Oklahoma OAC 252:100-31, CONTROL OF EMISSION OF SULFUR COMPOUNDS, Part 5. New Equipment Standards, SIP effective September 2, 2019 (OKd27)
Regulatory Text:
Oklahoma Administrative Code. Title 252. Department of Environmental Quality
Chapter 100. Air Pollution Control (OAC 252:100)
SUBCHAPTER 31. CONTROL OF EMISSION OF SULFUR COMPOUNDS
PART 5. NEW EQUIPMENT STANDARDS
As approved by EPA August 1, 2019 (84 FR37579), SIP effective September 3, 2019 (OKd27),
Regulations.gov docket EPA-R06-OAR-2017-0145.
Sections:
252:100-31-25. Requirements for new fuel-burning equipment, OKd27
252:100-31-26. Requirements for new petroleum and natural gas processes, OKd27
252:100-31-25. Requirements for new fuel-burning equipment, SIP effective September 3, 2019 (OKd27)
As adopted in Oklahoma Register June 17, 2013 (30 OkReg 1078) effective July 1, 2013.
Submitted to EPA February 14, 2017 (OK-58),
Regulations.gov document EPA-R06-OAR-2017-0145-0003 [OK028.03] page 504 and 432.
Approved by EPA August 1, 2019 (84 FR 37579) SIP effective September 3, 2019 (OKd27),
Regulations.gov docket EPA-R06-OAR-2017-0145 [OK028].
Any fuel-burning equipment that was not in being on or
before July 1, 1972 or that is modified after July 1, 1972 shall
comply with the following requirements.
(1) Emission limits. Emissions ofS02 attributable to
the burning of fuel by fuel-burning equipment shall meet
the following limits.
(A) Gaseous fuel. Emissions of SO2 from
combustion of natural gas or other gaseous fuel
in fuel-burning equipment shall not exceed
0.2 lb/MMBTU heat input (86 ng/J).
(B) Liquid fuel. Emissions of SO2 from combustion
of liquid fuel in fuel-burning equipment shall not
exceed 0.8 lb/MMBTU heat input (340 ng/J).
(C) Solid fuel. Emissions of SO2 from combustion
of solid fuel in fuel-burning equipment shall not
exceed 1.2 lb/MMBTU heat input (520 ng/J).
(D) Combination of fuels burned. When different
types of fuels are burned simultaneously in any
combination, emissions of SO2 shall not exceed the
applicable limit determined by proration unless a secondary
fuel is used in de minimis quantities (less than
five percent (5%) of total BTU heat input annually).
The applicable limit, in lb/MMBTU heat input, shall
be determined using the following formula, where X
is the percent of total heat input derived from gaseous
fuel, Y is the percent of total heat input derived from
liquid fuel, and Z is the percent of total heat input
derived from solid fuel:
SO2 limit = (0.2X + 0.8Y + 1.2Z)/(X + Y + Z).
(2) Averaging time. The averaging time for the emission
limits set in OAC 252:100-31-25(1) is three (3) hours
unless a solid fuel sampling and analysis method is used to
determine emission compliance. In that case the averaging
time is 24 hours.
(3) Additional requirements for sources with heat
input of 250 MMBTU/hr or more. Any fuel-burning
equipment with design heat input values of 250
MMBTU/hr or more shall comply with the following
requirements.
(A) Sulfur dioxide emissions monitoring.
(i) The owner or operator
shall install, calibrate, maintain, and operate a continuous
SO2 emissions monitoring system, except where:
(I) gaseous fuel containing less than 0.1%
by weight sulfur (0.29 gr/scf or approximately
500 ppmv at standard conditions on a dry basis)
is the only fuel burned; or
(II) a solid or liquid fuel sampling and
analysis method is used to determine SO2 emission compliance.
(ii) Required emission monitoring systems shall be
installed, calibrated, maintained, and operated in
accordance with 40 CFR Part 60, Appendix B, and
40 CFR Part 51, Appendix P.
(B) Fuel monitoring. The sulfur content of solid
or liquid fuels as burned shall be determined in
accordance with methods previously approved by the
Director or in accordance with Method 19 of 40 CFR
Part 60, Appendix A.
(C) Recordkeeping. The owner or operator shall
maintain records of all measurements required in
(A) and (B) of this subsection in accordance with
the applicable requirements of OAC 252:100-43-7,
including compliance status records and excess emissions
measurements.
(4) Alternative fuel. The requirements of this section
apply to any fuel-burning equipment that uses an
alternative fuel, unless another limit representing BACT
or equivalent is specified in the source's permit. Use of
an alternative fuel in fuel-burning equipment is allowed,
provided its use is authorized under an enforceable permit.
Use of an alternative fuel in fuel-burning equipment is subject
to any applicable restrictions or prohibitions that may
exist in other provisions of state or federal statutes or rules,
e.g., OAC 252:100-8-32.1, 252:100-31-7, 252:100-42,
and/or 40 CFR Parts 60, 61, and/or 63.
**End 252:100-31-25 SIP effective 9-3-2019***OKd27***OK028***z8s***
252:100-31-26. Requirements for new petroleum and natural gas processes, SIP effective September 3, 2019 (OKd27)
As adopted in Oklahoma Register June 15, 2012 (29 OkReg 996) effective July 1, 2012,
Submitted to EPA February 14, 2017 (OK-58),
Regulations.gov document EPA-R06-OAR-2017-0145-0003 [OK028.03] page 564.
Approved by EPA August 1, 2019 (84 FR 37579) SIP effective September 3, 2019 (OKd27),
Regulations.gov docket EPA-R06-OAR-2017-0145 [OK028].
Any petroleum and natural gas process that was not in being
on or before December 31. 1974 or that is modified after
December 31. 1974 shall comply with the following requirements.
(1) Hydrogen sulfide standards and alarm systems.
(A) H2S contained in the waste
gas stream from any petroleum or natural gas
process equipment shall be reduced by 95% by removal
or by being oxidized to SO2 prior to being emitted
to the ambient air. This requirement shall not apply if
a facility's emissions of H2S do not exceed 0.3 lb/hr,
two-hour average.
(B) The owner or operator shall install maintain.
and operate an alarm system that will signal a malfunction
for all thermal devices used to control H2S emissions
from petroleum and natural gas processing
facilities regulated under this subparagraph.
(2) Oxides of sulfur. The following requirements
apply to any gas sweetening unit or petroleum refinery
process equipment with a sulfur content of greater
than 0.54 LT/D in the acid gas stream. Alternatively,
any gas sweetening unit or petroleum refinery
process equipment with an emission rate of 100 lb/hr or
less of SOx expressed as SO2, two-hour average, shall be
considered to be below this threshold.
(A) Natural gas sweetening units.
The sulfur content of any acid gas stream from any
gas sweetening unit shall be reduced by use
of a sulfur recovery unit prior to release of the
gas to the ambient air. The sulfur recovery units
shall have the recovery efficiencies required in (C)
through (F) of this subparagraph.
(B) Petroleum refinery processing. Sulfur recovery
units operating in conjunction with any refinery
process shall have the recovery efficiencies
required in (C) through (F) of this subparagraph.
(C) Sulfur content greater than 0.54
LT/D but less than or equal to 5.0 LT/D. When the
sulfur content of the acid gas stream from a gas
sweetening unit or refinery process is greater than
0.54 LT/D but less than or equal to 5.0 LT/D, the
recovery efficiency of the sulfur recovery unit
shall be at least 75%.
(D) Sulfur content greater than 5.0 LT/D
but less than or equal to 150.0 LT/D. When
the sulfur content of the acid gas stream from a
gas sweetening unit or refinery process is greater than
5.0 LT/0 but less than or equal to 150.0 LT/D, the
required recovery efficiency of the sulfur recovery
unit shall be calculated using the following formula,
where Z is the minimum sulfur recovery
efficiency required and X is the sulfur feed
rate, expressed in LT/D of sulfur and rounded to one
decimal place: Z = 92.34X0.00774.
(E) Sulfur content greater than 150.0 LT/D
but less than or equal to 1500.0 LT/D. When
the sulfur content of the acid gas stream from a
gas sweetening unit or refinery process is greater than
150.0 LT/D but less than or equal to 1500.0 LT/D, the
required recovery efficiency of the sulfur recovery unit
shall be calculated using the following formula,
where Z is the sulfur recovery efficiency required
and X is the sulfur feed rate, expressed in LT/D of sulfur
and rounded to one decimal place: Z = 88.78X0.0156.
(F) Sulfur content greater than 1500.0 LT/D.
When the sulfur content of the acid gas stream
from a gas sweetening unit or refinery process is
greater than 1500.0 LT/D, the recovery efficiency of
the sulfur recovery unit shall be at least 99.5%.
***End 252:100-31-26 SIP effective 9-3-2019***OKd27***OK028***z8t***