Oklahoma OAC 252 Chapter 100. Air Pollution Control, Subchapter 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, SIP effective September 3, 2019 (OKd27)
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] Adobe file pages 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] Adobe file 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 September 3, 2019 (OKd27)***OK028***z8t***
***end OAC 252:100-31, Part 5, SIP effective September 3, 2019 (OKd27)***OK028***