limitations or the limits and 

allowances set for in this Chapter occurring during periods of start up, shut down or 

malfunction. After December 31, 2006, if periods of start up or shutdown are not 

specifically addressed by a source's license, the licensee may apply for a case by case 

exemption under M.R.S.A. § 349(9)." 

Throughout the public comment period for revised Chapter 101 and in its implementation 

memorandum for the rule, the Maine Department of Environmental Protection recognized the 

need for exemptions from the rule. In its memorandum, the Maine DEP states: 

"The start up/shut down exemption has been a difficult issue to resolve because 

boilers regulated by this rule vary in size, type and manufacturer's recommended start 

up procedures, and no single exemption applies to all boilers. Therefore the 

Department is proposing to provide exemptions through the licensing process on a 

case-by-case basis." (Memorandum from Marc Cone, Maine Bureau of Air Quality to 

the Maine Board of Environmental Protection, April 17, 2003) 

New York 

New York's EPA-approved opacity rule at 6 NYCRR 227-1.3(a) imposes the same opacity 

limits as proposed in the revised Massachusetts rule, with no explicit exemption for periods 

of start up, shut down or malfunction. However, the New York rule allows the source to 

apply for an equivalent opacity standard less stringent than the opacity standard in Section 

227-1.3(a) if the source owner can demonstrate through emission tests that the boiler is ".. .in 

compliance with all applicable emission standards other than the opacity standard and that 

the source and any associated emission control equipment is operated and maintained in a 

manner acceptable to the commissioner." See 6 NYCRR 227-1.3(c), 40 CFR 52.1679. 

13 
Connecticut 

Although Connecticut does not have exemptions for older or smaller boilers, its general 

standards at R.C.S.A. § 22a-174-185 are similar to those in Massachusetts' 1972 EPAapproved SIP. Specifically all stationary sources may not emit visible air pollutants darker 

than 20 % opacity/ Ringlemann #1, except for an aggregation of five minutes in any 60 

minutes a source may emit pollutants no darker than 40% opacity/Ringlemann #2. The EPA 

has approved these regulations. See 40 CFR § 52.385. 

Impact to GE 

As discussed above, in 2003, GE retained CCA to conduct a detailed Opacity Study, which 

reviewed all periods of elevated 6-minute block opacity greater than 15% dating back to 

November 2001. These data were extracted from the CEMS database. To assist in 

interpretation of the data, NOx emissions and operating/load data occurring coincident with 

these opacity incidents was also provided to CCA. Finally, in many cases operators had 

noted the reason for opacity excursions on the Daily Opacity Reports; this information was 

also available to CCA to assist in understanding of these events. 

Based on CCA's opacity study, on average across all four units (excluding special testing), 

GE's boilers comply with the 15% 6-minute block average limitation over 99.5% of the time. 

Most of the occurrences of opacity greater than 15% are associated with soot blowing, 

startup or shutdown activities; but as enumerated in the June 30, 2003 CCA Report and the 

Opacity Submittal letter to MA DEP, opacity excursions can also be caused by fuel 

swapping, rapid load changes, very high loads (as a trade-off for NOx control), malfunction 

type events (burner trip, unit trip, operating problems, etc.) as well as 

performance/optimization activities. 

The opacity data (> 15%) for each boiler were compiled by CCA into spreadsheets, and then 

separated into four categories based on Incident Type (Soot Blowing, Startup, Shutdown and 

Other). The grouped data were then formatted into graphs by year for easier visual 

examination. 

The graphs for November 2001 through 2003 are presented in Attachment 2. Each page in 

the attachment shows four graphs (one for each Incident Type) containing one year of data 

for a particular boiler. A 27% opacity line has been inset into each graph to facilitate 

identification of incidents that exceed this ceiling. Each graph also includes summary 

statistics listing: (1) the total number of elevated opacity (> 15%) 6-minute block periods 

under each special operating condition that occurred in the year, (2) the percent of total 

operating time represented by such elevated incidents (i.e. = total time opacity > 15%/ total 

operating time). 

In interpreting these graphs, it should be recognized that the operating patterns of the boilers 

differ. Boiler #3 is considered the base unit for the powerhouse in that it operates almost 

5

 Note that the version approved by the EPA was formerly numbered R.C.S.A. § 19-508-18(a). The text is the 

same in the current publication. 

14 
continuously. Boiler #2 is the primary support boiler and operates for long periods; but it is 

taken out-of-service when demand is low, and therefore has more startups and shutdowns 

than Boiler #3. Boiler #1 and Boiler #5 provide supplemental support, and their utilization 

during the year is more limited. 

The most basic finding, seen in these graphs, is that elevated opacity incidents constitute a 

very small percentage of overall operating time, generally less than a tenth of a percent. The 

graphs also show some decline in the number and severity of elevated opacity events over the 

course of the last two years reflecting the work of CCA, particularly on Boilers #2 and #5, as 

well as on-going efforts of plant personnel to refine operating practices. 

At the same time, the graphs clearly document that occasional opacity spikes above 27% 

occur during startup, shutdown and certain other special conditions, in spite of all the 

improvements made by CCA and in-house personnel. As discussed below, such spikes are 

inherent in the transient, somewhat unpredictable conditions prevailing under special 

situations or conditions. These elevated readings cannot be entirely eliminated by burner 

refinements and proper operating practices. 

CCA's conclusion in Attachment 3 - that the 27% opacity ceiling contained in the draft rule 

could not be satisfied at all times - is consistent with the experience of plant personnel who 

have themselves been closely monitoring opacity in order to both identify operating 

conditions that tend to produce opacity spikes and develop procedures to minimize such 

spikes. The opacity spikes that have proven most intractable are associated with transient 

operating conditions, including startup, shutdown, fuel swapping, abrupt load changes, 

burner trips, etc.). During such transient, off-design conditions the combustion process 

cannot be fully controlled, and therefore spikes cannot be completely avoided. The 

inherently unpredictable nature of these transient events makes it infeasible to completely 

manage opacity on all occasions. 

Of these normal types of transient operating conditions, startup and to a lesser extent 

shutdown, are the most prone to sporadic bursts of opacity spiking, and have proven most 

difficult to control under all circumstances. Conditions at initial unit startup vary 

significantly depending on the length of the shutdown, the amount of time elapsed since the 

last major servicing as well as the nature of any maintenance performed during the shutdown, 

ambient conditions, etc. all of which can combine to act in a somewhat unpredictable manner 

at light-off causing unanticipated combustion behavior, and in some cases brief periods of 

incomplete fuel burn-out, resulting in elevated opacity. Boilers are not high precision 

instruments, like gas turbines, so that startup operations are not entirely repeatable or 

predictable. While proper response by operators can minimize the duration of such spikes, 

they cannot always be entirely prevented. It is for this reason that GE feels imposition of an 

absolute 27% opacity ceiling at startup and shutdown, in particular, is inappropriate, as it is 

inconsistent with level of control achievable by proper system operation. 

Most air quality regulations, including the Massachusetts NOx RACT rule and the NSPS 

Opacity rules, recognize that combustion source opacity and emission controls are not as 

effective during startup and shutdown, and provide an explicit exclusion from compliance 

during such periods. The experience at GE supports the idea that opacity during startup and 

15 
shutdown periods is not amenable to the same type of control as can be achieved during 

normal unit operation. 

In addition, the GE data also indicate that, during scheduled shakedown, testing, and 

calibration activities, the 27% opacity limit could not be met consistently. In fact, enforcing 

the opacity limit during boiler optimization testing and troubleshooting activities would have 

the impact of discouraging operators from implementing such testing protocols which both 

optimize boilers and reduce emissions. In the long run, putting a 27% limit on shakedown, 

testing, and calibration activities, would likely have the impact of increasing emissions. 

GE's Proposal 

Based on the information presented above, GE is requesting that the proposed 310 CMR 

7.06(l)(c) opacity standard be modified to allow for occasional, brief, unavoidable opacity 

excursions, to allow up to two 6-minute block periods greater than 27%, as long as the one 

hour average containing the two 6-minute block periods that exceed 27%, is below 27% 

based on 60 minutes beginning at start-up. In addition, GE is also requesting a provision to 

allow for exemptions from 27% opacity limits for scheduled shakedown activities, testing, 

and calibrations when MA DEP is informed 24 hours prior to the scheduled event. This 

approach will maintain the overall high stringency of this rule, without creating limits that 

are impossible to achieve. 

Specifically, GE proposes that MADEP consider the exemptions below that would preserve 

the stringency of the opacity regulation in Massachusetts, be acceptable to US EPA based on 

precedent and other Region I approved opacity programs, and allow for improvements in 

boiler operations. 

1. ) During startup, shutdown, and soot blowing, allow for two 6-minute block averages 

that exceed 27% as long as the one-hour average remains less than 27%, with a onehour average based on 60 minutes beginning at the onset of the event. 

2. ) Allow for exemptions from the 27% opacity limit for scheduled shakedown activities, 

testing, and calibrations when MA DEP is informed 24 hours prior to the scheduled 

event. 

16 
Proposed 310 CMR 7.18(8)(d-g) Solvent Metal Degreasing 

Introduction 

At its Lynn facility, GE works on intricate and highly sophisticated aerospace components 

that are not amenable to parts cleaning with low-volatility, mineral spirit type solvents. 

These intricate and highly specialized components, which are used in applications such as 

commercial aircraft engines and military fighter jets, require high-purity solvents that will 

leave the parts clean, dry, and without any residue. The Federal Aviation Administration or 

the Department of Defense approves many of the cleaning specifications used on aviation 

components. In fact, residue on aviation parts can cause flight-critical malfunctions 

including in-flight engine shut down. 

GE operates numerous solvent cleaning units at Lynn that are subject to 310 CMR 7.18(8). 

To reduce petroleum-based solvent use, the Lynn facility has migrated over time to the use of 

ultrasonic cleaners and aqueous industrial dishwasher units where technologically feasible. 

As part of its ongoing compliance assurance activities, GE Lynn has carefully evaluated the 

applicability of the Solvent Metal Degreasing rules to its metal cleaning units. 

Extensive Six Sigma error-proofing activities have been conducted to assure that units that 

are clearly regulated by the current rules comply with all applicable requirements. During 

these error-proofing activities, GEAE has determined that various types of aqueous-based 

parts cleaners are inadvertently subject to regulation under 310 CMR 7.18(8). These units, 

which contain water-based detergents with only trace amounts of volatile organics, are 

neither clearly regulated by, nor clearly exempt from, the current Solvent Metal Degreasing 

regulations. These units include such cleaning equipment as large industrial dishwashers, 

ultrasonic cleaning units, and dip tanks containing aqueous solutions with small amounts of 

volatile organic compounds. Because these units use surfactants that contain a small amount 

of organic components, they could not clearly be considered exempt from the current 

regulations. 

Current and Proposed Regulations 

GE believes that 310 CMR 7.18(8) as drafted requires clarification so the regulated 

community can continue to pursue feasible alternatives to petroleum-based solvent cleaning 

without jeopardizing operating flexibility. In short, the rule should include exemptions for 

operations that will have minimal environmental impact. For this reason, GE requests that 

MA DEP consider in its final 310 CMR 7.18 the following revisions: 

• Include an exemption for low-volume cold cleaners (2 gallons or less), 

• Clarify the exemption for aqueous cleaners, and 

• Clarify a reference to instantaneous averaging time 

GE notes that analogous solvent degreasing rules recently promulgated by the Pennsylvania 

Department of Environmental Protection, at 25 PA 129.63 (Solvent Cleaning Operations) 

17 
and New York Department of Environmental Conservation, at 6 NYCRR 266 (Solvent Metal 

Cleaning Processes), as set out below, provide examples of rules that incorporate flexibility 

to account for the diversity of regulated activities. Both Pennsylvania and New York revised 

their solvent cleaning rules - to promote further progress toward the State's attainment of the 

1-hour ozone National Ambient Air Quality Standard. We note also that both US EPA and 

the Ozone Transport Commission approved Pennsylvania's and New York's rules in final 

form, including the exemptions we are recommending for Massachusetts. It is significant 

that neither Pennsylvania's nor New York's pre-existing solvent cleaning rules included 

any such exemptions - these exemptions were only recently adopted. Therefore, 

Massachusetts should have the same ability to adopt such exemptions. 

Our rationale for requesting these exemptions is presented below. 

1. Low volume threshold. Including a low-volume threshold (such as the 2-gallon 

thresholds recently adopted by Pennsylvania and New York, and which was incorporated 

into the Halogenated Solvent Cleaning National Emissions Standards for Hazardous Air 

Pollutants (NESHAP) [40 CFR 63.461]) would provide significant flexibility by allowing 

small, bench top containers of solvent to be used for spot cleaning or wipe cleaning, with 

little or no environmental impact. Such an exemption would minimize regulatory 

burdens for small cleaning operations, and also clarify the applicability of 310 CMR 7.18 

as directed at immersion cold cleaners. 

New York low volume language - 6 NYCRR 226.6 Exemptions 

(a) This Part shall not apply to: 

(a)(1) conveyorized degreasers with an air/vapor interface smaller than 22 square feet 

(2.0 m2); 

(a)(2) open-top vapor degreasers with an open-top area smaller thanl 1 square feet 

(1.0 m2); 

(a)(3) conveyorized and open-top vapor degreasers subject to the requirements in 40 

CFR 63, Subpart T; and 

(a)(4) cold cleaning degreasers that use a solvent with a VOC content of 5 percent or 

less by weight. 

Pennsylvania low volume language - 25 PA129.63. VOC Cleaning Operations 

(a) Cold cleaning machines. Except for those subject to the Federal NESHAP for 

halogenated solvent cleaners under 40 CFR Part 63 (relating to National emission 

standards for hazardous air pollutants for source categories), this subsection 

applies to cold cleaning machines that use 2 gallons or more of solvents 

containing greater than 5% VOC content by weight for the cleaning of metal 

parts. 

18 
Halogenated Solvent Cleaning NESHAP low volume language - 40 CFR 63.461 

Definitions 

Solvent cleaning machine means any device or piece of equipment that uses 

halogenated HAP solvent liquid or vapor to remove soils from the surfaces of 

materials. Types of solvent cleaning machines include, but are not limited to, batch 

vapor, in-line vapor, in-line cold, and batch cold solvent cleaning machines. Buckets, 

pails, and beakers with capacities of 7.6 liters (2 gallons) or less are not considered 

solvent cleaning machines. 

2. Clarify the definition of "Aqueous Cleaning". GEAE lauds MA DEP for considering 

the use of an aqueous exemption in its proposed 310 CMR 7.18(8) Solvent Metal 

Cleaning regulations. However, as written, virtually no aqueous solvent cleaners would 

be exempted from regulation since the conditions for exemptions are either too stringent 

or impractical to apply. Many aqueous cleaning solutions contain a small amount of 

organic components, such as glycols or glycol ethers, or various surfactants. To be 

considered an aqueous cleaner, the current proposed regulation requires that "the cleaning 

fluid contains no more than 10 percent by weight organic material, excluding soaps6; and, 

all organic materials have a vapor pressure less than 1 millimeter Mercury (mm Hg) at 25 

degrees Celsius" (310 CMR 7.18(8)(d)(ii)). Although it appears that some organic 

materials contained in our current aqueous cleaners may meet the 1 mm Hg threshold, 

many of the surfactants and other additives are not common chemicals and thus vapor 

pressure information is not readily available. Examples of these additives are "alkyl 

polyoxyalkylene glycol ether" and "nonylphenoxypoly (ethyleneoxy) ethanol." 

Determining the vapor pressures of such obscure materials will demand unreasonable 

time and resources at the facility level, with little value added because the materials 

typically are present in very small amounts (< 5 %). This effort makes it extremely 

difficult to demonstrate compliance with little added benefit given the low volume of the 

VOC contained within the aqueous cleaner. 

We note that the Federal Aerospace NESHAP [40 CFR 63.741(f)] exempts from 

substantive regulation as wipe cleaning solvents, any water-miscible solution with greater 

than or equal to 80 percent water with a flashpoint greater than 200 degrees Fahrenheit. 

No vapor pressure limitation is imposed. This rule also specifies that "detergents, 

surfactants, and bioenzyme mixtures and nutrients may be combined with the water along 

with a variety of additives, such as organic solvents (e.g., high boiling point alcohols), 

builders, saponifiers, inhibitors, emulsifiers, pH buffers, and antifoaming agents." (Table 

1, 40 CFR 63.744(e)). We encourage MA DEP to adopt a similar, easy to implement 

6

 Typically, documentation for cleaners, such as a Material Safety Data Sheet (MSDS), will not list any nonhazardous ingredients; and even if manufacturers provide detailed listings of components, it is not readily 

apparent whether organic materials meet MA DEP's definitions of either volatile organic compounds (VOC) or 

soaps. Since few members of the regulated community will go to the trouble or expense of a detailed database 

search or analysis to determine if a compound will "participate in atmospheric photochemical reactions," 

virtually any carbon-containing compound not specifically excluded from MA DEP's definition is considered a 

VOC. Similarly, it is difficult to apply the definition of a "soap" to a listing of ingredients that may include, for 

example, "orange terpene" or "sodium xylene sulfonate," as provided on some household and industrial 

cleaners. 

19 
exemption in its rules. The imposition of a vapor pressure threshold creates obstacles to 

compliance due to the inability to determine the vapor pressure of many trace additives. 

The recently-promulgated Pennsylvania and New York solvent cleaning rules exempt 

aqueous cleaners with up to 5% VOC - without a vapor pressure threshold. We 

encourage MA DEP to incorporate this type of simple, percentage-based exemption in its 

solvent cleaning rules. Allowing the use of aqueous solvents with small amounts of VOC 

will promote, rather than hinder, Massachusetts' program to reduce VOC emissions by 

encouraging conversion to cleaning technologies using aqueous materials with small 

amounts of VOC for use as surfactant, biocide, or other purposes. We urge MA DEP to 

follow the example of US EPA and the States of Pennsylvania and New York by 

exempting the use of materials with up to 5% VOC from 310 CMR 7.18(8) without 

limiting the vapor pressure of the VOC components. 

3. Clarify the Reference to Instantaneous Averaging Time. The proposed 310 CMR 

7.18(8)(g) references the preparation and maintenance of daily records to demonstrate 

compliance with instantaneous averaging time. While this is not a change to the existing 

rule except in citation, the revision offers an opportunity to clarify what is a confusing 

reference for the regulated community. The reference to instantaneous averaging time 

refers back to 7.18(2)(a), which indicates that instantaneous averaging time is the 

compliance test method averaging time based on emissions control methods applicable to 

coatings industries, not to degreasers. Coatings are covered in a separate part of the rule, 

and reference to instantaneous averaging time within the context of Solvent Metal 

Cleaning is unclear. Therefore, GE suggests that the first sentence of 310 CMR 7.18(g) 

be revised to read: 

"Any person subject to 310 CMR 7.18(8)(a)(b)(c) or (d) shall prepare and maintain 

daily records sufficient to demonstrate continuous compliance as stated in 310 CMR 

7.18(2)(a)." 

GE believes that Massachusetts can include the exemptions described above in 310 CMR 

7.18 without compromising the air quality goals of the State, US EPA or the Ozone 

Transport Commission. The same forces that required revision of solvent cleaning rules in 

Pennsylvania and New York, which were approved by both US EPA and the Ozone 

Transport Commission, drive revision of 310 CMR 7.18(8). 

In fact, promulgation of 310 CMR 7.18(8) without such exemptions would result in an 

unlevel playing field among Ozone Transport Region states. Massachusetts' proposed 310 

CMR 7.18(8) is unnecessarily much more stringent than either Pennsylvania's or New 

York's promulgated solvent cleaning rules. In comparing the regulatory constraints imposed 

by the two neighboring states, industry could choose to locate or re-locate in either state 

rather than Massachusetts because of the additional operating flexibility offered, while still 

meeting the objectives of the Ozone Transport Commission to reduce VOC emissions. 

We believe that exemptions from 310 CMR 7.18(8) such as those described above would 

focus the rule on the more significant solvent metal cleaning operations. In particular, GE 

20 
believes that exemptions for small quantity solvent metal cleaning operations (<2 gallons) 

and solutions with less than 5% VOC content can qualitatively be shown to be on the whole 

as effective as the current rule given the relatively low level of emissions from such 

operations. We also believe the exemptions could result in even further VOC reductions than 

the current 310 CMR 7.18 because they would encourage the use of aqueous or lower vapor 

pressure cleaning solvents with inherently lower emissions. 

Because controlling such de minimis sources (i.e., those containing 2 gallons or less, or those 

using solvents with less than 5% VOC content) under 310 CMR 7.18 would result in little or 

no environmental gain, Alabama Power Co. v. Costle, 636 F.2d 323, 357 (D.C. Cir. 1979), 

provides sufficient legal authority for exempting them. Finally, to the extent that the 

Department adopts new exemptions in 310 CMR 7.18 consistent with our comments, GE 

also asks the Department to adopt corresponding permitting exemptions under 310 CMR 

7.02 and 7.03. 

Impact to GE 

The inclusion of the requested exemptions and clarifying language in the revised 310 CMR 

7.18(8) would demonstrate clearly that the Solvent Metal Cleaning rule does not apply to 

industrial dishwashers and ultrasonic cleaners using aqueous-based surfactants containing 

trace amounts of VOC. Regulation of such units does not result in any appreciable 

environmental benefit, and the original intent behind their design was to use other 

mechanisms for cleaning (i.e., ultrasonic and high-pressure water), than those afforded by 

traditional hydrocarbon-based solvents. The clear exemption of the use of small amounts of 

VOC contained within aqueous solutions will encourage conversion to these technologies 

that are more environmentally beneficial. 

The clarification regarding instantaneous averaging time simply allows the regulated 

community to clearly understand the obligations set forth in 310 CMR 7.18(8), Solvent Metal 

Cleaning, without allowing question of compliance demonstration which clearly references 

another section of the regulation. 

GE's Proposal 

GE proposes that MADEP include in its Solvent Metal Degreasing Regulations, language 

that will allow for the continued manufacture of high-performance military and commercial 

aircraft engines and components, while realizing significant environmental benefit from 

encouraging the use of aqueous cleaning technologies. GE proposes that MADEP: 

1. Include an exemption for low-volume cold cleaners that are 2 gallons in capacity 

or smaller. Precedent for such an exemption is established in the U.S. EPA 

Halogenated Solvent Degreasing NESHAP and recently promulgated solvent 

cleaning regulations in New York and Pennsylvania. 

2. Clarify the exemption for aqueous cleaners such that up to 5% VOC-containing 

materials can be contained within the aqueous cleaner, regardless of the vapor 

21 
pressure of the VOC component. Such an exemption will encourage migration 

from traditional solvent cleaning technologies, to alternative aqueous cleaners. 

Eliminate the reference to instantaneous averaging time to more accurately reflect 

that the compliance test method for degreasers is the preparation and maintenance 

of daily records of continuous compliance as stated in 310 CMR 7.18(2)(a). 
Proposed 310 CMR 7.54 U Large Combustion Emission Units 

Introduction 

GE offers the following comments on MA DEP's proposed changes to 310 CMR 7.54 U 

Large Combustion Emission Units. Specifically, the definitions imposing federal 

enforceability requirements for regulated facilities are unnecessary as a result of past 

decisions of the D.C. Circuit Court of Appeals.7 Therefore, GE submits that the word 

"federally" should be removed and replaced with "practically" when relating to 

enforceability. GE also submits that the definition for "construction" is redundant in the 

amendments as it is essentially the same as the definition for "modification." Finally, GE 

submits that the definition for "pollution control project" should not be limited to the listed 

projects; it should also include low NOx burners and provide flexibility for other obvious 

pollution control measures. 

1. Federal Enforceability Unnecessary 

US EPA's definition of "potential to emit" has been under controversy for 25 years, with 

courts repeatedly asking the US EPA to amend its definition to recognize limitations on 

emissions to be included in the calculation of a source's potential to emit. Initially, US EPA 

amended its definition to include limitations on emissions, but only those that were "federally 

enforceable." To comply with this statutory directive, US EPA's rules previously provided: 

Any physical or operational limitation on the capacity of the stationary source to emit 

a pollutant, including air pollution control equipment and restrictions on hours of 

operation or on the type or amount of material combusted, stored, or processed, shall 

be treated as part of its design if the limitation effect it would have on emissions is 

federally enforceable.8 

Although US EPA announced a rule in 1983 that did not include the federal enforceability 

requirement, when the final rule was promulgated, US EPA stated that the limitations must 

be federally recognized and enforceable.9 Finally, in 1995, the D.C. Circuit Court of Appeals 

recognized that US EPA's definition of "potential to emit" was based on an unsubstantiated 

need for absolute federal control and the US EPA had failed to recognize obviously effective 

state-imposed limitations.10 The definition was once again sent back to US EPA requesting 

that state and local limitations be recognized, until finally in Chemical Manufacturers 

Association et al. v. EPA, the DC Circuit vacated the EPA's definition altogether.11 

7

 National Mining Association v. United States EPA, 313 U.S. App. D.C. 363, 59 F.3d 1351 (D.C. Cir. 1995). 

8

 45 Fed. Reg. 52,676(1980). 

9

 54 Fed. Reg. 27,274(1989). 

1 0

 National Mining Association v. United States EPA,2,\3 U.S. App. D.C. 363, 59 F.3d 1351 (D.C. Cir. 1995). 

1 1

 Chemical Manufacturers Association, et al. v. EPA, 1995 U.S. App. LEXIS 31475, 70 F.3d 637 (D.C. Cir. 

September 15, 1995); See also Clean Air Implementation Project v. EPA, No. 96-1224, 1995 U.S. App. LEXIS 

18402 (D.C. Cir. June 28, 1996). 

23 
On the basis of the DC Circuit cases that led to US EPA's regulation being vacated, GE 

submits that the proposed MA DEP definitions for "net emission increase" under section 

7.54(d)(7)(b), "potential to emit" under section 7.54(e) and "allowable emissions" under 

section 7.54(i) not include the words "federally enforceable" but rather use "practically 

enforceable," instead, making these definitions consistent with current federal law. 

Therefore, GE requests that these proposed definitions be revised in 310 CMR 7.00 

accordingly. 

2. Definition for Construction Unnecessary 

The proposed MA DEP amendments contain a definition for "construction" in section 

7.54(f), however, these regulations for Large Combustion Emission Units only apply to the 

substantial reconstruction of one or more large combustion emission units resulting in major 

modification. Therefore, this definition for "construction" is not really necessary and it does 

not appear to be used anywhere in the proposed regulations that make changes to section 7.54 

U Large Combustion Emission Units. Also, the definition that is written appears to be 

almost identical to the previous definition for "major modification" in section 7.54(c), that 

similarly states, in part, "any physical change or change in the method of operation.. .that 

would result in a significant net emissions increase." Therefore, the definition for 

"construction" is redundant and need not be included in the amendment. 

3. Definition of Pollution Control Project 

GE would also like to comment on the pollution control project definition in section 7.54(n), 

to recommend that the definition not be exclusive to the projects listed but rather state "such 

projects or activities include, but are not limited to..." GE also proposes that low NOx 

burners be included in the list of projects under "the installation of conventional or 

innovative pollution control technology" under section 7.54(n)(l). The installation of low 

NOx burners should clearly be included in the definition of "pollution control projects." 

24 
Attachment 1 

US EPA Region 10 Response 

Turbine Relocations and Impacts on NSPS Applicability 
Control Number: 0300006 

193405361.txt 

Category: NSPS 

Region: Region 10 

Date: 08/01/2002 

Title : Turbine Relocations and Impacts on NSPS Applicability 

Recipient: Jordan Jacobson 

Author: Jeff KenKnight 

Comments: 

Subparts: Part 60 A General Provisions 

Part 60 GG Stationary Gas Turbines 

References: 60.14(e)(6) 

60.2 

60.330 

Abstract: 

Ql: Are turbines that were manufactured before October 

3, 1977, but that did not begin operation on the TAPS pump 

stations unti l after October 3, 1977, subject to NSPS 

Subpart GG, no matter when they were purchased by Alyeska 

from the manufacturer or other owner? 

A l: No. These stationary gas turbines, that are purchased 

in completed form, are not subject to NSPS GG provided they 

were not "modified" or "reconstructed" as defined in NSPS 

Subpart A, on or after October 3, 1977. 

Q2: Do the requirements of subparts A and GG follow a 

new turbine wherever i t i s operated on the TAPS? 

Page 1 
193405361.txt 

A2: Yes. The requirements of subparts A and GG follow a 

turbine constructed, modified or reconstructed after 

October 3, 1977, regardless of where the turbine i s 

relocated to, but do not apply to the equipment that i s 

powered by the turbine (such as a generator or a pump). 

Q3: Do the Alyeska turbines that were manufactured before 

October 3, 1977 become subject to NSPS GG i f they are 

relocated between TAPS pump stations as a pool of identical 

turbines to allow for maintenance of turbines? 

A3: No. The relocation of a turbine as part of a pool of 

identical turbines would not make the turbine subject to 

NSPS subpart GG i f the turbine i s not "modified" or 

"reconstructed," as those terms are defined in 40 CFR 

subpart A, as a result of the relocation, certain 

requirements are required in the Titl e V permit. 

Q4: Does a turbine that i s not subject to NSPS subpart GG 

become subject to NSPS subpart GG i f i t i s rotated into a 

location to replace a turbine that i s subject to NSPS 

subpart GG? 

A4: No. As discussed above, a relocation of an affected 

facilit y is not, by itself , a modification. 

Letter: 

August 1, 2002 

Reply To 

Page 2 
Attn Of: OAQ-107 

193405361.txt 

Jordan E. Jacobson 

Counsel 

Alyeska Pipeline service Company 

1835 South Bragaw Street 

Anchorage, Alaska 99512 

Re: 40 CFR part 60, Subpart GG, Applicability Determination 

Dear Mr. Jacobson: 

The purpose of this lette r i s to respond to your lette r of 

December 18, 2001, asking several questions relating to the 

applicability of New source Performance standard (NSPS) 

subparts A and GG (Standards of Performance for Stationary 

Gas Turbines) to turbines used in the operation of the 

Trans-Alaska Pipeline System (TAPS) pump stations. NSPS 

subpart GG applies to al l stationary gas turbines with a 

heat input at peak load equal to or greater than 10.7 

gigajoules (10 mil. Btu) per hour, based on the lower 

heating value of the fuel fired , that commenced 

construction, modification or reconstruction after October 

3, 1977. See 40 CFR 60.330. 

Your lette r correctly states that the state of Alaska does 

not have federal delegation of NSPS subpart GG, and you 

therefore appropriately directed your applicability 

determination to EPA. Authority to issue determinations 

pertaining to applicabilit y of a source to 40 CFR part 60 

has been delegated to the unit Managers in EPA Region 10's 

Page 3 
Office of Air Quality. 

193405361.txt 

Background 

Alyeska is the operator of TAPS on behalf of the 

pipeline owner companies, crude oi l pipeline common 

carriers. The TAPS pipeline transports crude oi l through 

the pipeline by pumps that are associated with pump 

stations. According to Alyeska, the pump stations at 

issue, including the major equipment and emission sources 

"commenced construction," as defined in NSPS subpart A, 

prior to October 3, 1977. The pump stations employ 

turbines that provide mechanical power for a number of 

tasks, such as powering pumps and electric generators. The 

turbines are removed from their operating locations 

periodically for maintenance and a turbine from the TAPS 

inventory of the same turbine family is substituted as a 

replacement. The equipment powered by the turbine (such as 

the pump or the electric generator) remains in place. In 

other words, there are a number of turbines, both in use 

and in inventory, that are moved around the TAPS from 

location to location. 

Most of the turbines were manufactured and began operation 

on the TAPS prior to October 3, 1977, the applicability 

date for NSPS subpart GG. Alyeska does also have some 

turbines manufactured after October 3, 1977. According to 

your letter , Alyeska has at al l times treated these 

turbines manufactured after October 3, 1977, as subject to 

NSPS subparts A and GG regardless of where they are 

operated on the TAPS. 

Page 4 
193405361.txt 

The turbines at issue i n Alyeska's applicability 

determination request are those that were manufactured 

before October 3, 1977, but did not begin operating on the 

TAPS unti l after October 3, 1977, for one of several 

reasons: 

-the turbines were purchased and maintained by Alyeska 

before October 3, 1977, but did not begin operation on the 

TAPS unti l after October 3, 1977. These turbines were 

held as spares and late r rotated into service to replace 

operating turbines removed for maintenance; 

- the turbines were not purchased by Alyeska unti l after 

October 3, 1977 and therefore did not begin operation on 

the TAPS unti l after October 3, 1977; or 

-the turbines were purchased used by Alyeska after October 

3, 1977 from another owner who bought them before October 

3, 1977. Alyeska does not know whether they were placed 

into operation by the previous owner before October 3, 

1977. 

Question 1: Are the turbines that were manufactured before 

October 3, 1977 and purchased and maintained by Alyeska 

before October 3, 1977, but that did not begin initia l 

operation on the TAPS unti l after October 3, 1977 because 

they were held as spares and later rotated into service, 

subject to NSPS subpart GG? 

Question 2: Are the turbines that were manufactured before 

October 3, 1977, but were not purchased by Alyeska from the 

Page 5 
193405361.txt 

manufacturers unti l after October 3, 1977 (and therefore 

did not begin operation on the TAPS unti l after October 3, 

1977), subject to NSPS subpart GG? 

Question 3: Are the turbines that were manufactured before 

October 3, 1977, and purchased as used by Alyeska after 

October 3, 1977 from another owner who bought them before 

October 3, 1977, subject to NSPS subpart GG, even i f they 

may not have been placed into operation by the previous 

owner before October 3, 1977? 

Response 1, 2 and 3: In the case of stationary gas 

turbines that are mass-produced and purchased in completed 

form, EPA considers the manufacturer as the original owner 

or operator. Based on the information provided in your 

letter , the turbines you describe appear to fi t this 

description. Therefore, these turbines are not subject to 

NSPS GG provided they were not "modified" or 

"reconstructed", as defined in NSPS subpart A, on or after 

October 3, 1977. See Letter from Edward E. Reich, EPA, to 

David, L. Mulliken, dated December 29, 1980 (Control Number 

GG06) (for purposes of subpart GG, EPA considers the 

manufacturer as the original owner or operator and hence 

subject to the standard; once the manufacturer has sold a 

turbine, i t i s no longer considered the owner or operator 

of that turbi ne). 

Question 4: Do the requirements of NSPS subparts A and GG 

apply only to the turbine, as the "affected facility, " so 

that a turbine that i s subject to NSPS subparts A and GG i s 

operated as a GG turbine no matter where i t is operated on 

Page 6 
193405361.txt 

the TAPS? in other words, do the requirements of subparts 

A and GG follow the new turbine wherever i t i s operated on 

the TAPS? 

Response 4: under NSPS subparts A and GG, the turbine i s 

the "affected facility, " as defined in 40 CFR 60.2 and the 

requirements of subparts A and GG follow a turbine 

constructed, modified or reconstructed after October 3, 

1977, regardless of where the turbine is relocated to. See 

40 CFR 60.2 (definition of affected facility) ; 40 CFR 

60.330 (applicability and designation of affected facilit y 

under subpart GG). The "affected facility " subject to NSPS 

subpart GG i s the stationary gas turbine and does not 

include the equipment that i s powered by the turbine (such 

as a generator or a pump). 

Question 5: Do the Alyeska turbines that were manufactured 

before October 3, 1977 become subject to NSPS GG i f they 

are treated as a pool of identical turbines and moved from 

location to location between TAPS pump stations to allow 

f or maintenance of turbines? 

Response 5: Assuming the maintenance does not result i n a 

"modification" or "reconstruction," as those terms are 

defined in 40 CFR subpart A, and, assuming that the 

turbines are not otherwise "modified" or "reconstructed," 

as those terms are defined i n 40 CFR subpart A, as a result 

of the relocation of the turbines, relocation of a turbine 

as part of pool of identical turbines would not make the 

turbine subject to NSPS subpart GG. See 40 CFR 

60.14(e)(6)(the relocation or change in ownership of an 

affected facilit y i s not, by itself , a modification); see 

Page 7 
193405361.txt 

also Letter from Steven c. Riva, Chief, Permitting 

section, Air Programs Branch, EPA Region 2, to Thomas 

Micai, Chief, Bureau of Operating Permits, Air Quality 

Permitting Program, New Jersey Department of Environmental 

Protection, dated April 1, 1999 (switching a pool of 

identical turbines among different generating stations to 

allow for the routine repair of malfunctioning units does 

not constitute a "modification" for purposes of NSPS 

provided the turbines are not otherwise modified or 

reconstructed); lette r from R. Douglas Neeley, Chief, Air 

and Radiation Technology Branch, Air, Pesticides and Toxics 

Management Division, EPA Region 4, to Ronald W. Gore, 

Chief, Air Division, Alabama Department of Environmental 

Management, dated March 1, 1999 (Control Number 0000110) 

(subpart GG does not apply to turbines retrofitte d with 

pollution control equipment or relocated to another 

facilit y i f the cost for any repairs or maintenance 

undertaken as a result of relocation is less than 50% of 

the cost for comparable new turbines; assumes the 

retrofittin g with pollution control equipment wil l not 

increase emissions). 

The Titl e v permit can be written to reflect Alyeska's 

practice of maintaining a pool of turbines and moving 

turbines from location to location between TAPS pump 

stations to allow for maintenance of turbines by using the 

authority provided for reasonably anticipated operating 

scenarios in 40 CFR 70.6(a)(9). To do this , i t i s 

essential that the Titl e V permit require monitoring, 

recordkeeping, and reporting requirements to document that 

the turbines not subject to NSPS subpart GG can be clearly 

Page 8 
193405361.txt 

identifie d and that the relocation and replacement of such 

turbines from the pool does not constitute a "modification" 

or "reconstruction," as those terms are defined in NSPS 

subpart A. EPA therefore expects that the Titl e v permit 

issued for the TAPS wil l contain monitoring, recordkeeping, 

and reporting requirements along the lines of the 

foi1owi ng: 

1. inclusion in the permit of a complete lis t of al l 

turbines maintained as part of the pool, with detailed 

information on the make, model, date of manufacture, serial 

number, maximum heat input, and location for each turbine. 

This must be made part of the Titl e V permit and updated 

with regard to the location of each turbine as it s i s moved 

along the TAPS. 

2. A requirement to maintain, for each turbine, records of 

the maintenance/repairs/parts replacement, including the 

date and time of each servicing, the service performed, and 

the costs of the service. 

3. A requirement to notify the permitting authority in 

writing no later than 7 days after any turbine from the 

pool is switched with another turbine from the pool. 

4. A requirement to record in a log the following 

information each time a turbine i s switched: 

a. the date the switch occurred; 

b. identification of the malfunctioning turbine and the 

substitute turbine by make, model, date of manufacture, 

Page 9 
193405361.txt 

serial number, maximum heat input, and location; and 

c. a demonstration (such as mass balance) showing that the 

switch did not result in an increase of any pollutant or 

the emission of a new pollutant not previously emitted. 

Question 6: Does a turbine that i s not subject to NSPS 

subpart GG (because i t was not constructed, modified or 

reconstructed after October 3, 1977) become subject to NSPS 

subpart GG i f i t rotated into a location to replace a 

turbine that is subject to NSPS subpart GG? 

Response 6: A turbine that was not constructed, modified 

or reconstructed after October 3, 1977, as those terms are 

defined in 40 CFR subpart A, does not become subject to 

NSPS subpart GG simply because i t i s rotated into a 

location to replace a turbine that i s subject to NSPS 

subpart GG. As discussed above, under NSPS subparts A and 

GG, the turbine is the "affected facility, " as defined in 

40 CFR 60.2, and a relocation of an affected facilit y is 

not, by itself , a modification. 

Please note that the responses in thi s lette r are limited 

to questions presented under NSPS subparts A and GG. Other 

CAA requirements may apply to these kinds of changes, such 

as major New Source Review or Prevention of Significant 

Deterioration. I f you have any questions regarding the 

above, please feel free to contact me at (206) 553-6641 or 

contact Kai-Hon Shum at (206) 553-2117 for technical 

matters or 3ulie vergeront at (206) 553-1497 for legal 

matters. 

Page 10 
193405361.txt 

Sincerely, 

/Signed/ 

Jeff KenKnight, Manager 

Federal And Delegated Air Programs Unit office of Air 

Quality 

cc: John Kuterbach (ADEC) 

Page 11 
Attachment 2 

Combustion Components Associates, Inc. 

Analysis of GE AE Lynn, Massachusetts, Opacity Data 
GE - Lynn, MA 

Boilers 1,2,3 & 5 

6 Min Average Opacity > 15% by Year 

November 19,2003 

Prepared by 

Nathan Schindler 

Combustion Components Associates, Inc. 

884 Main Street 

Monroe, CT 06468 
100 

g 80 

S 60 

o 

CO 

QL 

O 

40 

20 

0 

1/1/2001 

100 

qr 80 

>> 60 

a 40 

° 20 

0 

1/1/2001 

100 

g 80 

>r 60 

o 

a

 4 0 

O 20 

0 

1/1/2001 

100 

g 80 

>? 60 

o 

a

 4 0 

° 20 

0 

GE-Lynn, MA - Boiler #1 

2001 - 6 Minute Averages > 15% Opacity 

Soot Blowing 

4/2/2001 

4/2/2001 

4/2/2001 

1 - 6 Minute Averages: 0.042% Operating Time 

27% Opacity 

7/2/2001 

Start Up 

10/1/2001 12/31/2001 

7 - 6 Minute Averages: 0.295% Operating Time 

27% Opacity ft o 

7/2/2001 

Shut Down 

10/1/2001 12/31/2001 

0 - 6 Minute Averages: 0.00% Operating Time 

27% Opacity 

7/2/2001 

Other 

10/1/2001 12/31/2001 

- * 

:": ; 

0 - 6 Minute Averages: 0.00% Operating Time 

:

 i :

 i 

-

27% ^picity 

i i ! \ 1 i 

1/1/2001 4/2/2001 7/2/2001 

237 Operating Hours November 1 - December 31 

10/1/2001 12/31/2001 
100 

qr 80 

^ 60 

§ 40 Q. 

O 20 : 

0 

1/1/2002 

100 

80 : 

& 60 

CD 

QL 

O 

40 : 

20 

0 

1/1/2002 

GE-Lynn, MA - Boiler #1 

2002 - 6 Minute Averages > 15% Opacity 

Soot Blowing 

4/2/2002 

4/2/2002 

3-6 Minute Averages: 0.02% Operating Time 

27% Opacity 

7/2/2002 

Start Up 

10/1/2002 12/31/2002 

5-6 Minute Averages: 0.03% Operating Time 

27% Opacity 

7/2/2002 10/1/2002 12/31/2002 

100 

qr 80 

5 60 

a

 4 0 

° 20 

0 

1/1/2002 

100 

Co 80 

£ 60 

'§. 40 

° 20 

0 

1/1/2002 

o o 

4/2/2002 

4/2/2002 

Shut Down 

4 - 6 Minute Averages: 0.03% Operating Time 

27% Opacity 

7/2/2002 

Other 

10/1/2002 12/31/2002 

2 - 6 Minute Averages: 0.01% Operating Time 

27% Opacity 

J [_ 

7/2/2002 10/1/2002 12/31/2002 

1448 Operating Hours 
100 

3^ 80 

co 40 

Q. 

o 20 

0 

1/1/2003 

100 

qr 80 

2 60 

Q.

 4 0 

° 20 

0 

1/1/2003 

100 

80 : 

& 60 

° 20 

0 

1/1/2003 

100 

80 

^ 60 F 

'o 

CD 

Q. 

o 

40 

20 

GE - Lynn, MA - Boiler #1 

2003 - 6 Minute Averages > 15% Opacity 

Soot Blowing 

- } _-

; 4-6 Minute Averages: 0.02 5% Operatin Operating Time 

:

 i 

- j i 

- * ~ —©—. •• 27% Opacity r 

S3 ; 

4/2/2003 7/2/2003 

Start Up 

10/1/2003 12/31/2003 

- * 

r..- r:': — ':..-f . : 8-6 Minute Averages: 0.05% Operating Time 

- i 

- • 

; 27% Oparitv 

o 

_.o.. - o o 

i i 

4/2/2003 7/2/2003 

Shut Down 

10/1/2003 12/31/2003 

3-6 Minute Averages: 0.02% Operating Time 

27% Opacity 

1 

4/2/2003 7/2/2003 

Other 

10/1/2003 12/31/2003 

1

 7-6 Minute Averages: 0.04% Operating Time 

27% Opacity 

0 

1/1/2003 4/2/2003 7/2/2003 

1612 Operating Hours Thru November 13 

10/1/2003 12/31/2003 
GE-Lynn, MA - Boiler #2 

2001 - 6 Minute Averages > 15% Opacity 

Soot Blowing 

100 

Co 80 

0

s 

J 60 

8.

 4 0 

° 20 

0 

; 3-6 Minute Averages: 0.04% Operating Time 

' : } 

- : ; 

- * ; 27% Opacity """ - a 

- f * 

.... , 

.0 ? 

1/1/2001 4/2/2001 

100 

7/2/2001 

Start Up 

10/1/2001 12/31/2001 

Co 80 ~ 

60 

'o 

CO 

Q. 

O 

40 

20 

0 

1/1/2001 

58 - 6 Minute Averages: 0.76% Operating Time 

"* .0.""'. Tz 

:;:' • 0 • 0 

r t 

- • O 

... . , . 27% Opacity 

8S -88 -

4/2/2001 7/2/2001 

Shut Down 

10/1/2001 12/31/2001 

100 

Co 80 

>> 60 

o 

CO 

Q. 

O 

40 

20 

4 - 6 Minute Averages: 0.05% Operating Time 

0 

1/1/2001 

27% Opacity 

4/2/2001 7/2/2001 

Other 

10/1/2001 12/31/2001 

>> 

0 

CO 

Q. 

o 

100 

80 

60 

40 

20 

0 

1/1/2001 4/2/2001 7/2/2001 10/1/2001 12/31/2001 

760 Operating Hours November 1 - December 31 

- ; 

2-6 Minute Averages: 0.026% Operating Time 

-

?7% Opacity 

1 i 

. . . 0 0 
GE - Lynn, MA - Boiler #2 

2002 - 6 Minute Averages > 15% Opacity 

Soot Blowing 

100 

Co 80 

o^ 

>, 60 ° 

co 40 

° 20 

0 

1/1/2002 

100 

80 

&

 6 0 

i.

 4 0 

° 20 

1/1/200 0 2 

100 

Co 80 

>, 60 

CD 40 

° 20 

0 

1/1/2002 

4/2/2002 

o o 

4/2/2002 

4/2/2002 

100 

Co 80 

1 5 s 

60 

I 40 

° 20 

0 

1/1/2002 

6093 Operating Hours 

1 1 

4/2/2002 

30 - 6 Minute Averages: 0.05% Operating Time 

27% Opacity 

o o 

7/2/2002 

Start Up 

10/1/2002 12/31/2002 

109-6 Minute Averages: 0.18% Operating Time 

27% Opacity 

7/2/2002 

Shut Down 

10/1/2002 12/31/2002 

: . ... . .... „ ........... : 

.. 11 -6 Minute Averages Averages: 0.02% Operatin Operating Time 

- - ; •_- - -'• 

i t 

.° o § -

T i 

8o 

7/2/2002 

Other 

10/1/2002 12/31/2002 

11- 6 Minute Averages: 0.02% Operating Time 

27% Opacity 

7/2/2002 10/1/2002 12/31/2002 
100 

80 

>> 60 

'o 

CO 40 

Q. 

O 20 

0 

1/1/2003 

100 

Co 80 

J 60 

g.

 4 0 

° 20 

0 

1/1/2003 

100 

Co 80 

^ 60 

I 40 

° 20 

0 

1/1/2003 

100 

c? 80 

+-« 60 

'o 

CO o 

40 

O 20 

0 

GE-Lynn, MA - Boiler #2 

2003 - 6 Minute Averages > 15% Opacity 

Soot Blowing 

12-6 Minute Averages: 0.02% Operating Time 

27% Opacity 

4/2/2003 7/2/2003 

Start Up 

10/1/2003 12/31/2003 

—o 0 

-©— e 

8 - 6 Minute Averages: 0.01 % Operating Time 

27% Opacity 

4/2/2003 7/2/2003 

Shut Down 

10/1/2003 12/31/2003 

3-6 Minute Averages: 0.005% Operating Time 

27% Opacity 

4/2/2003 7/2/2003 

Other 

10/1/2003 12/31/2003 

OO '-

14-6 Minute Averages: 0.02% Operating Time 

— u— 

27% Opacity 

1/1/2003 4/2/2003 7/2/2003 10/1/2003 12/31/2003 

5887 Operating Hours Thru November 13 
GE-Lynn, MA - Boiler #3 

2001 - 6 Minute Averages > 15% Opacity 

Soot Blowing 

100 

Co 80 

o^ 

J 60 

co 40 

Q. 

o 

20 : 

0 

1/1/2001 4/2/2001 

100 

Co 80 

& 60 

CD 40 

° 20 

0 

7/2/2001 

Start Up 

10/1/2001 

1/1/2001 4/2/2001 7/2/2001 

Shut Down 

10/1/2001 

100 

Co 80 

o"-

& 60 

CD 40 

° 20 

0 1/1/2001 4/2/2001 

100 

Co 80 

0

s

" 

J 60 

| 40 

° 20 

0 

7/2/2001 

Other 

10/1/2001 

1/1/2001 4/2/2001 7/2/2001 10/1/2001 

1365 Operating Hours November 1 - December 31 

:

" ' • ;T

: :

 -~" • : 

3-6 Minute Averages: 0.02% Operating Time 

- -

_. • - ; 27% Opacity 

- : 

i i 

• o o -

12/31/2001 

- ; - J-; - -

• * 

0-6 Minute Averages: 0.00% Operating Time 

I 

- : 27% Opacity : z : • 

12/31/2001 

: 0-6 Minute Averages: 0.00% Operating Time 

~

 :"~ ^ 

- : ; 27% Opacity

 :: : 

1 1 

12/31/2001 

i 

2 - 6 Minute Averages: 0.015% Operating Time ... 1 

27% Opacity ;;;; 

I \ 

! O 

12/31/2001 
GE-Lynn, MA - Boiler #3 

2002 - 6 Minute Averages > 15% Opacity 

Soot Blowing 

100 

Co 80 

o"-

J 60 

co 40 

Q. 

o 

20 

0 

1/1/2002 

100 

80 : 

60 

s.

 4 0 

° 20 

0 1/1/2002 

100 

V P 80 

o^ 

60 

'o 

CD 40 

Q. 

o 20 

0 

1/1/2002 

100 

80 : 

£

 6 0 

I 40 

° 20 

0 

T 

. o 

_ .. o 

4/2/2002 

4/2/2002 

4/2/2002 

1' o o 

1/1/2002 4/2/2002 

8107 Operating Hours 

* 

:'.. . ::. .. 131 - 6 Minute Averages: 0.16% Operating Time 

: 

. „ . , „ . ; 

:

 j . ^ • 

- - ' - • !" " -

?7% Opacity . - c 

o —• 0 

o -o 8>ooc^- ...<$5>..-, O. . i 

- i 

7/2/2002 

Start Up 

10/1/2002 12/31/2002 

i ~:...:..TM:L----:.—•:::T:-:- Z.-~-.Z * t 

21 -6 Minute Averages: 0.025% Operating Time 

- ' I 

. o 27% Opacity

 1 

8 

- 8 ..." i ; j o 

o e 

I " i 

7/2/2002 

Shut Down 

10/1/2002 12/31/2002 

3-6 Minute Averages: 0.004% Operating Time 

27% Opacity 

7/2/2002 

Other 

10/1/2002 12/31/2002 

71 - 6 Minute Averages: 0.09% Operating Time 

27% Opacity 

7/2/2002 10/1/2002 12/31/2002 
100 

Co 80 

J 60 

« 40 

° 20 

0 

1/1/2003 

100 

Co 80 

o"~ 

& 60 

a 40 

° 20 

0 

1/1/2003 

100 

Co 80 

& 60 

co 40 

Q. 

o 20 

0 

1/1/2003 

100 

Co 80 

o^-

^ 60 

a

 4 0 

° 20 

0 

GE-Lynn, MA - Boiler #3 

2003 - 6 Minute Averages > 15% Opacity 

Soot Blowing 

6 Minute Averages: 0.0 2% Operating Time :. 

_, , . . 

::::::z.:zp:.... 14- 6 Minute Averages: 0.0 2% Operating Time :. 

:

 i „ . 

- - ••-

97% Dpar.ity 

? 

- : o % & & > i , 

4/2/2003 7/2/2003 

Start Up 

10/1/2003 12/31/2003 

* i 

_ 

:.::/ ; _ 12 • 6 Minute Averages: 0.02% Operating Time 

: ": ./. 

o ; { 

- • " ~; " D; ;_'/-_' ~'; 9 7% Opacity i

 ; 

- y 

» 

4/2/2003 7/2/2003 

Shut Down 

10/1/2003 12/31/2003 

4 - 6 Minute Averages: 0.006% Operating Time 

27% Opacity 

4/2/2003 7/2/2003 

Other 

10/1/2003 12/31/2003 

20 - 6 Minute Averages: 0.03% Operating Time 

27% Opacity 

1/1/2003 4/2/2003 7/2/2003 

6532 Operating Hours Thru November 13 

10/1/2003 12/31/2003 
GE-Lynn, MA-Boiler #5 

2001 - 6 Minute Averages > 15% Opacity 

Soot Blowing 

'o 

CO 

Q. 

O 

100 

80 

60 

40 

20 

0 

1/1/2001 

0-6 Minute Averages 

27% Opacity 

i i 

4/2/2001 

O 

CO 

CL 

O 

100 

80 

60 

40 

20 

0 

1/1/2001 4/2/2001 

'o 

CO 

Q. 

O 

100 

80 

60 

40 

20 

0 

1/1/2001 4/2/2001 

cr-

'o 

CD 

CL 

O 

100 

80 

60 

40 

20 

0 - 6 Minute Averages 

7/2/2001 

Start Up 

10/1/2001 12/31/2001 

: 0-6 Minute Averages \ 

: 

- • 97% Opacity 

i 

f i ; - . '"".]-. : 

7/2/2001 

Shut Down 

10/1/2001 12/31/2001 

; 0-6 Minute Averages 

- r -

::: :

 zz.'zzr~::.zzi"i. 

- • • 

°7°/L Omritv 

r- ? 

-

i i 

7/2/2001 

Other 

10/1/2001 12/31/2001 

27% Opacity 

0 

1/1/2001 4/2/2001 7/2/2001 

0 Operating Hours November 1 - December 31 

10/1/2001 12/31/2001 
100 

Co 80 

^ 60 

<-> 

cl

 4 0 

° 20 

0 

1/1/2002 

100 

Co 80 

o^ 

J 60 

co 40 

° 20 

0 1/1/2002 

100 

Co 80 

o^ 

& 60 

co 40 

° 20 

0 1/1/2002 

100 

80 

o^ 

>. 

•I— ' 

60 

"o 

CO 40 

CL 

o 20 

0 

GE-Lynn, MA - Boiler #5 

2002 - 6 Minute Averages > 15% Opacity 

Soot Blowing 

4/2/2002 

4/2/2002 

4/2/2002 

123-6 Minute Averages: 1.6% Operating Time 

27% Opacity 

7/2/2002 

Start Up 

10/1/2002 12/31/2002 

• •.::;:::';;-;:i:yj.::7: ^ 

-r:. -

59 -6 Minute Averages: 0.75% Operating Time 

; • " 

0 ?7% Opacity 

i . o 

§ 

„ - •• 1 

i i 

o« i 

7/2/2002 

Shut Down 

10/1/2002 12/31/2002 

-

| : -

- ; " - - ' 5-6 Minute Averages: 0.06% Operating Time 

- : 

Z .. .". .6." 1. 

2/% Opacity 

_ 0 

i i 

o o 

"i i 

7/2/2002 

Other 

10/1/2002 12/31/2002 

-

6 Minute Averages: 0.55% Operating Time 1 ; 43- 6 Minute Averages: 0.55% Operating Time 

; ?7% Opacity 

a ft 

a * 

i i i i 1 1 

1 

1/1/2002 4/2/2002 7/2/2002 10/1/2002 12/31/2002 

785 Operating Hours 
GE - Lynn, MA - Boiler #5 

2003 - 6 Minute Averages > 15% Opacity 

Soot Blowing 

100 

Co 80 

& 60 

co 40 o. 

O 

34-6 Minute Averages: 0.26% Operating Time 

27% Opacity 

20 

0 

1/1/2003 

100 

4/2/2003 7/2/2003 

Start Up 

10/1/2003 

Co 80 

o ^ 

J 60 

co 40 

° 20 

0 

Z. 13-6 Minute Averages: 0.1% Operating Time 

27% Opacity 

1/1/2003 4/2/2003 7/2/2003 

Shut Down 

10/1/2003 

100 

CP 80 

o~» 

'o 

CO 

CL 

o 

2 - 6 Minute Averages: 0.015% Operating Time 

40 

20 

27% Opacity 

0 

1/1/2003 4/2/2003 7/2/2003 

Other 

10/1/2003 

100 

80 : 

^ 60 \ 

co 40 

° 20 

0 

1/1/2003 4/2/2003 7/2/2003 

1317 Operating Hours Thru November 13 

10/1/2003 

12/31/2003 

12/31/2003 

12/31/2003 

0 0 - R Minut e AvpranPR- 0 17 % Onpratin n Tim<=>

 + t 

•" * o 

: 27% Opacity 

? 

- j 

12/31/2003 
Attachment 3 

Combustion Components Associates, Inc. 

Letter Re: Proposed 310 CMR 7.06(l)(c) 

26 
COMBUSTION COMPONENTS ASSOCIATES, INC. 

884 Main Street, Monroe, Connecticut 06468 

TEL: (203) 268-3139 FAX: (203) 261-7697 EMAIL: MAIL@CCA-INC.NET 

February 4, 2004 

TO: Bill Currier 

FROM: John Hurley/John Dale 

SUBJECT: Proposed Amendments To Regulations 310 CMR 7.00 (Specifically 

7.06(l)(c)) 

COPY: Bob Machaver 

The amendments proposed to CMR 7.06 (1) (c) are for the most part consistent with the 

work that CCA has done for you at the GE Lynn facility. The one exception that we did 

note was the firm maximum limit of 27% for any operational situation. Based on our 

experience, it will be difficult, if not impossible, for any facility firing heavy oil to have 

an operating scenario where 27% will never be exceeded for a six-minute average. 

Anything that substantially upsets the boiler thermal stability or combustion 

stiochiometry can cause brief periods of opacity excursions. During steady state boiler 

operation, and even during typical startup and shutdown events, the 7.06(1 )(c) proposed 

opacity limits should be achievable for the GE boilers. There will likely be times 

however that unanticipated, unusual, or atypical conditions arise at startup and shutdown 

and other transient firing periods which upset the combustion process and result in brief 

opacity spikes above the 27% ceiling. These occurrences can happen and not necessarily 

be associated with equipment malfunction or improper operating practices. We are not 

saying that 100% compliance with the proposed amendments is impossible, just that it 

will be highly unlikely. In our proposed limits to you, we suggest having annual limits 

where several 6-minute opacity averages beyond 27% would be allowed to address these 

issues for 100% compliance. If these special instances are not allowed, we still feel 

compliance will be exceptionally high. Should you want to discuss these concerns in 

more detail, let us know.