40 CFR 98 Subpart W Petroleum and Natural Gas Systems
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1 40 CFR 98 Subpart W Petroleum and Natural Gas Systems Overview: Onshore natural gas processing sector A. GHG emissions associated with the onshore natural gas processing sector must be reported for the following source types a) Reciprocating compressor rod packing venting; b) Centrifugal compressor venting; c) Blow-down vent stacks; d) Dehydrator vents; e) Acid gas removal vents; f) Flare stacks; g) Leaks from valves, connectors, open-ended lines, pressure relief valves and meters; h) Combustion sources B. Calculating GHG Emissions a) Reciprocating compressor rod packing venting 1) Annual emission measurements must be made for each compressor in the mode in which it is found i) Operating or standby pressurized mode isolation valve leakage through the blow-down stack; ii) Operating mode rod packing emissions; iii) Not operating, depressurized mode isolation valve leakage through the blow-down stack 2) For the not operating, depressurized mode, each compressor must be measured at least once in any three consecutive calendar years. Acoustic leak detection may be used to determine the presence of isolation valve leakage through the blow-down stack to open ended vents in this mode. 3) For configurations such that the rod packing and blow-down vent connect to an open-ended vent line, emissions are to be quantified usingi) Calibrated bagging method; ii) High volume sampler method; iii) Vane anemometer or orifice meter 4) For configurations such that the rod packing is not equipped with a vent line, emissions are to be identified using i) Optical gas imaging (to be used for all source types that are inaccessible and cannot be accessed without elevating the monitoring personnel more than 6 feet above a support surface); ii) Method 21; iii) Infrared laser beam illumination; iv) Acoustic leak detection 5) For configurations such that the rod packing is not equipped with a vent line, identified emissions are to be quantified using i) Calibrated bagging method; ii) High volume sampler method; iii) Vane anemometer or appropriate meter 6) Both operating and standby pressurized modes are to be taken into account for calculating emission rate factors for isolation valve leakage through the blow-down vent. 7) Annual emission rate factors are to be calculated utilizing collected data for all reciprocating compressors in the three modes of operation. The calculated emission rate factor is to be applied to every unit. 8) In calculating the annual emission rate factor, the emission rate factor data for the current and two preceding calendar years are to be utilized. 9) GHG emissions are to be adjusted as appropriate if the vent stream is routed to controls. 1
2 b) Wet and dry seal centrifugal compressor venting 1) Annual emission measurements must be made for each compressor in the mode in which it is found i) Operating mode isolation valve leakage through the blow-down stack; ii) Operating mode wet seal oil degassing vents; iii) Not operating, depressurized mode isolation valve leakage through the blow-down stack 2) For the not operating, depressurized mode, each compressor must be measured at least once in any three consecutive calendar years. Acoustic leak detection may be used to determine the presence of isolation valve leakage through the blow-down stack to open-ended vents in this mode. 3) For isolation valve leakage through the blow-down stack that is routed to an open-ended vent line, emission rates are to be quantified using - i) Calibrated bagging method; ii) High volume sampler method; 4) For wet seal oil degassing vents, emission rates are to be determined using a vane anemometer or flow meter. 5) Both operating and standby pressurized modes are to be taken into account for calculating emission rate factors for isolation valve leakage through the blow-down vent. 6) Annual emission rate factors are to be calculated utilizing collected data for all centrifugal compressors in the three modes of operation. The calculated emission rate factor is to be applied to every unit. 7) In calculating the annual emission rate factor, the emission rate factor data for the current and two preceding calendar years are to be utilized. 8) GHG emissions are to be adjusted as appropriate if the vent stream is routed to controls. c) Blow-down vent stacks 1) The total volume of equipment to be blown down, including piping, compressor cases, cylinders and suction/discharge bottles, and vessels, is to be estimated. 2) If the total estimated volume to be blown down is in excess of 50 scf, documentation as to the number of blow downs for each equipment type is to be maintained. 3) If the blow-down volume is less than 50 scf, reporting is not required. 4) GHG emissions are to be adjusted as appropriate if the blow-down stream is routed to a control device. d) Dehydrator vents 1) For dehys with a throughput greater than or equal to 400 MCFPD, GHG emissions can be calculated using a software program which utilizes the Peng-Robinson equation of state, including GRI GLYCalc and HYSYS. GHG emissions are to be adjusted as appropriate if the stream is routed to a control device. 2) For dehys with a throughput less than 400 MCFPD, GHG emissions can be estimated using the equation and emission factors provided in the regulation. GHG emissions are to be adjusted as appropriate if the stream is routed to a control device. e) Acid gas removal vents 1) Calculation Methodology #1 For those configurations that utilize a CEM to measure CO2 emissions, the Tier 4 Calculation Methodology as outlined in 40 CFR 98 Subpart C is to be followed. 2) Calculation Methodology #2 For those configurations that utilize a flow meter to measure the flow of the vent gas off the condenser and flash tank, the annual volume of vent gas and the composition of the vent gas are to be utilized to calculate GHG emissions. 3) Calculation Methodology #3 For those configurations not utilizing either a CEM or a flow meter, the inlet or outlet gas flow rate and the composition of the inlet and outlet gas streams can be utilized to calculate GHG emissions. 2
3 4) Calculation Methodology #4 - For those configurations not utilizing either a CEM or a flow meter, a software program which utilizes the Peng-Robinson equation of state, including HYSYS and AMINECalc, can be utilized to estimate GHG emissions. Typical operating conditions over the calendar year as determined by engineering estimate and process knowledge based on best available operating data are to be utilized. 5) If a continuous gas analyzer is installed on either the inlet or outlet stream, data from the same is to be used in calculating GHG emissions. If not available, a gas analysis is to be performed quarterly on the inlet and outlet streams. Pipeline quality specifications for CO2 can be utilized as the outlet stream concentration. 6) If a continuous flow meter is installed on either the inlet or outlet stream, data from the same is to be used in calculating GHG emissions. If not available, engineering calculations can be utilized to determine the flow. 7) If GHG emissions are captured and transferred outside the facility, reported emissions are to be adjusted accordingly. f) Flare stacks 1) If equipped, data from a continuous flow measurement device must be utilized in calculating GHG emissions. If not equipped with the same, engineering calculations based on process data, company records and best available data can be utilized to estimate flow rates. 2) If equipped, data from a continuous gas analyzer must be utilized in calculating GHG emissions. If not equipped with the same, the mole fraction of the specific GHG in the produced natural gas can be utilized. 3) If the destruction efficiency of the flare is unknown, the regulation allows for the assuming of 98%. 4) Both combusted and non-combusted GHG emissions are to be calculated. g) Leaks from valves, connectors, open-ended lines, pressure relief valves and meters 1) Applicable to sources in which the composition of the gas stream is greater than 10% methane plus CO2 by weight and tubing diameters greater than ½ in diameter. 2) Leak detection surveys are to be completed utilizing the following methods i) Optical gas imaging (to be used for all source types that are inaccessible and cannot be accessed without elevating the monitoring personnel more than 6 feet above a support surface); ii) Method 21; iii) Infrared laser beam illumination; iv) Acoustic leak detection 3) The number of leak detection surveys depicted in the GHG monitoring plan must be conducted during the calendar year. 4) Appropriate default leak detection factors as listed in Table W-2 of 40 CFR 98 Subpart W are to be utilized in estimating GHG emissions. h) Combustion Sources 1) Utilize the methodology, as applicable in 40 CFR 98 Subpart C. C. Data Monitoring and QA/AC Requirements a) Best available monitoring methods for specified activities 1) Use of best available monitoring methods, including a) supplier data; b) engineering calculations; c) other company records; or, d) monitoring methods currently used by the facility but not meeting the specifications of the regulation, during the period of January 1, 2011 through December 31, 2011 may be requested for the following - 3
4 i) Leak detection and repair for a) Reciprocating compressor rod packing venting; b) Centrifugal compressor wet seal degassing venting; c) Equipment leaks from valves, connectors, open-ended lines, pressure relief valves and meters 2) Requests for use of the best available monitoring methods must be filed by April 30, D. Data reporting requirements a) Reciprocating compressors 1) Rod packing venting in operating mode - i) Compressor total annual operating time; ii) Annual throughput in MMSCF, using an engineering calculation; iii) GHG emissions for compressors measured and compressors not measured 2) Blow-down vents not manifold to rod packing vents in both operating and standby pressurized modes i) Total time in hours each compressor is in standby pressurized mode; ii) Emission factor in cubic feet/hr; iii) Emissions in operating and standby pressurized modes 3) Isolation valve in not operating and depressurized mode i) Total time in hours each compressor is not operating and depressurized mode; ii) Emission factor for isolation valve emissions in not operating and depressurized in cubic feet/hr; iii) GHG emissions in not operating and depressurized mode 4) Total annual compressor GHG emissions for all modes of operation, collectively b) Centrifugal compressors 1) Wet seals degassing vent in operating mode i) Number of wet seals connected to the degassing unit; ii) Fraction of vent gas recovered for fuel or sales or flared; iii) Annual throughput in MMSCF, using an engineering calculation; iv) Types of meters used for making measurement; v) Emission factor for wet seal degassing in cubic feet/hr; vi) Total operating time of each compressor; vii) GHG emissions for compressors measured and compressors not measured 2) Blow-down vent in operating mode i) Total operating time of each compressor; ii) Emission factor for blow-down vents in cubic feet/hr; iii) GHG emissions in operating mode 3) Isolation valve in not operating and depressurized mode i) Total hours for each compressor in not operating and depressurized mode; ii) Emission factor for isolation valve in cubic feet/hr; iii) GHG emissions in not operating and depressurized mode 4) Total annual compressor GHG emissions for all modes of operation, collectively c) Blow-down vent stacks 1) Total number of blow-downs per equipment type per year; 2) Emissions per equipment type, collectively 4
5 d) Dehys with a throughput greater than or equal to 400 MCFPD 1) Natural gas throughput rate in MMSCFPD for each dehy; 2) Type of glycol circulation pump for each dehy; 3) Whether stripping gas is used for each dehy; 4) Whether a flash tank is used for each dehy; 5) Type of absorbent for each dehy; 6) Total operating time of each dehy in hours; 7) Temperature and pressure of inlet gas stream for each dehy; 8) Concentration of methane and CO 2 in inlet gas stream for each dehy; 9) Type of controls employed, if applicable, for each dehy; 10) GHG emissions vented to atmosphere for each dehy; 11) GHG emissions vented to controls for each dehy; e) Dehys with a throughput less than 400 MCFPD 1) Count of dehys with a throughput less than 400 MCFPD; 2) Whether controls were used; 3) GHG emissions, collectively, for all dehys having a throughput less than 400 MCFPD f) Acid gas removal vents 1) Total annual natural gas throughput in MMSCF; 2) For Calculation Methodologies #1 and 2, CO2 content in the vent gas from the condenser and flash tank; 3) For Calculation Methodology #3, the CO2 content of the inlet and outlet gas stream; 4) Report GHG emissions for each unit, separately; 5) GHG emissions recovered and transferred outside of facility g) Flare stacks 1) Presence of a continuous flow meter and composition analyzer for each flare 2) Volume of gas sent to each flare in ft 3 /yr using best available data 3) Estimated percent of gas sent to each flare when the pilot is not lit 4) Assumed combustion efficiency 5) GHG emissions, combusted and not combusted, for each flare h) Leaks from valves, connectors, open-ended lines, pressure relief valves and meters 1) Total count of leaks listed by date of survey and type of leak source as defined in Table W-2; 2) Concentration of methane and CO2; 3) Report methane and CO2 emissions by equipment type, collectively i) Combustion sources 1) Unit ID number; 2) Code for unit type; 3) Maximum rated heat input capacity in relevant units depending upon type of combustion source; 4) Each type of fuel combusted in the unit during the report year; 5) The methodology, ie, tier, used in the calculations; 6) The methodology start and end dates; 7) Annual CO2, methane and NO2 mass emissions for each fuel type combusted; 8) Annual biogenic CO2 mass emissions 5
6 E. Recordkeeping requirements a) The following data must be retained for five years - 1) Dates on which measurements were conducted; 2) Results of all emissions detected and measurements made; 3) Calibration reports for detection and measurement instruments; 4) Inputs and outputs of calculations or computer model runs for estimating emissions 6
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