DEPARTMENT OF ENVIRONMENTAL QUALITY

AIR QUALITY DIVISION

AIR POLLUTION CONTROL

(By authority conferred on the director of the department of environmental quality by

sections 5503 and 5512 of the natural resources and environmental protection act, 1994 PA

451, MCL 324.5503 and 324.5512)

PART 4. EMISSION LIMITATIONS AND PROHIBITIONS—SULFUR

BEARING COMPOUNDS

R 336.1401 Emission of sulfur dioxide from power plants.

Rule 401. (1) In a power plant, it is unlawful for a person to burn fuel that does not comply

with the sulfur content limitation of table 41 or which, when burned, results in sulfur

dioxide (SO₂) emissions exceeding an equivalent emission rate as shown in table 41. In a

power plant located in Wayne county, it is unlawful for a person to burn fuel that does not

comply with the sulfur content limitation of table 42 and unlawful to cause or permit a

discharge into the atmosphere from fuel-burning equipment SO₂in excess of the SO₂

concentration limit shown in table 42.

(2) Tables 41 and 42 read as follows:

TABLE 41

Fuel and SO₂Emission Limitations for Power Plants

Maximum

Average

Sulfur

Equivalent Emission Rates

Parts per Million by Volume Pounds of SO₂per

Plant Capacity^(a)

(ppmv) Corrected to 50%

Million Btu of Heat Input

(e)

Excess Air^(e)

Content in

Fuel^{(b, e)}

Solid Fuel^(c)Liquid Fuel^(d)Solid

Liquid

Fuel^(d)

(18,000

Btu/lb)

(Percent

by weight)

(12,000

Btu/lb)

(18,000

Btu/lb)

Fuel^(c)

(12,000

Btu/lb)

0-500,000 lbs Steam

per Hour Plant

Capacity

Greater than 500,000

lbs Steam per Hour

Plant Capacity

1.5

1.0

890

630

2.5

1.67

590

420

1.67

1.11

(a) The total steam production capacity of all coal- and oil-burning equipment in a power plant as

of August 17, 1971.

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(b) "Maximum average sulfur content in fuel" means the average sulfur content in all fuels burned

at any 1 time in a power plant. The sulfur content shall be calculated on the basis of 12,000 Btu

per pound for solid fuels and 18,000 Btu per pound for liquid fuels.

(c) Solid fuels include both pulverized coal and all other coal.

(d) Liquid fuels include distillate oil (No. 1 and No. 2), heavy oil (No. 4, No. 5, and No. 6), and

crude oil.

(e) A person shall sample, analyze, calculate, and record for each day of operation for each unit at

the power plant, the sulfur content of the fuel combusted or the fuel’s equivalent SO₂emission rate

in accordance with as-fired fuel sampling and analysis procedures found in appendix A of 40 CFR

part 60; in particular the “Standard Test Methods for Sulfur in Petroleum Products:” ASTM D129,

D1266, or D1552 and the “Standard Test Methods for Total Sulfur in the Analysis of Coal and

Coke:” ASTM D3177 or D4239; as referenced in 40 CFR 60.17, adopted by reference in R

336.1902. Records must be kept, including the identification of the power plant, days of operation,

and maximum sulfur content of fuel combusted for each day of operation. Records must be

maintained on site for 5 years and submitted to the department upon written request.

TABLE 42

Fuel and SO₂Concentration Limitations for Power Plants Located in Wayne County

Maximum Weight Percent

SO₂ppmv Emission Rates

Fuel Type

Sulfur Content in Fuel^{(a & b)}

Corrected to 50% Excess Air ^(b)

Limitations for Fuel-Burning

Equipment

1.00

Pulverized Coal

Other Coal

Distillate Oil Nos. 1 & 2

Used Oil

Crude and Heavy Oil

Nos. 4, 5, & 6

550

420

120

300

400

0.75

0.30

1.00

(a) “Maximum weight percent sulfur content in fuel" means the maximum weight percent sulfur

content in all fuels burned at any 1 time in a power plant.

(b) A person shall sample, analyze, calculate, and record for each day of operation for each unit

at the power plant, the sulfur content of the fuel combusted and the fuel’s equivalent SO₂

emission rate in accordance with as-fired fuel sampling and analysis procedures found in

appendix A of 40 CFR part 60; in particular the “Standard Test Methods for Sulfur in Petroleum

Products:” ASTM D129, D1266, or D1552 and the “Standard Test Methods for Total Sulfur in

the Analysis of Coal and Coke:” ASTM D3177 or D4239; as referenced in 40 CFR 60.17,

adopted by reference in R 336.1902. Records must be kept, including the identification of the

power plant, days of operation, and maximum sulfur content of fuel combusted for each day of

operation. Records must be maintained on site for 5 years and submitted to the department

upon written request.

(3) The following provisions apply to persons in Wayne county:

(a) The maximum weight percent sulfur content in fuel limitations for fuel-burning

equipment provisions of table 42 of this rule do not apply to any person who uses a

combination of fuels in such ratios as to meet the SO₂concentration limitations specified

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in table 42 and has obtained written approval from the department for this exemption. The

allowable concentration limit will be based on the value in the table for the fuel having the

higher allowable concentration limit.

(b) The maximum weight percent sulfur content in fuel limitations for fuel-burning

equipment provisions of table 42 of this rule do not apply to any person who has received

an installation permit from the department for a control device to desulfurize the stack

gases if the control device is installed and operating properly.

(4) Instead of conducting daily as-fired fuel sampling and analysis pursuant to subrule (2)

of this rule, a person at any power plant equipped with a SO₂continuous emissions

monitoring system (CEMS) may compute and record the daily equivalent emission rates

as determined by the SO₂CEMS. The SO₂CEMS must be calibrated, maintained, and

operated in accordance with the procedures in 40 CFR 60.13(d), (e), (f), and (h) and in

performance specification 2, appendix B of 40 CFR part 60 or 40 CFR part 75 excluding

the data substitution outlined in subpart D, adopted by reference in R 336.1902. Records

must be maintained on site for 5 years and submitted to the department upon written

request.

History: 1980 AACS; 2002 AACS; 2008 AACS 2013 AACS; 2019 AACS.

R 336.1401a Definitions.

Rule 401a. As used in this part:

(a) "Power plant" means a single structure devoted to steam or electric generation, or both,

and may contain multiple boilers.

(b) “Sulfur recovery plant” means any plant that recovers elemental sulfur from any gas

stream.

History: 2008 AACS 2013 AACS; 2019 AACS.

R 336.1402 Emission of SO₂from fuel-burning equipment at a stationary source

other than power plants.

Rule 402. (1) For fuel burning equipment at a stationary source other than a power plant

it is unlawful for a person to cause or allow the emission of SO₂from the combustion of

any coal or oil fuel in excess of 1.7 pounds per million Btu of heat input for oil fuel or in

excess of 2.4 pounds per million Btu of heat input for coal fuel.

(2) The provisions of subrule (1) of this rule do not apply to fuel-burning equipment at a

stationary source that is unable to comply with the specified emission limits because of

SO₂emissions caused by the presence of sulfur in other raw materials charged to the fuel-

burning equipment. This exception applies if at any time the actual SO₂emission rate

exceeds the expected theoretical SO₂emission rate from fuel burning. The expected

theoretical SO₂emission rate must be based on the quantity of fuel burned and the average

sulfur content of the fuel.

(3) For fuel burning equipment at a stationary source located in Wayne county other than

a power plant, it is unlawful for a person to burn fuel that does not comply with the sulfur

content limitation of table 43 and unlawful to cause or allow a discharge into the

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atmosphere from fuel burning equipment SO₂in excess of the SO₂concentration limit

shown in table 43.

(4) Table 43 reads as follows:

Table 43

Fuel and SO₂Concentration Limitations for Fuel Burning Equipment^(c)at a Stationary

Source Located in Wayne County Other than a Power Plant

Maximum Weight Percent SO₂ppmv Emission Rates

Fuel Type

Sulfur Content in Fuel^{(a, b)}Corrected to 50%

Limitations for Fuel-

Burning Equipment

0.75

ExcessAir^b

Coal

420

120

Distillate Oil Nos. 1

& 2

0.30

Used Oil

Crude and Heavy Oil

Nos. 4, 5, & 6

1.0

1.00

300

400

(a) The determination of sulfur content (percent by weight) of fuel shall be carried

out in accordance with the “Standard Test Methods for Sulfur in Petroleum

Products:” ASTM D129, D1266, or D1552 and the “Standard Test Methods for

Total Sulfur in the Analysis of Coal and Coke:” ASTM D3177 or D4239; as

referenced in 40 C.F.R. 60.17, adopted by reference in R 336.1902.

(b) Records must be kept, including the identification of the fuel burning equipment,

days of operation, and maximum sulfur content of fuel combusted for each day of

operation. Records must be maintained on site for 5 years and submitted to the

department upon written request.

(c) For table 43, fuel burning equipment includes residential and commercial space

and water heating. The maximum weight percent sulfur content in fuel and SO₂

ppmv emission rate limitations for distillate, crude, and heavy oils listed above also

apply to these units.

(5) The following provisions apply to persons in Wayne county:

(a) The maximum weight percent sulfur content in fuel limitations for fuel-burning

equipment provisions of table 43 of this rule do not apply to a person who uses a

combination of fuels in such ratios as to meet the SO₂concentration limitations specified

in table 43 and has obtained written approval from the department for this exemption. The

allowable concentration limit will be based on the value in the table for the fuel having the

higher allowable concentration limit.

(b) The maximum weight percent sulfur content in fuel limitations for fuel-burning

equipment provisions of table 43 of this rule do not apply to a person who has received an

installation permit from the department for a control device to desulfurize the stack gases

if the control device is installed and operating properly.

History: 1980 AACS; 2008 AACS 2013 AACS; 2019 AACS.

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R 336.1403 Oil- and natural gas-producing or transporting facilities and natural gas-

processing facilities; emissions; operation.

Rule 403. (1) Except as provided in subrule (3) of this rule, it is unlawful for a person to

cause or allow the emission of sour gas from an oil- or natural gas-producing or

transporting facility or a natural gas- processing facility without burning or equivalent

control of hydrogen sulfide and mercaptans.

(2) Except as provided in subrule (3) of this rule, sour gas that is burned at an oil- or natural

gas-producing or transporting facility or at a natural gas-processing facility shall be burned

in a properly engineered flare, incinerator, or other combustion system with elevated

discharge to the atmosphere. If the flare, incinerator, or other combustion system burns

sour gas in such volume and with such hydrogen sulfide concentration that the daily

quantity of hydrogen sulfide in the gas is less than 28 pounds, then it shall be equipped

with either a pilot flame which will burn continuously when gas flows to the flare,

incinerator, or other combustion system or with an automatic ignition system, unless

otherwise authorized by the department. If the flare, incinerator, or other combustion

system burns sour gas in such volume and with such hydrogen sulfide concentration that

the daily quantity of hydrogen sulfide in the gas is 28 pounds or more, then it shall be

equipped with a continuously burning pilot flame and a mechanism which will operate,

upon failure of the pilot flame, to shut off the flow of gas, unless otherwise authorized by

the department.

(3) The provisions of subrules (1) and (2) of this rule do not apply to either of the

following:

(a) Crude oil-producing facilities that serve a well or group of wells which attained an

average production level of 10 or less barrels per day per well before January 1, 1978,

unless the department has received 1 complaint of odors regarding the facility, and the

owner or operator is unable to or fails to demonstrate, to the satisfaction of the department,

that the uncontrolled hydrogen sulfide and mercaptan emissions do not cause an odor

nuisance or health hazard.

(b) A vessel or a battery of vessels that releases a total daily volume of vapors of less than

5,000 standard cubic feet, if the owner or operator demonstrates both of the following:

(i) Combustion of the vapors is not economically reasonable.

(ii) The uncontrolled release of the vapors will not cause a violation of the provisions of

R 336.1901.

(4) A person shall not cause or allow the emission of sulfur dioxide from a new sweetening

facility, unless such emissions are controlled using the best available control technology.

(5) The operator of a sour gas-, crude-, or condensate-sweetening facility-ty shall do all of

the following:

(a) Monitor the mass flow rate of hydrogen sulfide either entering the plant or going to the

waste gas flare or flares on a periodic schedule specified by the department. The

monitoring program shall include a determination of the hydrogen sulfide concentration

using colorimetric detector tubes or their equivalent and a determination of the volumetric

gas flow rate. The monitoring data shall be submitted to the department in an acceptable

format within 30 days following the end of the month in which the data were collected.

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(b) Provide fencing, warning signs, or other measures as necessary to warn or deter

unauthorized individuals from entering the plant property or buildings. Signs shall read:

"Danger--Poison Gas," with at least 1 sign on each side of the plant property.

(c) Provide control of malodorous emissions from any pressure relief valve or valves,

storage tanks, and dehydrator vent or vents by burning or equivalent control.

(d) Conduct a program of continuous monitoring of concentrations of hydrogen sulfide in

any building enclosing a sweetening process. The sensor shall be placed as close to process

equipment as practicable. The system shall be designed, installed, and maintained to

provide a visual alarm when the hydrogen sulfide concentration is more than 50 ppm.

(e) Automatically begin a safe and orderly shutdown of all process inflow streams to the

facility if the concentration of hydrogen sulfide is more than 100 ppm in any building

enclosing a sweetening process. Full operation may be resumed only after successful

corrective measures have been applied.

(f) Automatically commence shut-in of the facility within 1 second after extinguishment

of the flare flame, unless otherwise authorized by the department. Operation of the facility

shall not continue unless corrective measures taken to reignite the flame are successful.

(6) A new sweetening facility shall not be installed at a distance of less than 1,300 feet

from an existing residence, unless otherwise authorized by the department. Such

authorization shall depend upon a satisfactory showing by a permit applicant that an odor

nuisance shall not result from a lesser setback distance.

History: 1980 AACS; 1989 AACS; 2002 AACS.

R 336.1404 Emission of SO₂and sulfuric acid mist from sulfuric acid plants.

Rule 404. (1) It is unlawful for a person to cause or allow the emission of sulfuric acid mist

from any sulfuric acid plant in excess of 0.50 pounds per ton of acid produced, the

production being expressed as 100% sulfuric acid.

(2) It is unlawful for a person in Wayne county to cause or allow SO₂emissions into the

atmosphere from any sulfuric acid plant to exceed 6.5 pounds per ton of acid produced.

(3) Compliance with this rule must be demonstrated using 40 CFR part 60, appendix A,

reference test method no. 8, adopted by reference in R 336.1902.

History: 1980 AACS; 2008 AACS 2013 AACS; 2019 AACS.

R 336.1405 Emissions from sulfur recovery plants located within Wayne county.

Rule 405. At sulfur recovery plants located in Wayne county, a person shall not cause or

allow the emission into the atmosphere of sulfur dioxide, sulfur trioxide, or sulfuric acid

from any such sulfur recovery plant to exceed 0.01 pounds per pound of sulfur produced.

History: 2008 AACS.

R 336.1406 Hydrogen sulfide emissions from facilities located within Wayne county.

Rule 406. (1) A person in Wayne county shall not cause or allow the combustion of any

refinery process gas stream that contains hydrogen sulfide in a concentration of greater

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than 100 grains per 100 cubic feet of gas without removal of the hydrogen sulfide in excess

of this concentration.

(2) When the odor of hydrogen sulfide is found to exist beyond the property line of a

source, a person in Wayne county shall not cause or allow the concentration of hydrogen

sulfide to exceed 0.005 parts per million by volume for a maximum period of 2 minutes.

History: 2008 AACS.

R 336.1407. Sulfur compound emissions from sources located within Wayne county

and not previously specified.

Rule 407. Both of the following apply to process and fuel burning equipment at a

stationary source located within Wayne county to which the provisions of R 336.1401 to

R 336.1406 do not apply.

(a) A person shall not cause or allow the emission into the atmosphere gases with a

concentration of SO₂greater than 300 parts per million by volume, which shall be corrected

to 50% excess air.

(b) A person shall not cause or allow the emission into the atmosphere gases with a

concentration of sulfuric acid or sulfur trioxide or a combination thereof greater than 15

milligrams per cubic meter, which shall be corrected to 50% excess air.

History: 2008 AACS; 2013 AACS.

R 336.1420 Rescinded.

History: 2008 AACS; 2013 AACS; 2019 AACS.

R 336.1430 Emission of SO₂from United States Steel, Great Lakes Works.

Rule 430. (1) The provisions in this rule supersede the requirements of R 336.1407 that

apply to United States Steel, Great Lakes Works reheat furnaces and Zug Island boilers as

referenced in subrules (2) and (3) of this rule.

(2) All of the following apply to United States Steel, Great Lakes Works, 80” hot strip

mill reheat furnaces:

(a) On and after December 31, 2016, the combined SO₂emission rate from the 5 reheat

furnaces shall not exceed 148 pounds per hour, based on a 1-hour average starting on the

hour for each clock-hour.

(b) On and after December 31, 2016, the company shall install, calibrate, maintain, and

operate in a manner approved by the department devices to separately monitor and record

the coke oven gas and natural gas usage rates, in cubic feet per hour, for the 5 reheat

furnaces combined for each hour of operation. The 5 furnaces shall be equipped with a

common coke oven gas usage meter and a common natural gas usage meter. The company

shall keep the usage rate records on file at the facility for a period of 5 years, in a format

acceptable to the department, and make them available to the department upon request.

(c) On and after December 31, 2016, the company shall compile hourly SO₂emission

rate calculations for the 5 reheat furnaces combined in pounds per hour, for each hour of

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operation. Emission rates shall be determined using the method specified in subrule (3)(g)

of this rule. The company shall keep the records of the calculations on file at the facility

for a period of 5 years, in a format acceptable to the department, and make them available

to the department upon request.

(d) Not later than June 30, 2017, the company shall conduct SO₂emission stack tests of

the reheat furnaces, based on testing of a representative furnace. Not less than 30 days

before testing, a complete stack test protocol shall be submitted to the department for

approval. The final plan must be approved by the department before testing. Verification

of emission rates includes the submittal of a complete report of the test results to the

department within 60 days following the last date of the test. The company shall keep the

records of the test on file at the facility for a period of 5 years, in a format acceptable to the

department, and make them available to the department upon request.

(e) On and after September 15, 2017, the company shall submit an excess emission report

in an acceptable format to the department semiannually. The report shall be submitted by

September 15 for the January 1 to June 30 reporting period, and by March 15 for the July

1 to December 31 reporting period. The excess emission report shall include the following

information:

(A) A report of each exceedance above the SO₂limitation including the date, time,

magnitude, cause, and corrective actions for all occurrences during the reporting period.

(B) A report of all periods of fuel gas usage rate monitoring system downtime and

corrective action.

(C) If no SO₂limitation exceedance and no fuel gas usage rate monitoring system

downtime occurred during the reporting period, the company shall report that fact.

(3) All of the following apply to United States Steel, Great Lakes Works, Zug Island

boiler houses number 1 and 2:

(a) The following limits shall be met on and after December 31, 2016:

(i) The combined SO₂emission rate from the number 1 boiler house boilers 1 to 5 shall

not exceed 15 pounds per hour, based on a 1-hour average starting on the hour for each

clock-hour.

(ii) The combined SO₂emission rate from the number 2 boiler house boilers 1 to 5 shall

not exceed 21 pounds per hour, based on a 1-hour average starting on the hour for each

clock-hour.

(iii) The maximum hydrogen sulfide content of the blast furnace gas fired in the boilers

shall not exceed .0274 grains per dry standard cubic foot, based on a 1-hour average starting

on the hour for each clock-hour.

(b) The type of fuels burned in the boilers shall be restricted to blast furnace gas, coke

oven gas, and natural gas.

(c) On and after December 31, 2016, the company shall install, calibrate, maintain, and

operate in a manner approved by the department devices to separately monitor and record

the coke oven gas, blast furnace gas, and natural gas usage rates in cubic feet per hour for

the combined number 1 boiler house boilers and for the combined number 2 boiler house

boilers for each hour of operation. The company shall keep the usage rate records on file

at the facility for a period of 5 years, in a format acceptable to the department, and make

them available to the department upon request.

(d) On and after December 31, 2016, the company shall install, calibrate, maintain, and

operate in a manner approved by the department devices to monitor and record the blast

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furnace gas hydrogen sulfide content in grains per cubic foot for the blast furnace gas fired

in the number 1 boiler house boilers 1 to 5 and in the number 2 boiler house boilers 1 to 5

on a continuous basis to determine the 1-hour average hydrogen sulfide concentration in

the blast furnace gas for each hour of operation. The company shall keep the records of

the hydrogen sulfide content on file at the facility for a period of 5 years, in a format

acceptable to the department, and make them available to the department upon request.

(e) On and after December 31, 2016, the company shall compile hourly SO₂emission

rate calculations separately for the combined number 1 boiler house boilers 1 to 5 and for

the combined number 2 boiler house boilers 1 to 5 for each hour of operation. Emission

rates shall be determined using the method specified in subdivision (g) of the subrule. The

company shall keep the calculation records on file at the facility, for a period of 5 years, in

a format acceptable to the department, and make them available to the department upon

request.

(f) On and after September 15, 2017, the company shall submit an excess emission report

in an acceptable format to the department semiannually. The report shall be submitted by

September 15 for the January 1 to June 30 reporting period, and by March 15 for the

July 1 to December 31 reporting period. The excess emission report shall include the

following information:

(i) A report of each exceedance above the SO₂and/or hydrogen sulfide limitations

including the date, time, magnitude, cause, and corrective actions for all occurrences during

the reporting period.

(ii) A report of all periods of fuel gas usage rate monitoring system and/or fuel gas

hydrogen sulfide monitoring system downtime and corrective action.

(iii) If no SO₂and/or hydrogen sulfide limitation exceedances, no fuel gas usage rate

monitoring system downtime, or no fuel gas hydrogen sulfide monitoring system downtime

occurred during the reporting period, the company shall report that fact.

g) The company shall determine the average hourly SO₂emission rate for the group of 5

furnaces or boilers grouped as number 1 boiler house or number 2 boiler house boilers

subject to subrule (2) or (3) of this rule as specified below or by a method approved by the

department as required in subrule (4) of this rule:

HOURLY RATE (lbs SO₂/hour) = [COG (1000 ft³/hour) * (0.702 lbs SO₂/ 1000 ft³) +

BFG (ft³/hr) * H₂S (gr/ft³BFG) * (1 lb H₂S / 7,000 gr H₂S) * (1.88 lb SO₂/lb H₂S) + NG

(1,000,000 ft³/hr)* (0.6 lb SO₂/ 1,000,000 ft³)]

Where:

HOURLY RATE = boiler house group or furnace group emission rate (lbs SO₂/hour).

COG = actual volume of coke oven gas consumed (1000 ft³per clock-hour) in a furnace

group or boiler house group.

BFG = actual volume of blast furnace gas consumed (ft³per clock-hour) in a furnace group

or boiler house group.

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NG = actual volume of natural gas consumed (1,000,000 ft³per clock-hour) in a furnace

group or boiler house group.

H₂S = actual concentration of hydrogen sulfide in BFG (gr/ft³) determined on a 1-hour

average basis for each clock-hour of operation.

(h) Not later than June 30, 2017, the company shall conduct SO₂emission stack tests of

a representative boiler in number 1 boiler house and of a representative boiler in number 2

boiler house. Not less than 30 days before to testing, a complete stack test protocol must

be submitted to the department for approval. The final plan must be approved by the

department before testing. Verification of emission rates includes the submittal of a

complete report of the test results to the department within 60 days following the last date

of the test. The company shall keep the records of the test on file at the facility for a period

of 5 years, in a format acceptable to the department, and make them available to the

department upon request.

(4) The emission rate limits in subrules (2)(a) and (3)(a) of this rule, or equivalent limits

as determined by dispersion modeled SO2 impacts, may be met with several different

control methods including sulfur dioxide flue gas emission controls, blending of alternate

lower sulfur content fuels with currently used fuels, application of fuel desulfurization

control to the currently used coke oven gas and blast furnace gas, use of improved

dispersion techniques such as use of taller exhaust stacks, or a combination of these and/or

other control measures. By August 31, 2016, the company shall submit to the MDEQ for

approval the control methods, control efficiencies as appropriate, and associated testing,

recordkeeping and reporting methods that the company will use to comply with this rule.

History: 2016 AACS.

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