IDENTIFICATION AND EVALUATION OF


 OPPORTUNITIES TO REDUCE METHANE LOSSES
 

AT FOUR GAS PROCESSING PLANTS
 

Prepared For:
 

GAS TECHNOLOGY INSTITUTE
 

1700 South Mount Prospect Road 


Des Plaines, IL 60018-1804 


And 


Under USEPA Grant No: 827754-01-0 


By:
 

CLEARSTONE ENGINEERING LTD. 


200, 635 – 8th Ave. S.W.
 

Calgary, Alberta
 

T2P 3M3 


June 20, 2002 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

EXECUTIVE SUMMARY
 

A comprehensive directed inspection and maintenance (DI&M) measurement program 

has been conducted at four gas-processing plants in the western United States to identify 

potential sources of cost-effective opportunities for reducing natural gas losses and 

methane emissions due to fugitive equipment leaks and avoidable process inefficiencies 

or wastage. Raw natural gas is predominantly methane but may contain varying amounts 

of non-methane hydrocarbons (NMHC) and impurities or contaminants, such as 

hydrogen sulfide (H2S), nitrogen (N2), carbon dioxide (CO2) and water vapor (H2O). 

Losses of natural gas to the atmosphere result in direct emissions of these constituents. 

Losses of natural gas into flare systems or due to excess fuel consumption result in 

atmospheric emissions of CO2 and other combustion products. 

Here, cost effective opportunities to reduce natural gas losses are seen primarily as a 

prudent means of reducing methane and greenhouse gas (GHG) emissions 

(predominantly methane and CO2), and to a lesser extent, non-methane hydrocarbon 

(NMHC) emissions. All GHG emissions are expressed as CO2-equivalent emissions 

(CO2E) and use a global warming potential of 21.0 for methane. A baseline assessment of 

the total natural gas losses and emissions of the target air pollutants at each host facility is 

provided, and the potential savings and emission reductions that may be achieved by 

reducing losses are highlighted. Additionally, total hydrocarbon (THC) emission factors 

are presented for fugitive equipment leaks and the active natural gas-fueled process 

equipment surveyed. 

METHODOLOGY 

All fieldwork was conducted during the fourth quarter of 2000. The work comprised a 

fugitive-emissions survey of all equipment components in hydrocarbon gas service, 

measurement and characterization of flows into all key vent and flare systems, and 

limited performance testing of natural gas-fueled combustion equipment at three of the 

four sites. Although not specifically targeted, any components in hydrocarbon-liquid or 

plant compressed air service that were noticeably leaking were tagged and brought to the 

attention of site personnel. Complete component counts were prepared for the surveyed 

equipment. 

A total of 101,193 individual equipment components, 5 process vents, 28 natural gasfueled compressor and generator engines, 7 process heaters, and 6 flare/vent systems 

were surveyed. Sufficient process information was collected to allow determination of 

total annual emissions from the compiled measurement results. Additionally, specific 

emission-control opportunities were identified, and a preliminary cost-benefit analysis 

was performed to evaluate these opportunities. The analysis takes into account the 

estimated cost of implementing repairs, the life of the repair, and the value of conserved 

gas. Input was solicited from site personnel to help ensure any site-specific constraints, 

costs associated with equipment/component isolation, and cost data were considered. 

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The four host facilities tested ranged from 20 to 50 years in age, with an average age of 

35 years. In comparison, there are 726 (GRI, 1996) active gas processing plants in the 

United States, and the age distribution of these plants is depicted in the histogram below 

based on data adapted from a 1992 survey by GRI. 

Approximate Age Distribution of Gas Processing Plants in the United States 

Percent of Total Population 

30 

25 

20 

15 

10 

5 

0 

20.4 

10.4 

19.0 

28.2 

22.0 

>31 27 to 31 22 to 26 17 to 21 0 to 16 

Age (Years) 

If it is arbitrarily assumed that the mean age of plants in the >31 years category (20.4 

percent of the population) is 50 years (e.g., lean oil facilities have been around since the 

1920’s), then the average age of gas plants in the United States would be approximately 

26 years. Only one of the four sites surveyed was in the 17 to 21 years category that 

comprises the largest population at greater than 28 percent. While it is assumed that the 

age of the facility is strongly related to the amount of leakage found, other contributing 

factors include how well the facility is maintained, frequency of maintenance practices, 

sweet vs. sour operations, operating practices, facility margins, etc. that may have an 

even larger impact on loss opportunities. 

OVERVIEW OF THE EMISSIONS INVENTORY 

Total atmospheric emissions of methane from all sources at the combined sites are 

estimated at 5,104.4 tonnes per year (t/y) (or 727.9 mscfd). Corresponding GHG and 

NMHC emissions are estimated at 558,527.7 t/y CO2E and 9,509.3 t/y (1,369.3 mscfd), 

respectively. While the primary focus of this study was to identify GHG (methane) loss 

opportunities, consideration of NMHC losses also, added notably to the costeffectiveness of implementing a DI&M program at gas processing facilities. The majority 

of the methane emissions resulted from fugitive equipment leaks (82.0 percent). 

Incomplete combustion by natural gas-fuelled equipment and flares were also noteworthy 

sources of methane emissions (10.1 percent and 1.6 percent, respectively). The major 

sources of GHG emissions are fuel consumption by compressor engines and process 

heaters (79.6 percent), fugitive equipment leaks (15.7 percent), rejection of raw carbon 

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dioxide from the produced natural gas via the amine regeneration vents (2.6 percent), and 

flare/vent systems surveyed (1.8 percent). The dominant source of NMHC emissions is 

storage losses. 

OVERVIEW OF THE NATURAL GAS LOSSES 

The combined value of all natural gas losses at the sites, including direct atmospheric 

emissions, gas leakage into flare systems, and excess fuel consumption by process 

equipment, is estimated at $2,249,500 per year (or $562,375 per year per plant) based on 

the fourth quarter 2000 long-term contract price for natural gas of $4.50/mscf. 

Overall, it is estimated that up to 94.9 percent of total natural gas losses are cost-effective 

to reduce. This would result in corresponding emission reductions of 79.5 percent for 

methane, 16.7 percent for GHG, and 95.7 percent for NMHC. The relatively low impact 

on GHG emissions is due to the significant contribution of CO2 emissions from fuel 

consumption to total GHG emissions at the sites. 

If solely control opportunities having less than a certain payout period (i.e., 0.5, 1, 2, or 4 

years) are implemented, the estimated percent total natural gas loss reduction, including 

unnecessary fuel consumption, and corresponding reductions in methane and GHG 

emissions are as follows: 

Pollutant < 6 months 

(Percent) 

< 1 year 

(Percent) 

< 2 years 

(Percent) 

< 4 years 

(Percent) 

Total Natural Gas Loss Reduction 78.8 92.3 93.1 94.9 

Methane Emission Reduction 71.9 78.1 79.2 79.5 

GHG Emission Reduction 14.6 16.3 16.5 16.7 

NMHC Emission Reduction 88.0 91.0 94.0 95.7 

These estimates do not include the cost of identifying and evaluating natural gas loss 

reduction opportunities; however, such costs are typically small compared to the net 

benefit obtained. For example, the current survey costs, when expressed in terms of the 

number of components in gas service at each facility, were approximately $1.25 per 

component which is only slightly more than the cost of conventional volatile organic 

compounds (VOC) Leak Detection and Repair (LDAR) programs. 

Actual costs on a per-component basis will vary between facilities and will tend to 

increase with the relative number of vents, combustion sources and control opportunities 

identified, the complexity of the operation, the remoteness of the facility, and the severity 

of conditions. The current study identified more than $20 in gross savings, or $13 in net 

savings (i.e., after repair or control costs), per component for control opportunities having 

a less than a 1-year payback based on a gas value of $4.50 per mscf. Consideration of 

opportunity identification costs reduces the net savings by only about 10 percent. If a 

value is assigned to the resulting GHG credits, work is done as a routine commercial 

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service rather than as a study, and efforts are focused on the plant areas most likely to 

offer meaningful control opportunities, improved economics would apply. 

The main cost-effective control opportunities identified at the sites are as follows: 

•	 Fugitive Equipment Leaks: Approximately 2.6 percent of the equipment 

components (approximately 2,630 out of 101,193) in natural gas service were 

determined to be leaking (i.e., had a screening value of 10,000 ppm or more) at 

the combined sites. Components in vibrational, high-use or heat-cycle gas service 

were the most leak prone. The majority of the identified natural gas losses from 

fugitive equipment leaks are attributed to a relatively small number of these 

leaking components. Valves were the greatest contributor to this source category, 

accounting for 30.0 percent of the total, followed by connectors (24.4 percent), 

compressor seals (23.4 percent), open-ended lines (11.1 percent), crankcase vents 

on compressors and compressor engines (4.2 percent), and pressure relief devices 

(3.5 percent). The remaining 3.4 percent was from pump seals, flow meters, 

blowdowns and regulators. 

It is estimated that implementing all cost-effective equipment-repair or 

replacement opportunities identified would reduce natural gas losses from fugitive 

equipment leaks by 95.0 percent and result in gross annual cost savings of 

approximately $1,135,785 (i.e., based on a gas value of $4.50/mscf applicable at 

the time the data were analysed). This amounts to 53.2 percent of total practical 

loss reduction opportunities identified for all source categories at the plants, and a 

gross average annual value of $283,946 per site (or site-specific values ranging 

between $180,686 and $333,377). Less significant losses and fewer loss-reduction 

opportunities would be expected at newer plants. 

Though gas prices fluctuate, economic opportunities exist even at lower values of 

natural gas. For instance, if a value of $2.00/mscf for natural gas were applied, the 

total emissions reduction from cost-effective repair opportunities would be 

reduced to 85.4 percent. The corresponding gross annual value of the total natural 

gas losses from these opportunities is $453,962 or an average of $113,490 per 

site. 

Fixing the 10 greatest emitting cost-effective-to-repair components at each site 

(refer to Appendix II for a ranked listing emission rates by payout period) would 

reduce natural gas losses by approximately 481.8 mscfd or 35.2 percent. 

•	 Flaring: Total residual gas flows in the flare or main vent system at each of the 

sites (i.e., flows outside of blowdown or emergency relief events) amounted to 

334.16 mscfd. In several cases the flows from individual systems were sufficient 

to potentially justify installing a flare-gas recovery unit. Another option is to 

target the actual source or sources of the residual gas flow in these systems (e.g., 

possibly excess purge gas consumption, and leaking pressure-relief devices, 

drains and blowdown valves connected to the flare header). However, these 

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causes are often difficult to isolate, usually required a major plant shutdown to 

fix, and are likely to reoccur. Installing flare-gas recovery units, where economic 

to do so, would reduce GHG emissions at the surveyed plants by approximately 

8,165 tonnes CO2E per year, and take less than a year to pay out. This amounts to 

8.8 percent of total practicable loss reduction opportunities identified. 

•	 Natural Gas-Fueled Process Equipment: While several of the compressor 

engines tested would have benefited from tuning, most units proved to be 

operating efficiently (i.e., air-to-fuel ratios and concentrations of combustibles in 

the flue gas were at or near values recommended by manufacturers). This likely 

reflects the greater attention typically given to combustion equipment at 

continuously manned facilities such as those surveyed. Greater opportunities are 

believed to exist for tuning heaters and engines used at unmanned field facilities. 

Total avoidable fuel consumption from servicing all economic-to-tune engines 

and heaters is estimated at 130.4 mscfd, which is equivalent to GHG emission 

reductions of 2,882.5 tonnes CO2E per year. 

All of the natural gas-fueled engines surveyed were properly matched with the 

current process load requirements (i.e., the units were operating within the 

optimum portion of their performance curve). Notwithstanding this, situations 

may arise where engines are operated outside the optimum portion of their 

performance curve (e.g., due to changes in original load requirements caused by 

declining production, or initial mismatching of equipment to process applications) 

resulting in significantly higher operating costs. 

•	 Storage Tanks: Tanks at three of the sites were checked for vapor losses in 

excess of normal weathered-product evaporation rates. Only one site showed 

abnormally high vapor losses from a storage tank. This tank was subsequently 

removed from hydrocarbon service and the stream was rerouted within the 

process. Isolation of the exact cause of the unusually high losses was beyond the 

scope of this project. Total vapor losses in this case amounted to 160.98 mscfd. 

KEY FINDINGS 

The study has been a success with all program participants having an opportunity to 

realize economic benefits from implementing a voluntary Directed Inspection and 

Maintenance (DI&M) program. The major sources of the target emissions in the natural 

gas processing industry are compressor engines, acid gas wastes, fugitive emissions from 

leaking process equipment, and, if present, glycol dehydrator vent streams. While it is not 

reasonable to extrapolate the results of this study to all gas processing facilities, it is clear 

that significant cost-effective opportunities to reduce natural gas losses and, thereby, 

atmospheric emissions, do exist at gas processing facilities. Based on the presented 

results and the nature of the oil and gas industry, the best opportunities tend to exist at 

older facilities, particularly where facilities have limited remaining life expectancies 

resulting in reduced motivation for capital and maintenance expenditures. 

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Other noteworthy findings and recommendations of the study include the following: 

•	 The host facilities did not have accurate counts of their equipment components. 

Initial estimates provided by the sites were 40 percent lower, on average, than the 

physical counts developed during site visits. One probable explanation for the 

significant underestimate is that the facilities developed their counts from process 

drawings rather than conducting actual field counts. Such errors are usually 

related to the lack of detailed mechanical drawings for packaged process units 

(e.g., compressors and process heaters). Additionally, some facilities may not 

have considered components under 1⁄2 inch in size per NSPS KKK, whereas this 

study considered all component sizes. 

• Sixty-nine percent of the engine and compressor crankcase vents surveyed (i.e., 

25 of 36) were determined to be leaking. The average THC emission factor for 

these components was 0.883 kilogram per hour per source – the greatest value of 

any of the equipment component categories surveyed. In addition, the engine 

crankcase vents may emit products of incomplete combustion. In a number of 

cases, the emissions were discharged inside compressors buildings and work 

areas. This poses a potential health and safety risk. 

•	 The experience of the largest facility was that most of the economical-to-control 

natural gas losses could be eliminated at no real cost. Typically, only simple lowcost repairs were required and could be implemented by existing staff, as time 

was available during normal working hours. Thus, there was no incremental labor 

charge, and material costs were minimal. The repair program was actually used as 

a team building exercise in which each shift competed against the others to 

determine which could implement the most emission reductions. Additionally, it 

served as an opportunity to train new staff in all the different process areas. 

•	 This study has examined natural gas losses at only 0.6 percent of the estimated 

726 gas processing plants in the United States, and has not necessarily captured 

the impact of all significant factors or facility characteristics (e.g., age, size, H2S 

content, and climatic region). To better delineate the extent of natural gas control 

opportunities at gas processing plants and provide more statistically defensible 

results, additional facilities should be surveyed. At a minimum, it is recommended 

that data be compiled for each of the following three plant age categories, since 

this appears to be the most critical factor: new (less than 20 years old), medium 

(20 to 30 years old) and old (greater than 30 years old). Each sample group should 

contain at least 3 plants to allow standard deviations to be calculated and 

statistical tests to be performed between sample groups. 

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•	 It is recommended that a best management practice (BMP) be developed to assist 

companies in devising an optimum loss control program for their circumstances. 

Specific matters to be addressed include: impact of facility age and type on 

opportunity availability, source categories or facility areas on which to focus 

efforts for maximum benefit, control options, low-cost monitoring systems to 

facilitate predictive maintenance of key sources, generic costs and life expectancy 

of repairs by source type and service category. 

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TABLE OF CONTENTS
 

Section Page 

EXECUTIVE SUMMARY ................................................................................................. i
 

TABLE OF CONTENTS................................................................................................. viii
 

LIST OF FIGURES ........................................................................................................... x
 

LIST OF TABLES............................................................................................................. xi
 

GLOSSARY ..................................................................................................................... xii
 

ACKNOWLEDGEMENTS ............................................................................................ xix
 

1.0 INTRODUCTION .................................................................................................. 1 


2.0 BACKGROUND .................................................................................................... 2 


3.0 METHODOLOGY ................................................................................................. 5 


3.1 Site Selection .......................................................................................................... 5 


3.2 Emissions Survey.................................................................................................... 5 


3.2.1 Component Screening................................................................................. 6 


3.2.2 Leak Rate Measurements.............................................................................8 


3.2.3 Measurement of Emissions from Vents and Open-Ended Lines...............10 


3.2.4 Determination of Residual Flaring Rates...................................................11 


3.2.5 Performance Testing of Natural Gas-Fuelled Equipment..........................12 


3.2.6 Evaluation of Excess Emissions from Storage Tanks................................14 


3.2.7 Component Counts.....................................................................................15 


3.2.8 Development of Average Emission Factors ..............................................15 


3.2.9 Emission Control Guidelines .....................................................................15 


3.3 Cost-Benefit Analysis ............................................................................................16 


3.3.1 Cost Estimating..........................................................................................16 


3.3.2 Value of Natural Gas .................................................................................17 


3.3.3 Repair Life .................................................................................................17 


3.3.4 Cost Curves................................................................................................17 


4.0 OVERVIEW OF THE RESULTS........................................................................ 19 


4.1 Emission Inventory ................................................................................................19 


4.2 Natural Gas Losses ................................................................................................23 


4.3 Fugitive Equipment Leaks .....................................................................................23 


4.3.1 Average Emission Factors .........................................................................23 


4.3.2 Average Leak-Rate Trends ........................................................................28 


4.3.3 Leak Frequencies .......................................................................................31 


4.3.4 Component Counts.....................................................................................35 


4.4 Control Opportunities ............................................................................................35 


4.4.1 Cost Curve for Reduction of GHG Emissions...........................................35 


4.4.2 Control Opportunities With a Payback of 1 Year or Less .........................39 


viii 
 

 

 

 

 

 

 

TABLE OF CONTENTS (Concluded)
 

Section Page 

5.0 CONCLUSIONS AND RECOMMENDATIONS .............................................. 41 


5.1 Conclusions .......................................................................................................... 41 


5.2 Recommendations ................................................................................................ 41 


6.0 REFERENCES CITED..........................................................................................43 


APPENDIX I: Measured THC Emission Rates Sorted by Emission Rate ................. 44 


APPENDIX II: Measured THC Emission Rates Sorted by Payout Period.................108 


APPENDIX III: Combustion Analysis and Efficiency Testing Results.......................173 


APPENDIX IV: Average Equipment Component Schedules for Natural Gas
 

Processing Plants ...............................................................................210 


APPENDIX V: Financial Considerations and Assumptions.......................................212 


APPENDIX VI: Basic Component Repair Costs and Mean Repair Life .....................213 


APPENDIX VII: Work Practice - Alternative Means for Leak Detection and Repair
 

in Natural Gas Processing..................................................................217 


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LIST OF FIGURES
 

Figure	 Page 

1. 	 Leak rate versus concentration.................................................................................3 


2 	 Cut-away view of natural gas compressor showing the potential leak
 

points including the compressor seals and crankcase vent ......................................7 


3. 	 Bubble test on leaking valve....................................................................................8 


4. 	 GRI HiFlowTM Sampler .........................................................................................10 


5. 	 Typical crankcase vent configurations recommended by manufacturers for
 

stationary compressor engines ...............................................................................13 


6. 	 Distribution of methane emissions by source category ........................................ 20 


7. 	 Distribution of non-methane hydrocarbon emissions by source category............ 21 


8. 	 Distribution of total GHG emissions by source category ..................................... 22 


9. 	 Distribution of natural gas losses by source category........................................... 25 


10. 	 Distribution of natural gas losses from equipment leaks by type of
 

component .............................................................................................................26 


11. 	 Average THC emissions for connectors by gas stream .........................................29 


12. 	 Average THC emissions for compressor sources, component type ......................30 


13. 	 Average THC emissions for crankcase vents by type ...........................................30 


14. 	 Average THC emissions for control valves by component type ...........................32 


15. 	 Average THC emissions for connectors by process unit.......................................32 


16. 	 Average THC emissions for valves by process unit ..............................................33 


17. 	 Comparison of company estimates to actual number of components....................36 


18. 	 Emissions from economically repairable sources..................................................37 


19. 	 Net cost curve for cumulative CO2E emission reductions at surveyed gas
 

plants......................................................................................................................38 


x 
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LIST OF TABLES
 

Table	 Page 

1. 	 Summary of the surveyed gas plants .......................................................................5 


2. 	 Summary of natural gas losses from the tested plants. ..........................................24 


3. 	 Summary of natural gas losses from combined data gathered at four
 

surveyed gas plants ................................................................................................24 


4. 	 Summary of natural gas losses from the top ten leakers........................................24 


5. 	 Comparison of average THC emission factors derived from data collected
 

at the test sites to other published values...............................................................27 


6. 	 Number of components and leak frequency at each of the four gas plants ...........34 


7. 	 Summary of the top ten sources of natural gas losses identified ...........................40 


I-1.	 Measured THC emissions rates, sorted by emission rate, from leaking 

equipment components at surveyed gas plants, October to December, 

2000........................................................................................................................44 


II-1.	 Measured THC emissions rates, sorted by payout period, from leaking 

equipment components at surveyed gas plants, October to December, 

2000......................................................................................................................108 


IV-1.	 Summary of average equipment component schedules for processes at
 

natural gas processing plants. ..............................................................................210 


VI-1.	 Summary of repair costs and mean life of repair for equipment
 

components in natural gas and non-methane hydrocarbon service. ....................213 


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GLOSSARY
 

Blow-By 

Carbon Dioxide Equivalent 

(CO2E) ­

Centrifugal Compressor 

Seal Systems ­

Combustion Efficiency ­

Gas from a piston cylinder that leaks past the piston rings 

into the crankcase. 

Carbon dioxide equivalent is an expression of the total 

emission of all greenhouse gases, based on the relative 

ability of the gases to trap heat in the atmosphere. 

Greenhouse gases are a group of compounds in the 

atmosphere that tend to absorb solar radiation and reradiate 

it back to the earth’s surface. The most important of these 

are carbon dioxide (CO2), methane (CH4) and nitrous oxide 

(N2O). Global warming potentials (GWPs) were developed 

as a simple measure of the global warming effects of the 

emission of various greenhouse gases relative to those of 

carbon dioxide. The current practice (IPCC, 1996) is to use 

a 100-year time horizon for global warming potentials. 

Therefore, the GWPs used in this document are: CO2 = 1.0, 

CH4 = 21.0 and N2O = 310. 

Greenhouse gas emissions are converted to carbon dioxide 

equivalent (CO2E) emissions by multiplying the mass 

emissions of each gas by the appropriate global warming 

potential and summing the CO2E emissions. CO2E 

emissions are expressed in metric tonnes. 

Centrifugal compressors generally require shaft-end seals 

between the compressor and bearing housings. Either facecontact oil-lubricated mechanical seals or oil-ring shaft 

seals, or dry-gas shaft seals are used. The amount of 

leakage from a given seal will tend to increase with wear 

between the seal and compressor shaft, operating pressure 

and rotational speed of the shaft. 

The extent to which all input combustible material has been 

completely oxidized (i.e., to produce H2O, CO2 and SO2). 

Complete combustion is often approached but is never 

actually achieved. The main factors that contribute to 

incomplete combustion include thermodynamic, kinetic, 

mass transfer and heat transfer limitations. In fuel rich 

systems, oxygen deficiency is also a factor. Also see 

thermal efficiency below. 

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Connectors ­

Crankcase ­

Destruction Efficiency ­

Flare and vent systems ­

Fugitive Emissions ­

Gas Plant ­

A connector is any flanged or threaded connection, or 

mechanical coupling, but excludes all welded or backwelded connections. If properly installed and maintained, a 

connector can provide essentially leak-free service for 

extended periods of time. However, there are many factors 

that can cause leakage problems to arise. Some of the 

common causes include vibration, thermal stress and 

cycles, dirty or damaged contact surfaces, incorrect sealing 

material, improper tightening, misalignment, and external 

abuse. 

The crankcase on reciprocating engines and compressors 

house the crankshaft and associated parts, and typically a 

supply of oil to lubricate the crankshaft. Integral 

compressors have a single crankcase since the engine and 

compressor share a common crankshaft. Non-integral 

compressors typically have two crankcases, one on the 

engine side and another on the compression side. 

The extent to which a target substance present in the input 

combustibles has been destroyed (i.e., converted to 

intermediate, partially-oxidized and fully-oxidized products 

of combustion). 

Venting and flaring are common methods of disposing of 

waste gas volumes at gas processing plants. The stacks are 

designed to provide safe dispersion of the effluent. Flares 

are normally used where the waste gas contains odorous or 

toxic components (e.g., hydrogen sulphide). Otherwise the 

gas is usually vented. Typically, separate flare/vent systems 

are used for high- and low-pressure waste gas streams. 

Unintentional leaks from equipment components including, 

but not limited to, valves, flanges and other connections, 

pumps and compressors, pressure relief devices, process 

drains, open-ended valves, pump and compressor seal 

system degassing vents, accumulator vessel vents, agitator 

seals, and access door seals. Fugitive sources tend to be 

continuous emitters and have low to moderate emission 

rates. 

A gas processing plant is a facility for extracting 

condensable hydrocarbons from natural gas, and for 

upgrading the quality of the gas to market specifications 

(i.e., removing contaminants such as H2O, H2S and CO2 

xiv 
 

 

 

Heat Rate ­

Integral Compressor 

Methane Leak 

Long-Term Contract Price 

of Natural Gas ­

Open-ended Valves 

and Lines ­

and possibly adjusting the heating value). 

The amount of heat energy (based on the net or lower 

heating value of the fuel) that must be input to a 

combustion device to produce the rated power output. Heat 

rate is usually expressed in terms of net J/kW·h. 

A reciprocating compressor that shares a common 

crankshaft and crankcase with the engine. 

Greater than 10,000 parts per million when sampled with a 

dual-element hydrocarbon detector (i.e., catalyticoxidation/thermal-conductivity). 

Historically, long-term contracts have been used by buyers 

to lock up a secure supply of natural gas and by sellers to 

reduce in the risk in developing a large reserve. During the 

1960s and 70s, these contracts were established for terms 

of up to 20 to 25 years and the price of the gas was set at 

values determined by periodic negotiations. The recent 

trend is towards shorter contract durations, and most new 

long-term contracts index the gas price to spot market rates. 

Today, a typical long-term contract with a cogeneration 

plant is about 15 years. Given the interest in risk 

management by sellers and buyers, there is also a trend 

towards greater standardization of long-term contracts to 

facilitate hedging activity in the financial or the over-thecounter market 

An open-ended valve is any valve that may release process 

fluids directly to the atmosphere in the event of leakage 

past the valve seat. The leakage may result from improper 

seating due to an obstruction or sludge accumulation, or 

because of a damaged or worn seat. An open-ended line is 

any segment of pipe that may be attached to such a valve 

and that opens to the atmosphere at the other end. 

Few open-ended valves and lines are designed into process 

systems. However, actual numbers can be quite significant 

at some sites due to poor operating practices and various 

process modifications that may occur over time. 

Some common examples of instances where this type of 

source may occur are listed below: 

• scrubber, compressor-unit, station and mainline 

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Power Output ­

Pressure-Relief or Safety 

Valves ­

Products of Incomplete 

Combustion ­

blowdown valves, 

•	 supply-gas valve for a gas-operated engine starter (i.e., 

where natural gas is the supply medium), 

•	 instrument block valves where the instrument has been 

removed for repair or other reasons, and 

•	 purge or sampling points. 

The net shaft power available from an engine after all 

losses and power take-offs (e.g., ignition-system power 

generators, cooling fans, turbo chargers and pumps for fuel, 

lubricating oil and liquid coolant) have been subtracted. 

For heaters and boilers it is the net heat transferred to a 

target process fluid or system. 

Pressure relief or safety valves are used to protect process 

piping and vessels from being accidentally over-pressured. 

They are spring loaded so that they are fully closed when 

the upstream pressure is below the set point, and only open 

when the set point is exceeded. Relief valves open in 

proportion to the amount of overpressure to provide 

modulated venting. Safety valves pop to a full-open 

positions on activation. 

When relief or safety valves reseat after having been 

activated, they often leak because the original tight seat is 

not regained either due to damage of the seating surface or 

a build-up of foreign material on the seat plug. As a result, 

they are often a source of fugitive emissions. Another 

problem develops if the operating pressure is too close to 

the set pressure, causing the valve to "simmer" or "pop" at 

the set pressure. 

Gas that leaks from a pressure-relief valve may be detected 

at the end of the vent pipe (or horn). Additionally, there 

normally is a monitoring port located on the bottom of the 

horn near the valve. 

These are any compounds, excluding CO2, H2O, SO2, HCl 

and HF, which contain C, H, S, Cl or F and occur in 

combusted gases. These compounds may result from 

thermodynamic, kinetic or transport limitations in the 

various combustion zones. All input combustibles are 

potential products of incomplete combustion. Intermediate 

substances formed by dissociation and recombination 

effects may also occur as products of incomplete 

combustion (CO is often the most abundant combustible 

xvi 
 

 

 

 

 

 

 

 

formed). 


Pump Seals ­ Positive displacement pumps are normally used for 

pumping hydrocarbon liquids at oil and gas facilities. 

Positive displacement pumps have a reciprocating piston, 

diaphragm or plunger, or else a rotary screw or gear. 

Packing, with or without a sealant, is the simplest means of 

controlling leakage around the pump shaft. It may be used 

on both the rotating and reciprocating pumps. Specially 

designed packing materials are available for different types 

of service. The selected material is placed in a stuffing box 

and the packing gland is tightened to compress the packing 

around the shaft. All packings leak and generally require 

frequent gland tightening and periodic packing 

replacement. 

Particulate contamination, overheating, seal wear, sliding 

seal leakage and vibration will contribute to increased 

leakage rates over time. 

Reciprocating Compressor 

Packing Systems -

Packings are used on reciprocating compressors to control 

leakage around the piston rod on each cylinder. 

Conventional packing systems have always been prone to 

leaking a certain amount, even under the best of conditions. 

According to one manufacturer, leakage from within the 

cylinder or through any of the various vents will be on the 

order of 1.7 to 3.4 m3

/h under normal conditions and for 

most gases. However, these rates may increase rapidly as 

normal wear and degradation of the system occurs. 

Standard Reference 

Conditions ­

Most equipment manufacturers reference flow, 

concentration and equipment performance data at ISO 

standard conditions of 15°C, 101.325 kPa, sea level and 0.0 

percent relative humidity. 

Thermal Efficiency ­ The percentage or portion of input energy converted to 

useful work or heat output. For combustion equipment, 

typical convention is to express the input energy in terms of 

the net (lower) heating value of the fuel. This results in the 

following relation for thermal efficiency: 

Useful Work/Heat Output η= Thermal Efficiency = x 100% 

Net Heat/Energy Input 

xvii 
 

 

 

 

 

Alternatively, thermal efficiency may be expressed in terms 

of energy losses as follows: 

⎛ ΣEnergy Losses
 ⎞

η
 =
⎜1
 x 100%
 ⎜

⎝

-

Net Heat/Energy Input 

⎟

⎟

⎠

Total Hydrocarbons (THC) 

-

Total Organic 

Compounds (TOC) ­

Valves ­

Losses in thermal efficiency occur due to the following 

potential factors: 

•	 exit combustion heat losses (i.e., residual heat value in 

the exhaust gases), 

•	 heat rejected to cooling jacket water and lubrication oil, 

•	 radiation from hot surfaces of the equipment, 

•	 air infiltration, 

•	 incomplete combustion, and 

•	 mechanical losses (e.g., friction losses and energy 

needed to run cooling fans and lubricating-oil pumps). 

All compounds containing at least one hydrogen atom and 

one carbon atom, with the exception of carbonates and 

bicarbonates. 

TOC comprises all VOCs plus all non-reactive organic 

compounds (i.e., methane, ethane, methylene chloride, 

methyl chloroform, many fluorocarbons, and certain 

classes of per fluorocarbons). 

There are three main locations on a typical valve where 

leakage may occur: (1) from the valve body and around the 

valve stem, (2) around the end connections, or (3) past the 

valve seat. Leaks of the first type are referred to as valve 

leaks. Emissions from the end connections are classified as 

connector leaks. Leakage past the valve seat is only a 

potential source of emissions if the valve, or any 

downstream piping, is open to the atmosphere. This is 

referred to as an open-ended valve or line. 

The potential leak points on each of the different types of 

valves are, as applicable, around the valve stem, body seals 

(e.g., where the bonnet bolts to the valve body, retainer 

connections), body fittings (e.g., grease nipples, bleed 

ports), packing guide, and any monitoring ports on the stem 

packing system. Typically, the valve-stem packing is the 

most likely of these parts to leak. 

xviii 
 

 

The different valve types include gate, globe, butterfly, 

ball, plug, and globe. The first two types are a rising-stem 

design, and the rest are quarter-turn valves. Valves may 

either be equipped with a hand-wheel or lever for manual 

operation, or an actuator or motor for automated operation. 

Vented Emissions ­ Vented emissions are releases to the atmosphere by design 

or operational practice, and may occur on either a 

continuous or intermittent basis. The most common causes 

or sources of these emissions are gas operated devices that 

use natural gas as the supply medium (e.g., compressor 

start motors, chemical injection and odorization pumps, 

instrument control loops, valve actuators, and some types 

of glycol circulation pumps), equipment blowdowns and 

purging activities, and venting of still-column off-gas by 

glycol dehydrators. 

Volatile Organic Any compound of carbon, excluding carbon monoxide, 

Compounds (VOC) ­ and carbon dioxide, which participates in atmospheric 

chemical reactions. This excludes methane, ethane, 

methylene chloride, methyl chloroform, many 

fluorocarbons, and certain classes of per fluorocarbons. 

xix 
 

ACKNOWLEDGEMENTS
 

The funding provided by US Environmental Protection Agency (Grant No. 827754-01-0), 

Gas Research Institute, BP Amoco, Duke Energy Field Services, and Dynegy Midstream 

Services in support of this project is gratefully acknowledged. Special thanks are given to 

the personnel at each of the host facilities for their help, interest in the work being done, 

and useful feedback, and to all the sponsors for their constructive review comments. 

xx 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

1.0 INTRODUCTION 

An intensive fugitive emissions screening and measurement program was conducted 

during the fourth quarter of 2000 at four gas processing facilities in the western USA. 

The selected facilities were of various ages, types, and throughputs and were evaluated 

with a strong emphasis on natural gas losses from leaking equipment components in heatcycle and vibration services. The facilities included sweet and sour gas processing, and a 

variety of processes including compression, separation, stabilization, deep cryogenic 

recovery and rejection, mole sieve and TEG/DEG dehydration, amine treatment, sulfur 

recovery, and flare systems. 

The primary objective of the study was to demonstrate the cost-effectiveness of 

conducting a comprehensive leak detection and repair program at domestic gas 

production and processing facilities using GTI's HiFlowTM Sampler technology. Field 

measurements also included an assessment of emissions from continuous vents, 

combustion equipment, flare systems, and diagnostic checks of natural gas-fueled 

equipment. Such efforts are seen as an opportunity to achieve sensible and verifiable 

reductions in methane, GHG and NMHC emissions, as well as a potentially noteworthy 

economic opportunity for industry from product loss prevention and recovery. 

Background information on key differences between the conventional Method 21 

approach to leak detection and repair and the GTI approach used here is provided in 

Section 2 and Appendix VII. A more detailed description of the GTI approach and other 

measurement techniques employed, as well as an overview of the basic assessment 

methodology are presented in Section 3. Section 3 also delineates the economic criteria 

used to evaluate the identified emission control opportunities. 

The results of the measurement program are presented in Section 4 and include an 

inventory of the determined emissions and natural gas losses, average emission factors, 

leak statistics, and an overview of the identified control opportunities. The conclusions 

and recommendations of this study are presented in Section 5, and all references cited are 

listed in Section 6. A detailed listing of all the identified equipment leaks is provided in 

Appendices I and II, ranked by emission rate and payout period, respectively. The 

following information is provided for each component: Site No., Tag No., Process Unit, 

Component Description, Emission Rate (103 m3

/y), Estimated Repair Costs ($), Net 

Present Value of Repair ($), CO2E Emissions (t/y), and Repair Payback Period (y). 

A detailed account of the combustion analysis results and efficiency testing for each 

tested unit is available in Appendix III. A summary of average equipment component 

schedules by type of process unit is provided in Appendix IV. The financial 

considerations and assumptions applied are summarized in Appendix V while the 

assumed component repair costs and mean repair life are provided in Appendix VI. 

1 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2.0 BACKGROUND 

The New Source Performance Standards in 40 CFR Part 60 KKK provide the regulatory 

requirements for conducting a leak detection and repair program for the onshore natural 

gas processing industry. This standard is directed at controlling/reducing volatile organic 

compound (VOC) emissions and specifically excludes methane and ethane. Therefore, 

gas-processing facilities have typically only included the light liquid and refrigeration 

portion of the facility in a leak detection program. Subsequently, very little information 

pertaining to the remaining portion of the facility (i.e. non-regulated) and potential 

leakage was available. The objective of this project was to evaluate the leak potential and 

cost-effectiveness of implementing a leak detection and repair program at natural gas 

processing facilities. 

Most leak detection and repair (LDAR) programs in the natural gas industry rely on US 

EPA Method 21. Depending on the selected detector, the concentration of either total 

hydrocarbons (THC) or volatile organic compounds (VOC’s) in air from a leaking 

component is measured, and then a correlation equation is used to estimate the leak rate. 

The uncertainties in this technique are typically ± two orders of magnitude, but can be as 

great as three to four orders of magnitude. In a conventional leak detection and repair 

program for the control of fugitive emissions, U.S. EPA’s Method 21 is utilized to screen 

the facility for leaks at a prescribed frequency (e.g. quarterly, bi-annually or annually). 

All components that screen above a given threshold (typically 10,000 parts per million) 

are to be repaired. 

However, concentration is a weak surrogate for the actual leak rate and under Method 21 

guidelines up to 10 times as many leaks are repaired than would be necessary to obtain a 

significant reduction in emissions. Also, the conventional approach does not provide an 

accurate measurement of either the baseline emissions from the facility or the amount of 

emissions reduced (error is ± 300%). 

Concentration values measured using Method 21 are plotted against the leak rate in 

Figure 1. The scatter in the data is nearly ± two orders of magnitude. Consequently, by 

repairing all components that screen above 10,000 parts per million, resources are wasted 

on repairing components with extremely small leaks, while many components that screen 

less than 10,000 parts per million are not fixed even though they have a significant leak 

rate. 

2 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

ppt96\Hummel\Jul\GRILOTT\2 

Leak Rate Versus Screening Value Figure 1 Leak Rate versus Concentration
 Mass Emission Rate (lb/ day THC Mass Emission Rate (lb/ )

1.0E­06

1.0E­05

1.0E­04

1.0E­03

1.0E­02

1.0E­01

1.0E+00 1.0E+00

1.0E+01 1.0E+01

Correlation Correlation Equation Equation

Bagging Bagging Data

1 10 100 1000 10000 100000

ScreeningValue(ppmv)ppt96\Hummel\Jul\GRILOTT\1 

Data collected by GTI (formerly the Gas Research Institute) show that only 10% of the 

fugitive components that screen above 10,000 parts per million at natural gas facilities are 

cost-effective to repair, while 20% of the fittings that screen less than 10,000 parts per 

million are cost-effective to repair and would not be repaired using standard Method 21 

criteria. 

Many leaks that are cost effective to repair are missed while many others, that are 

actually very small emitters, are repaired. Because the reduction in emissions cannot be 

accurately determined, the benefits of implementing an LDAR program cannot be 

evaluated. The problems with the current work practice result from Method 21’s inability 

to provide an accurate estimate of the actual leak rate. 

Additionally, the correlation equations only go to screening concentrations of 10,000 or 

100,000 parts per million to match the corresponding upper detection limits of common 

screening devices Any leak above these screening concentrations has the same estimated 

leak rate (known as a “pegged source” emission factor). A large percentage of leaks 

screen above these concentrations but are not cost effective to repair. This is especially 

true in the natural gas industry. 

GTI has significantly reduced the cost of applying leak detection and repair programs at 

natural gas facilities through use of the HiFlowTM Sampler and cost-efficient leak 

detection techniques and methodologies. GTI data has shown that when this procedure is 

implemented at natural gas compressor stations, emissions can be reduced by 80 to 90 

percent with a payback period of 6 to 12 months. 

3 
 

 

 

 

 

With an estimate of the repair cost and the measured leak rate, leaks can be rank ordered 

by payback period. Since the data show that 10 percent of the leaks are responsible for 

80 to 90 percent of the emissions from a facility, significant reductions can be achieved 

by repairing a relatively small number of leaks. In view of recent research and data which 

indicate that the HiFlowTM Sampler offers more robust estimates of actual leak rates, GTI 

is currently petitioning EPA for acceptance of an alternative work practice to Method 21. 

4 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

3.0 METHODOLOGY 

This section describes the site selection process and the methodology used by the study 

team to identify and evaluate cost-effective opportunities to reduce gas losses and 

methane and other GHG emissions at the selected gas processing facilities. The different 

measurement techniques considered for each type of primary source are delineated. 

3.1 Site Selection 

The four selected test facilities were chosen to provide a representative cross section of 

older gas plants with significant on-site compression since these types of facilities were 

expected to offer the greatest opportunities for cost-effective reduction of natural gas 

losses. As shown in Table 1, three sweet and one sour gas processing plants were 

selected. These plants range from 20 to 50 years in age, for an average age of 35. In 

comparison, the average age of gas processing facilities in the United States is estimated 

at 26 years. All of the plants have deep cut liquids extraction facilities, compression 

facilities, and mole sieve dehydration units. 

Table 1. Summary of Surveyed Gas Plants. 

Plant 

No. Type Age 

Number of 

Components 

Plant Throughput 

Gas 

(mmscfd) 

NGL 

(bbl/d) 

Condensate 

(bbl/d) 

Water 

(bbl/d) 

1 Sweet 35 16, 073 54 7,070 N/A N/A 

2 Sweet 50 14, 438 60 8,000 N/A N/A 

3 Sweet 20 56, 496 210 16,000 3,000 14 

4 Sour 35 14, 186 120 11,430 N/A N/A 

TOTAL Avg. 35 101,193 

The component counts presented in Table 1 above include components less than 1/2” 

nominal pipe size, which represent 13.8 percent of total components counted. The 

component counts are not complete for Sites 1, 2, and 4 since not all components in 

hydrocarbon liquid service were counted at these locations. 

3.2 Emissions Survey 

The main elements of each site survey included the following, as applicable: 

•	 screening of equipment components to detect leaks, 

•	 measurement of emission rates from identified leaking equipment components 

(i.e., leakers), 

•	 measurement of emissions from continuous vents and residual flows from 

emergency vents during passive periods, 

•	 developing counts of the surveyed equipment components, 

•	 measurement of residual flare-gas rates, 

•	 performance testing of natural gas-fueled combustion equipment, 

•	 sampling of process and waste streams, 

5 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

•	 development of the emissions inventory, 

•	 determination of site-specific average emission factors for fugitive equipment 

leaks, and 

•	 cost-benefit analysis of the identified control opportunities. 

3.2.1 Component Screening 

Equipment components on all process-, fuel- and waste-gas systems were 

screened for leaks. The types of components surveyed included flanged and 

threaded connections (i.e., connectors), valves, pressure-relief devices, openended lines, blowdown vents (i.e., during passive periods), instrument fittings, 

regulator and actuator diaphragms, compressor seals, engine and compressor 

crankcase vents (see Figure 2), sewer drains, sump, drain tank vents and tank 

hatch seals. 

Components in light-liquid service generally were not screened since the focus 

was on natural gas losses. Furthermore, they do not contribute significantly to 

total hydrocarbon losses at gas processing plants due to their low average leak 

rates (US EPA, 1995) and relative numbers. Leak detection (or screening) was 

done using bubble tests with soap solution, portable hydrocarbon gas detectors 

(Bascom-Turner Gas Sentry CGI-201 and CGI-211 and a GMI Gas Surveyor3) 

and an ultrasonic leak detector (SDT International, SDT-120). 

Bubble tests, as shown in Figure 3, were performed on the majority of 

components (including pipe threads, tubing connections and valves), since it is 

usually the fastest screening technique. Components that could not be screened 

using bubble tests included any in high-temperature service, certain flanged 

connections and open-ended lines. These were screened using the gas detectors. 

Ultrasonic detectors were found to be effective for leak detection in areas with 

low background noise levels in the ultrasonic range. In all cases a screening value 

of 10 000 ppm or greater was used as the leak definition. If a component was 

determined to be emitting by one of the alternative techniques (i.e., bubble tests or 

the ultrasonic leak detector), it was then screened using the hydrocarbon vapor 

analyzer to determine if the component would be classified as a leaker. 

All identified leaking components were tagged, and the specific source of leakage 

and date were noted on each tag. The emission rates from all leakers in natural gas 

service were then determined using the procedures described in Sections 3.2.2 and 

3.2.3. All leaker tags were left in place after the leak rate was quantified to 

simplify facility personnel follow-up action. 

6 
CRANKCASE

VENT 

Figure 2. 

PACKING 

Oil CASE 

Purge Leakage 

DISTANCE 

PIECE 

Leakage 

Vent Vent

Vent Leakage 

RECIPROCATING COMPRESSOR

PACKING & VENT SYSTEM

Oil 

Leakage Purge 

Leakage 

Vent Vent

Vent Leakage

EXPANDED VIEW OF THE

COMPRESSOR HEAD

Cut-away view of natural gas compressor showing the potential 

leak points including the compressor seals and crankcase vent. 

7
 

 

 

 

 

 

 

 

 

 

Figure 3 - Bubble test on leaking valve 

The following basic information was recorded for each leaking component: 

• Component Type 

• Model or Style of Component 

• Service 

• Size 

• Process Unit 

• Process Stream 

• Pressure and Temperature 

3.2.2 Leak-Rate Measurements 

The HiFlowTM Sampler was the primary method used to measure emission rates 

from leaking equipment components. Specific cases where the HiFlowTM Sampler 

was not used included any components leaking at rates above the upper limit of 

the unit (i.e., above about 14 m3

/h for the current HiFlowTM design) and most 

open-ended lines and vents. Either bagging or direct measurement techniques, as 

appropriate, were used in these cases (see Section 3.2.3). The following provides 

a brief description of the HiFlowTM Sampler. 

The HiFlowTM Sampler was developed by GTI as an economic means of 

measuring the emission rate from individual leaking equipment components with 

sufficient accuracy to allow an objective cost-benefit analysis of each repair 

opportunity. To bag all leakers in order to differentiate between economic-to8 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

repair and uneconomic-to-repair components is expensive and, therefore, is not 

normally done (typically, 6 to 15 leak-rate measurements per hour can be 

performed using the HiFlowTM Sampler compared to only 2 per hour using 

bagging techniques). Furthermore, compiling Method 21 (U.S. EPA, 1997) 

screening data for these components and then applying leak-rate correlations or 

stratified emission factors to the results does not provide sufficient accuracy for 

this purpose. The uncertainties in the correlation predictions on an individual 

component basis are ± two orders of magnitude and the use of stratified emission 

factors is even less reliable. In comparison, the results of HiFlowTM and bagging 

measurements contain uncertainties of only about ±10 to 15 percent. Accordingly, 

the HiFlowTM Sampler (shown in Figure 4) provides a practicable means of 

making objective repair decisions. The reliability and use of the HiFlowTM 

Sampler has been demonstrated in a number of studies (Howard et al., 1994; Lott 

et al., 1995). 

The operating principle of the HiFlowTM Sampler is simple – a variable-rate 

induced-flow sampling system provides total capture of the emissions from a 

leaking component. An assortment of specially-designed attachments are 

provided for use as needed to ensure total emissions capture, or to help prevent 

interference from other nearby sources. A dual-element hydrocarbon detector 

(i.e., catalytic-oxidation/thermal-conductivity), inserted directly in the main 

sample line within the HiFlowTM, measures hydrocarbon concentrations in the 

captured air stream ranging from 0.01 to 100 percent. A background samplecollection line and hydrocarbon detector allows the sample readings to be 

corrected for ambient gas concentrations, which is particularly important in 

buildings and confined areas. A thermal anemometer, also inserted directly into 

the main sample line, monitors the mass flow rate of the sampled air-hydrocarbon 

gas mixture. The HiFlowTM Sampler is intrinsically safe and is equipped with a 

grounding wire to dissipate any static charge that may accumulate as air passes 

through the sample collection line and instrument. 

The battery-operated fan in the HiFlowTM Sampler can generate a maximum 

sampling velocity of approximately 366 m/min (1200 ft/min), which corresponds 

to a maximum leak rate measurement capacity of roughly 14 m3

/h (8.5 scfm). 

Increasing the sampling rate generally improves the leak capture efficiency up to 

the point of total capture. Increasing sampling rates beyond this point results in 

increased dilution of the emissions with ambient air. Excessive dilution may cause 

the pollutant concentration to either fall below the detection range of the sample 

detector or to decrease to background levels resulting in a zero reading. The 

sampling rate is adjusted manually using a backpressure valve mounted on the fan 

outlet. For large leaks, the backpressure valve is left open; while for small leaks, 

the airflow rate is reduced so that the hydrocarbon concentration is within the 

sensing range of the hydrocarbon detector. 

The sample and background hydrocarbon detectors in the HiFlowTM Sampler 

were calibrated 100 percent methane and 2.5 percent methane-in-air to cover both 

9 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

ranges of the dual-element detector system. Zeroing of the detectors was done 

using ambient air upwind of the facilities. The calibrations were done prior to use 

of the HiFlowTM Sampler at each site, and then periodically thereafter to ensure 

that no significant drift occurred. The HiFlowTM Sampler is also calibrated 

periodically by releasing known flowrates of methane into the sampler inlet and 

comparing the leak rate measured by the HiFlowTM to the actual gas release rate 

determined using a bubblometer or diaphragm meter. A total of three correction 

factors are applied to the raw data collected. 

Figure 4. GRI HiFlowTM Sampler 

3.2.3 Measurement of Emissions from Vents and Open-ended Lines 

The emission rates from open-ended lines and vents were measured using an 

appropriate flow-through measurement device (i.e., a precision rotary meter, 

diaphragm flow meter, or rotameter, depending on the flow rate) if total flow 

capture was safe and practicable to achieve and the resulting backpressure on the 

vent system could be tolerated. Otherwise flows were determined by measuring 

the velocity profile across the vent line and the flow area at that point. 

Where flow capture was required custom-fabricated slip-on sheaths made of 

neoprene or plastic sheeting were used to connect a flow line to the end of the 

vent or open-ended line. The sheaths were easy to use and provided a reliable seal 

around the pipe. Nylon insert fittings and clear PVC tubing were used to conduct 

the vented gas from the sheath to the selected flow meter. Each flow measurement 

10 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

was typically averaged over a 10 to 20 minute time interval, depending on the 

amount and steadiness of the flow. 

Flow velocities were measured using a pitot tube, hot-wire anemometer or 

thermal dispersion anemometer. The traverse points were selected in general 

accordance with US EPA Methods 1 and 1A. 

When measuring flows from vents, a distinction was made between continuous 

and intermittent vent systems. Emissions from intermittent vents during inactive 

periods were defined as leakage. Emissions from continuous vent systems and 

intermittent vent systems during active periods were defined as vented emissions. 

Leakage from vents and open-ended lines was detected by screening using a 

hydrocarbon sensor. 

3.2.4 Determination of Residual Flaring Rates 

Flows in flare lines were determined using one of the following two methods, as 

presented in the order of decreasing reliability and preference: 

•	 Measurement of the Velocity Profile and Flow Area in the Flare Line ­

this is the same approach as described in Section 3.2.3 for measuring flows in 

vent lines. It requires that a safe-to-access port exist on the stack, the common 

line to the flare or on each branch line connected to the flare system. 

• Backcalculation Based on Pressure Drops - the pressure drop between the 

flare tip and a suitable upstream point on the flare line is measured and then 

the amount of flow required to produce that much pressure drop is determined 

by backcalculation. Ideally, at least several inches of water column pressure 

drop should be occurring to allow a reasonable estimation of the flow rate. If 

the flow velocities are too low there may not be any measurable pressure drop 

in the system but the flows can still be significant if the piping size is large. 

In each case, the hydrocarbon concentration of the stream was either determined 

using a portable combustible-gas detector or was based on a detailed laboratory 

analysis of the flare gas (where available). 

The determination of flows in continuous flare systems allows a review of the 

economics associated with conserving the waste gas. The determination of 

residual flows for intermittent flare systems provides an indication of the 

combined purge gas flow rate and leakage rates into the flare system. To 

distinguish between purge gas flows and leakage, the minimum required purge 

gas rate was calculated using the procedure presented by Stone et al. (1992), and 

subtracted from the total residual flare rate. The difference was then taken to be 

leakage or potentially avoidable natural gas loss. 

11 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

3.2.5 Performance Testing of Natural Gas-Fueled Equipment 

Each natural gas-fueled engine and process heater or boiler was tested to identify 

avoidable inefficiencies resulting in excessive fuel consumption and emissions. 

The focus was on identifying situations where equipment were either in need of 

tuning or repairs, or were mismatched for the current process demands resulting 

in operation low on, or off of, the unit’s published performance curve. The 

identification of opportunities to recoup waste heat from the units, or to reduce 

energy requirements through process modifications was beyond the scope of this 

project. 

The testing done on each unit involved analyzing the flue gas, measuring the flue 

gas temperature, obtaining an analysis of the fuel gas composition, and where 

possible, measuring the flow rate of one or more of the following: fuel gas, 

combustion air, or flue gas. Additionally, the make and model of each unit, and 

ambient conditions (i.e., temperature and barometric pressure) at the site were 

recorded. 

Typically, insufficient process data were available to allow a reliable estimate of 

the total amount of useful process work done by each unit, or to determine overall 

unit performance. Consequently, a simplified approach was taken in which the 

following parameters were evaluated and their departures from proper operating 

conditions were determined as an indication of opportunities for improvement: 

• residual heat content of the discharged flue gas (i.e., stack losses), 

• excess air setting, and 

• concentration of carbon monoxide and unburned hydrocarbons in the flue gas. 

Additionally, the crankcase vent on all reciprocating engines was checked for 

significant blow-by (i.e., leakage past the piston rings into the crankcase) as this 

reduces cylinder compression resulting in inefficient operation and contributes to 

emissions of unburned and partially burned fuel. As a first approximation of the 

resulting performance loss, measurements were performed to quantify the amount 

of combustible gases emitted as blow-by from the crankcase vent. These results 

are presented as fugitive equipment leaks. On integral compressor units (i.e., 

compressor units where the engine and compressor share a common crankshaft 

and crankcase), emissions from the crankcase vent potentially include blow-by 

from the engine cylinders and leakage from the compressor seals, as shown in 

Figure 2, which has entered the crankcase through the distance piece. 

In many cases, the engine crankcase was vented inside a building or work area. 

This poses a potential health and safety risk. Figure 5 depicts various venting 

configurations recommended by the engine manufacturers. 

12 
 

 

 

Figure 5.	 Typical crankcase vent configurations recommended by manufacturers for 

stationary compressor engines. 

13 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Where possible, equipment-specific emissions factors on either a kilogram-percubic-meter fuel basis (if the fuel consumption rate of the unit was known) or on a 

kilogram-per-day basis (if the flue gas flow rate was known) were generated for 

use in estimating total emissions of CO, NOx, CO2 and combustibles. A detailed 

summary of the calculations and a discussion of normal operating efficiencies and 

losses are provided in Appendix III. 

The flue gas analyses were conducted using an Enerac 2000E Portable 

Combustion Analyzer equipped with detectors for O2, CO, CO2, NOx, and 

combustibles, and thermocouples for measuring ambient and stack-gas 

temperatures. The flue gas was sampled either through a convenient sampling port 

on the exhaust stack or at the top of the stack. 

3.2.6 Evaluation of Excess Emissions from Storage Tanks 

Storage tanks are a potentially significant source of emissions due to evaporation 

losses, particularly where intentional boiling or flashing of the product occurs. 

However, other less recognized, and often unnoticed, contributions to atmospheric 

emissions or vapor losses from storage tanks may include the following: 

•	 Leakage of process gas or volatile product past seats of drain or blowdown 

valves into the product header leading to the tanks. 

•	 Inefficient separation of gas and liquid phases upstream of the tanks allowing 

some gas carry-through (by entrainment) to the tanks. This usually occurs 

where inlet liquid production (e.g., produced water) has increased 

significantly overtime resulting in a facility’s inlet separators being undersized 

for current conditions. 

•	 Piping changes resulting in the unintentional placement of high vapor pressure 

product in tanks not equipped with appropriate vapor controls. 

•	 Overheating of storage tanks or rundown of hot product to tanks containing 

volatile material. 

•	 Malfunctioning or improperly set blanket gas regulators and vapor control 

valves can result in excessive blanket gas consumption and, consequently, 

increased flows to the end control device (e.g., vent, flare or vapor recovery 

compressor). The blanket gas is both a carrier of product vapors and a 

potential pollutant itself (i.e., natural gas is usually used as the blanket 

medium for blanketed tanks at gas processing plants). 

•	 Leaking hatches and pressure-vacuum valves is a common problem on tanks 

equipped with gas blanketing systems, and results in direct atmospheric 

emissions of product vapors and blanket gas. 

Contributions of the last two types are accounted for under flare systems and 

fugitive equipment leaks, respectively. Contributions of the other types were 

determined by measuring venting rates (see Section 3.2.3) and comparing the 

observed emissions to calculated working losses for conditions at the time of 

testing. 

14 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

3.2.7 Component Counts 

Equipment component counts were prepared based on an initial review of the 

process and instrumentation drawings, followed by a subsequent walk-though 

inspection of each process unit at the site. In developing these counts, the 

following information was collected for each component: 

•	 type of component (e.g., connectors, valves, control valves, pressure relief 

valves, pressure regulators, orifice meters, other flow meters, blowdowns, 

open-ended lines, etc.), 

•	 component style (e.g., threaded and flanged connections, coupling, ball 

valves, plug valves, globe valve, gate valve, butterfly valve, pump seal, 

compressor seal, regulator, sampling connection, etc.), 

•	 nominal size of the component, 

•	 process temperature and pressure, 

•	 component service (i.e., natural gas, light hydrocarbon liquid), and 

•	 application (i.e., the process stream and unit on which they are used). 

3.2.8 Development of Average Emission Factors 

To determine the average emission factor for each type of component, the 

corresponding aggregate emissions were divided by the number of components. 

Total emissions are the sum of emissions from both leaking and non-leaking 

components. Emission rates for all leaking components (i.e., those with screening 

values of ≥ 10,000 ppm) were quantified using the methods described in Section 

3.2.2. Non-leaking components were assigned the average non-leaking emission 

rates presented in the Protocol for Equipment Leak Emission Estimates (US EPA, 

1995). 

3.2.9 Emission Control Guidelines 

There are currently no regulations or codes of practice that apply specifically to 

the control of methane emissions from fugitive equipment leaks from natural gas 

processing facilities. However, there are requirements for controlling leaks from 

equipment components in VOC service at gas processing plants (40 CFR Part 60, 

Subpart KKK), and for components in VOC and volatile hazardous air pollutant 

(VHAP) service in other industry sectors (e.g., petroleum refining and synthetic 

organic chemical manufacturing). Typically, these regulations require that the 

leak frequency not exceed 2 percent for any group of components excluding 

connectors (which may have a value up to 0.5 percent) and pump and compressor 

seals (which may have a value up to 10 percent). 

15 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

3.3 Cost-Benefit Analysis 

Practicable opportunities for reducing emissions due to fugitive equipment leaks and 

process venting are identified and assessed on a source-by-source basis. The net 

cost/benefit of each identified control option is expressed in dollars per tonne of CO2­

equivalent emission reduction on an annual basis. The information and assumptions 

regarding cost estimating, the value of the gas lost, and repair life used in this analysis are 

summarized below, while the financial discount rate and other financial considerations 

applied in this analysis are summarized in Appendix V. It should be noted that 

implementing a targeted DI&M program designed to quantify methane or total GHG 

opportunities resulted in identifying other hydrocarbon product loss prevention and 

recovery possibilities, further improving the economics of implementing such a program. 

3.3.1 Cost Estimating 

Detection and control costs are assessed on an individual-source or percomponent basis according to the estimated average costs once at the site. True 

costs will vary with the location and layout of the facility, the amount of work to 

be performed, the type of service (i.e., sweet or sour), and the actual repairs or 

control measures required. 

The basic cost to repair or replace a leaking equipment component is estimated 

based on the type and size of the component, typical billing rates quoted by the 

applicable types of service providers (e.g., compressor maintenance and repair 

companies, and valve repair and servicing companies) and the estimated amount 

of labour and materials required. Where possible, both direct and indirect 

contributions to these costs are considered. Direct contributions are the actual 

costs for parts, onsite labour, equipment, tools and disbursements, and are 

summarized in Appendix VI. Indirect contributions are losses in revenues due to 

any associated shutdowns or process interruptions required outside of normally 

scheduled facility turnarounds, and the value of any gas that is vented or flared as 

part of the specified repair or replacement activity. Where indirect costs are 

significant, it is assumed that the work will be left until the next scheduled plant 

turnaround. Otherwise, it is assume that the repairs are made within a short period 

of time following detection and evaluation of the leak. 

It was assumed that a leak, once repaired, will remain fixed for some finite period 

of time, and then will reoccur. The mean time between failures is dependent on 

the type, style and quality of the component, the demands of the specific 

application, component activity levels (e.g., number of valve operations) and 

maintenance practices at the site. The estimated mean time between failures for 

each type of component is provided in Appendix VI. These values are very crude 

estimates based on the experiences of the authors and limited feedback from the 

host facilities. The relatively low mean time between failures for connectors 

reflects wear and tear on these components from inspection and maintenance of 

associated equipment units. In a formal leak detection and repair program, 

16 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

information on mean times between failures is tracked on an ongoing basis and is 

used to identify problem service applications and to evaluate the potential need 

for changes to component specifications and maintenance practices. 

3.3.2 Value of Natural Gas 

The value of natural gas, including vapors from natural gas liquids and propane, is 

taken to be $4.50/mscf based on the long-term contract price of natural gas during 

the fourth quarter of 2000, or approximately $158.95/103 m3 or $4.25/GJ for 

methane. In comparison, the spot price for natural gas at the same time was in 

excess of $7.00/mscf. The market value of natural gas is subject to large 

fluctuations, and operators’ actual economic opportunities are dependent on 

current natural gas prices. 

Overall, the actual value of avoided natural gas losses is very site-specific and 

depends on many factors including the following: 

•	 Local market pricing. 

•	 Impact of emission reductions on specific energy consumption, equipment 

life, workplace safety, and system operability, reliability and deliverability. 

•	 Contract terms. 

•	 Remoteness of the facility. 

•	 Concentration of contaminants and NMHCs in the gas. 

•	 Applicable taxes and tax shields. 

3.3.3 Repair Life 

The mean time between failures is dependent on the type, style and quality of the 

component, the demands of the specific application, component activity levels 

(e.g., number of valve operations) and maintenance practices at the site. Arbitrary 

estimates of the mean time between failures for each type of component are 

provided in Appendix VI. These values are crude estimates and ultimately should 

be updated based on company-specific maintenance experiences. Component- and 

process-specific data for natural gas processing facilities should be compiled. In a 

formal leak detection and repair program, this type of information is tracked on an 

ongoing basis and is used to identify problem service applications and to evaluate 

the potential need for changes to component specifications and maintenance 

practices. 

3.3.4 Cost Curves 

A cost curve is used to show the approximate net cost associated with achieving 

different levels of emission reduction at a site. Each point on the curve represents 

the impact of implementing different emission-reduction measures. The presented 

costs do not account for the expense of finding and evaluating these reduction 

opportunities and, therefore, are slightly low (typically, these costs are small 

17 
 

 

 

 

 

compared to the control costs). Furthermore, the costs are based on a mix of 

facility and vendor supplied data and consensus estimates developed in 

consultation with the facilities. As various control actions have different lifetimes, 

the credited emission reduction for each control option only includes the emission 

reduction achieved in the first year. Control measures that continue to remain in 

effect in subsequent years will have reduced costs per unit of emission reduction. 

18 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

4.0 OVERVIEW OF THE RESULTS 

This section provides an overview of the atmospheric emissions and natural gas losses 

determined for each of the four sites, and delineates the main cost-effective lossreduction opportunities. Additionally, average total hydrocarbon (THC) emission factors 

and leak statistics are presented for fugitive equipment leaks at these facilities. 

Tagged-component information and individual leak rates for all leaking components are 

presented in Appendices I and II. Detailed results of the performance tests done on all 

active combustion sources are provided in Appendix III. 

4.1 Emission Inventory 

Total atmospheric emissions of methane, NMHC and GHG emissions from the four host 

gas processing plants amounted to 5,104.4 and 9,509.3 tonnes per year and 558,527.7 

tonnes CO2E per year, respectively. The relative distributions of these emissions by 

source category are presented in Figures 6 to 8. The carbon dioxide equivalent GHG 

emissions were calculated using the most recent 100-year global warming potentials 

(IPCC, 1996) (i.e., 1.0 for CO2 and 21.0 for CH4). The methane content of the measured 

THC emissions was determined based on typical gas analyses for the site and the analysis 

results for samples collected during the measurement program. Emissions of nitrous 

oxide were not evaluated but would be expected to contribute only a few percent to total 

GHG emissions at each site. 

As shown in Figure 6, fugitive equipment leaks are the dominant source of methane 

emissions, accounting for 82 percent of the total. This is followed by incomplete fuel 

combustion (14.3 percent) incomplete flare gas combustion (1.6 percent), and a small 

amount (2.1 percent) from process vents and storage tanks. 

Storage losses are the major source of NMHC emissions (58.1 percent) although fugitive 

equipment leaks are also a significant contributor (36.9 percent) (see Figure 7). The rest 

(5.0 percent) was contributed primarily by combustion equipment and vents. 

The GHG emissions are predominantly from fuel consumption by combustion equipment 

(79.6 percent) (see Figure 8). However, fugitive equipment leaks (15.7 percent), as well 

as process vents and storage tanks (4.7 percent) may generally offer more cost-effective 

control opportunities. 

19 
Figure 6. Distribution of Methane Emissions by Source Category
 

Flare Systems 

1.6% 

Non-Leaking Components 

0.1% 

Amine Vents 

NRU Vents 0.8%
 

0.5%
 

Storage Tanks Combustion Equipment 0.8% 14.3% 

Leaking Components 

82.0% 

Total Methane Emissions = 5,104.4 tonnes per year 

20 
Figure 7. Distribution of Non-Methane Hydrocarbon Emissions by Source Cate

Amine Vents Flare Systems 2.5% 0.4% 

Non-Leaking Components
 

0.1%
 Combustion Equipment 

1.3% NRU Vents
 

0.8%
 

Leaking Com

36.9

Storage Tanks 

58.1% 

Total NMHC Emissions = 9,509.3 tonnes per year
 

21 
Figure 8. Distribution of Total GHG Emissions by Source Category 

Non-Leaking Components
 

0.03%
 

NRU Vents Flare Systems 

0.1% 1.8% 

Storage Tanks Amine Vents 

2.6% 0.2% 

Leaking Components 

15.7% 

Combustion Eq

79.6% 

Total GHG Emissions = 558,527.7 tonnes CO2E per year 

22 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

4.2 Natural Gas Losses 

A summary of total natural gas losses and their estimated value at the four sites is 

presented in Tables 2 and 3 below. The value of natural gas is taken to be $4.50 per mscf 

(i.e., long-term contract price of natural gas in the fourth quarter of 2000, or 

approximately $158.95/103 m3 or $4.25/GJ for methane). The determined gas losses 

include direct leakage and venting of natural gas to the atmosphere as well as losses into 

the process (e.g., excess fuel consumption by out-of-tune or inefficiently-operated 

engines and heaters, and gas leakage into flare systems). These latter losses lead to 

increased combustion emissions without any net process benefit. 

The relative distribution of natural gas losses by source category is shown in Figure 9. 

Leaking equipment components are the greatest source of natural gas losses at the gas 

plants, accounting for more than 53 percent of the total. Other major sources include 

leakage into flare systems (24.4 percent), storage tanks (11.8 percent) and avoidable 

inefficiencies by combustion equipment (9.9 percent). As shown in Figure 10, most (30 

percent) of the natural gas losses from equipment leaks are attributable to valve leakage 

(both block and control). Connectors, compressor seals and open-ended lines are also 

noteworthy sources, accounting for 24.4, 23.4 and 11.1 percent, respectively, of losses 

from leaking equipment components. The top ten leakers at each site contributed over 

half of the total natural gas losses from fugitive equipment leaks (refer to Table 4). 

4.3 Fugitive Equipment Leaks 

The following subsections characterize the fugitive equipment leaks for components in 

natural gas service at the surveyed gas plants. 

4.3.1 Average Emission Factors 

Average emission factors were determined for each type of equipment component 

in natural gas service at the surveyed sites. The results are presented in Table 5 

and are compared to corresponding factors published by U.S. EPA (1995) for oil 

and gas production operations and by U.S. EPA and GRI (1996) for natural gas 

facilities. Overall, the developed average emission factors are greater than those 

for oil and gas production facilities, and more comparable to the previous values 

for natural gas facilities. 

The average emission factors are simply the total emissions from all tested 

components divided by the total number of components of that type surveyed. 

Quantification of emissions from non-leaking components (i.e., components with 

screening values between zero and 10,000 parts per million) was not attempted. 

Instead, emissions from these components were assumed to be represented by the 

average no-leak emission rates presented in the Protocol for Equipment Leak 

Emission Estimates (U.S. EPA, 1995). 

23 
 

 

 

Table 2. Summary of Natural Gas Losses from the Tested Gas Plants. 

Plant No. 

Natural Gas 

Losses 

(mmscfd) 

Value of 

Gas Lost 

($/y) 

Percent of 

Throughput 1 

1 173.3 285,000 0.27 

2 213.4 351,000 0.29 

3 638.8 1,049,000 0.27 

4 347.5 571,000 0.25 

Combined 1,373 2,256,000 0.27 

1

 Total equivalent gas throughput (i.e., gas sales plus LPG and NGL volumes 

expressed as equivalent gas volumes). 

Table 3. Summary of Natural Gas Losses from Combined Data Gathered at 

Four Surveyed Gas Plants. 

Source 

Gas Losses 

(mscf/y) 

Gross Value 

($/y) 

Leaking Equipment Components 265,161.54 1,193,482 

400 bbl Separator 58,758.74 264,471 

NRU Vents 1,506.54 6,781 

Non-Leaking Equipment Components 436.26 1,964 

Flare Systems 120,811.13 543,766 

Common Blowdown (Vent) Stack 2,507.10 11,284 

Amine Vents 2,574.58 11,588 

Avoidable Fuel Consumption by 

Combustion Equipment 49,374.46 222,233 

Total 501,130.35 2,255,569 

Table 4. Summary of Natural Gas Losses from the Top Ten Leakers1 

. 

Plant No. 

Gas Losses 

from Top 10 

Leakers 

(mscfd) 

Gas Losses 

from all 

Equipment 

Leaks 

(mscfd) 

Percentage 

Contribution 

by Top 10 

Leakers 

Percentage 

of Total 

Leakers 

1 43.8 122.5 35.7 1.78 

2 133.4 206.5 64.6 2.32 

3 224.1 352.5 63.6 1.66 

4 76.5 211.3 36.2 1.75 

Combined 477.8 892.84 53.5 1.85 

24 
1

 Excluding leakage into flare systems. 


25
 
Figure 9. Distribution of Natural Gas Losses by Source Category
 

Combustion Equipment
 

9.9% 

Amine Vents 

0.5% 

Flare Sy

24.4

Leaking Components 

53.1% Non-leakin

NRU Vents 

0.3% 

Storage Tanks 

11.8% 

Total Natural Gas Losses = 501,130 mscf per year 

26 
Figure 10. Distribution of Natural Gas Losses from Equipment Leaks by Type o

Pressure Relief Valves
 

3.5% Pump Seals 

Orifice Meters 1.9% 

0.1% 

Other Flow Meters Pressure Regulators 

0.4% 0.2% Valv

Open-Ended Lines 26.0

11.1% 

Control Valves
 

4.0%
 

Compressor Seals 

23.4% 

Conne

24.4

Crankcase Vents 

4.2% 

Total Natural Gas Losses = 266,100 mscf per year
 

27 
 

 

 

 

 

 

 

 

 

Table 5. Comparison of average THC emission factors derived from data 

collected at the Test Sites to other published values. 

Source 

Average Emission Factors (kg/h/source) 

Test Sites U.S. EPA1 U.S. EPA Gas 

Facilities2,3 

Connectors 2.22e-03 2.0e-04 3.048e-04 

Block Valves 1.10e-02 4.5e-04 3.400e-03 

Control Valves 4.85e-02 4.5e-04 N/A 

Pressure Relief 

Valves 6.73e-02 8.8 e-03 2.238e-03 

Pressure Regulators 1.74e-02 8.8 e-03 N/A 

Orifice Meters 3.58e-03 8.8 e-03 N/A 

Other Flow Meters 2.03e-01 8.8 e-03 N/A 

Crank Case Vents 8.83e-01 N/A N/A 

Open-Ended Lines 5.18e-02 2.0e-03 9.015e-02 

Pump Seals 1.67e-01 2.4e-03 N/A 

Compressor Seals4 8.52e-01 8.8 e-03 1.172e+00 

Blowdowns 8.78e-01 8.8 e-03 5.533e+00 

N/A Emission factor for this source type is not available. 

---­ No components in this category were screened. 

1 Source: U.S. EPA. 1995. Protocol for Equipment Leak Emission Estimates. 

Research Triangle Park, NC 27711. 

2 Source: U.S. EPA and GRI. 1996. Methane Emissions from the Natural Gas 

Industry. Volume 8: Equipment Leaks. Research Triangle Park, NC 27711. 

3 The factors presented in the column are for methane emissions only but should be 

comparable to, although slightly less than, the corresponding THC values for the 

applicable component categories. The factors presented in the other two columns 

are for THC emissions. 

4 Compressor seals component category accounts for emissions from individual 

compressor seals. As compressor seal leakage was typically measured from 

common vent and drain lines, emissions have been divided evenly among the 

seals on units with detected leakage. 

28 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

4.3.2 Average Leak-Rate Trends
 

A statistical analysis of the compiled leak data was performed to identify any 

trends or correlations that could be used to help focus leak detection and control 

efforts. The effects of component type and style, process temperature and 

pressure, component size, application (i.e., type of process unit on which the 

component is used), and type of process stream (e.g., fuel gas, residue gas, acid 

gas, etc) were evaluated. In the following section, the average emission factors are 

given as total hydrocarbons on a kg/h/source basis to be consistent with published 

average emission factors (U.S. EPA, 1995). The main findings are as follows: 

•	 Components in fuel gas service tend to leak more than components in process 

gas service. Additionally, components in sweet gas service leak more than 

those in sour service. This behavior is depicted in Figure 11. Each point on 

Figure 11 denotes the average emission factor for the corresponding type of 

component indicated on the horizontal axis. The integer shown adjacent to 

each emission factor value is the number of data used to develop the factor. 

The vertical line through each average emission factor denotes the 95-percent 

confidence limits based on the variance in the compiled data and number of 

data points assuming a normal distribution. 

•	 The components with the greatest average emissions are crankcase vents on 

reciprocating compressors and compressor engines, compressor seals, and unit 

blowdown systems (see Figure 12). Although not normally identified as a 

source of fugitive emissions, crankcase vents on compressors are a potential 

source of fugitive emissions due to gas leakage from the rod packing case into 

the distance piece and past the rod wiper seals. The presence of process gas in 

the compressor crankcase indicates excessive backpressure on the distance 

piece vent, poor maintenance or performance of the rod wiper seals, or a 

combination thereof. Combustible gas in the crankcase of an engine indicates 

gas leakage past the piston rings in one or more of the engine cylinders. 

Manufacturers of natural gas-fueled compressor engines generally recommend 

that crankcase vents be vented outside the engine room1

. In almost all cases 

observed the vents were discharged inside the building or shelter, although 

these areas were generally well ventilated. In one case the crankcase vent was 

connected to the air intake on the engine. A total of 36 crank case vents were 

tested for emissions: 21 on compressors, 4 on natural gas-fueled engines and 

11 on integral compressor-engine units. As shown in Figure 13 average 

emissions were comparable in all three cases. 

1	 According to one manufacturer, fumes will clog air filters and increase air inlet temperature, 

possibly causing engine damage. Problems in electrical equipment can be caused by exposure to 

the fumes. The fumes can also be a health hazard if discharged in a poorly ventilated room. Fumes 

must not be discharged into air ventilation ducts or exhaust pipes. They will become coated with 

oily deposits creating a fire hazard. 

29 
Figure 11. Average THC Emissions for Connectors by Gas Stream 

Emissions (kg/h/source) 

0.007 

0.006 

0.005 

11 103
 0.004 

0.003 

17 283
 9 154
 

28 417
 

0.002 

0.001 

1 397 2 472 4 814 6 526
 

0.000 

Fuel Gas Residue C3 Process Sour Gas NGL C2 Stab OH C4 

Gas Gas 

30
 
 

 

 

 

 

Figure 12. Average THC Emissions for Compressor Sources, Component Type 

Emissions (kg/h/source) 

0.00 

0.50 

1.00 

1.50 

2.00 

2.50 

3.00 

3.50 

Emissions (kg/h/source) 

1 

22 177 36 

6 

Lube Vent Seals Drain Crank Case Vent Distance Piece Vent Seals Vent 

Figure 13. Average THC Emissions for Crank Case Vents by Type 

2.50 

2.00 

1.50 

1.00 

0.50 

0.00 

4 

21 

11 

CCV-Compressor CCV-Engine CCV-Integral 

31 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

On reciprocating compressors, emissions from the compressor seals are taken 

to be the sum of emissions from the packing case drains, the distance piece 

vents and the lube oil drain tank vent. Aggregate emissions from these sources 

are divided by the number of seals on the unit to determine the average leak 

rate per seal. 

•	 The stem packing on control valves tends to leak more than on block valves. 

Hydra-mechanical governors2 on compressor engines tended to be the most 

leak prone component in control valve service (see Figure 14). 

•	 Components tend to have greater average emissions where subjected to 

frequent thermal cycling (tc), vibrations (v), or cryogenic service (c) (see 

Figures 15 and 16). 

•	 All other parameters had little or no impact on average emissions. 

4.3.3 Leak Frequencies 

For service categories (e.g., VOC and VHAP) and industry sectors (e.g., gas 

processing plants, petroleum refineries and chemical plants) where leak 

monitoring is a regulatory requirement, the required frequency of leak monitoring 

is generally determined based on a facility’s historical leak frequencies. While the 

specific requirements vary with the target industry sector and service category 

(e.g., see 40 CFR Part 60 and 63), fugitive equipment leaks are typically 

considered to be well controlled when the leak frequency for each component 

type (except connectors, compressor and pump seals) is 2 percent or less. For 

connectors, the value is 0.5 percent leakers or less, and for compressor and pump 

seals it is 10 percent leakers or less. Based on these guidelines, none of the 

categories for the combined plants would be considered adequately controlled 

(see Table 6). However, some categories at individual plants exceeded these 

guidelines (i.e., pressure relief valves and regulators at Site 1, regulators at Site 2, 

pump seals, orifice meters and other flow meters at Site 3 and other flow meters at 

Site 4). Compressor seals, crankcase vents, blowdown systems, pump seals, flow 

meters and valves are the most leak prone components. 

The engine governor controls engine speed, and in some generator applications, generator load. 

Hydra-mechanical governors sense engine speed mechanically, and use the engine’s oil pressure 

to hydraulically move the actuator controlling fuel flow to the cylinders. 

32 

2 
 

 

 

 

 

 

 

 

COGEN: RECIP (v) 

NRU (c) 

COMP: RECIP (v) 

DEHY: MOLE (tc) 

HG REMOVAL 

REFRIG: C3 (c, v) 

REFRIG: TURBO (c, v) 

COMP: ELEC (v) 

COMP: TURB (v) 

SALES 

SWEETN: AMINE 

FRAC: DEEPCUT (c) 

DEHY: TEG 

INLET SEPARATION 

STORAGE NGL 

STABILIZER 

UTILITIES 

COGEN: TURB (v) 

VRU: ELEC (v) 

CLAUS 

Figure 14. Average THC Emissions for Control Valves by Component Type 

Emissions (kg/h/source) 

Emissions (kg/h/source) 

0.90 

0.80 

0.70 

0.60 

0.50 

0.40 

0.30 

0.20 

0.10 

0.00 

48 

66 

71 

217 80 335 423 

Governor Control Valve Butterfly Ball Plug Injection Valve Globe 

Figure 15. Average THC Emissions for Connectors by Process Unit 

0.0150 

0.0200 

0.0250 

0.0300 

215 

11 842 1 295 

11 110 

2 218 

304 

17 931 

5 595 

823 

260 

3 7122 564 2 727 1 588 

12 549

977 

3 085 2 654 1 295 

194 

0.0100 

0.0050 

0.0000 

33 

 

 

 

 

 

 

 

 

 

NRU (c) 

COMP: RECIP (v) 

REFRIG: C3 (c, v) 

DEHY: MOLE (tc) 

NGL Storage 

REFRIG: TURBO (c, v) 

COMP: TURB (v) 

COGEN: RECIP (v) 

DEHY: TEG 

COGEN: TURB (v) 

INLET SEPARATION 

FRAC: DEEPCUT (c) 

UTILITIES 

HG REMOVAL 

SALES 

SWEETN: AMINE 

STABILIZER 

COMP: ELEC (v) 

VRU: ELEC (v) 

CLAUS 

Figure 16. Average THC Emissions for Valves by Process Unit 

0.0000 

0.0100 

0.0200 

0.0300 

0.0400 

0.0500 

0.0600 

0.0700 

0.0800 

Emissions (kg/h/source)

324 

570 

451 

981 

1 509 

2 362 

3 433 

387 157 

41 

173 

975 

761 816 

503 

99 

792 

35 

2 017 

26 

35
 
Table 6. Number of components and leak frequency at each of the four gas plants. 

Compone nt 

Site 1 Site 2 Site 3 Site 4 

Total Leaker 

s 

Leak 

Freq. 

Total Leaker 

s 

Leak 

Freq. 

Total Leaker 

s 

Leak 

Freq. 

Total Leaker 

s 

Leak 

Freq. 

Connector s 

12,93 

6 222 1.71 

12,19 

1 219 1.80 

46,13 

4 397 0.86 

10,88 

5 187 1.72 

Block Valves 

2, 

427 237 9.77 1,567 134 8.55 8,771 453 5.16 2,371 249 10.50 

Control Valves 170 35 20.59 241 47 19.50 632 32 5.06 197 27 13.71 Pressure Relief Valves 70 1 1.43 48 4 8.33 219 5 2.28 48 1 2.08 Regulator s 29 0 0.00 11 0 0.00 108 4 3.70 21 2 9.52 Orifice Meters 11 1 9.09 34 3 8.82 80 0 0.00 42 7 16.67 Other Meters 5 1 20.00 0 --­ --­ 1 0 0.00 1 0 0.00 

Crankcase Vents 6 6 100 5 5 100 20 9 45.00 5 5 100 

Openended Lines 366 40 10.93 301 19 6.31 384 26 6.77 559 73 13.06 Pump Seals 29 8 27.59 

0 --­ --­ 48 4 8.33 6 1 16.67 

Compress or Seals 22 22 100 40 40 100 92 54 58.70 51 51 

100.0 

0 

36 
Blowdow 

n Systems 0 --­ --­ 0 --­ --­ 6 2 33.33 0 --­ --­ Total 

16,07 

3 

562 3.50 14,43 

8 

465 3.22 56,49 

6 

950 1.68 14,18 

6 

594 4.20 

37 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

4.3.4 Component Counts 

Prior to the start of the fieldwork, each host facility provided estimated counts of 

the total number of components in natural gas service at their site. During the 

fieldwork actual component counts were developed for these facilities. It is 

noteworthy that the plant estimates were generally much lower than the field 

counts as shown in Figure 17. On average the component counts were estimated 

at approximately 60 percent of the actual counts. One explanation is that the 

component counts supplied by facilities were intended to reflect total numbers of 

components in hydrocarbon gas and liquid service but likely would have excluded 

components less than 0.5” nominal pipe size (per Method 21). Overall, 13.8 

percent of these component counts are components less than 0.5” nominal pipe 

size. The component counts are not complete for Sites 1, 2, and 4 since not all 

components in hydrocarbon liquid service were counted at these locations. This 

would tend to make the discrepancy even greater. It is likely that the facilities 

developed their counts largely from process drawings and did not have sufficient 

detail to capture all components. 

A summary of the average component schedules by type of process unit is 

presented in Appendix IV. 

4.4 Control Opportunities 

Practicable opportunities for reducing the identified natural gas losses were identified and 

assessed on a source-by-source basis. Overall, it is estimated that up to 94.9 percent of 

total natural gas losses could be avoided if all control opportunities with zero net cost or a 

positive payback are implemented (see Figure 18). This would result in corresponding 

reductions of 78.1 percent in methane emissions, 16.3 percent in GHG emissions, and 

88.5 percent in NMHC emissions in the first year alone. Moreover, many of the control 

options have multi-year life expectancies resulting in significant emission reductions in 

subsequent years as well. 

4.4.1 Cost Curve for Reduction of GHG Emissions 

To further evaluate the control of natural gas losses as a means of reducing GHG 

emissions, it is useful to express the results in terms of a cost curve. Figure 19 

presents the net annualized cost curve for implementation of the various 

opportunities identified at the four gas plants based on a value of $4.50 per mscf 

for the conserved natural gas. The net cost of each target control opportunity is 

calculated as the equalized annual implementation cost over the life of the project 

(i.e., the net present cost of the opportunity expressed as an equivalent series of 

equal annual payments over the life of the project) divided by the resulting 

average annual CO2-equivalent emission reduction. 

38 
 

 

 

Number of Components

Figure 17. Comparison of Company Estimates to Actual Number of
 

Components 1 

120,000 

100,000 

80,000 

60,000 

40,000 

20,000 

0 

16,073 14,438 

56,496 

14,186 

101,193 

59,778 

45,000 

5,000 2,988 

6,790 

Site #1 Site #2 Site #3 Site #4 Total 

Estimate 

Actual 

1	 Components of less than 0.5 inch nominal pipe size constitute 13.8 percent of 

the actual component counts. Company estimates may have excluded 

components less than 0.5 inch nominal pipe size (per Method 21). 

39 
 

 1 Figure 18. Emissions from Economically Repairable Sources

Natural Gas Losses (mscfd)

Total Emissions 

Repairable Sources 

1,600 

94.9 % 

1,400 

1,200 

1,000 

800 

600 

400 

200 

0
 

Site #1 Site #2 Site #3 Site #4 Overall
 

94.5 % 

96.7 % 

92.3 % 95.0 % 

1	 Based on the long term contract price for natural gas during the fourth quarter 

of 2000 of $4.50 per mscf. 

40 
Net Cost ($/t CO

2E Reduction) 

500 400 300 200 100 

-100 

0 

0 20000 40000 60000 80000 

-200 -300 -400 -500 

Figure 19. Net cost curve for cumulative CO2 E emission reductions at surveyed gas p

Cumulative GHG Emission Reduction (tonnes CO2 E) 

Note. The cost of finding and evaluating these emission reduction opportunities is excluded. 

41
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Figure 19 shows that the incremental cost per tonne of CO2E GHG emission 

reduction resulting from implementation of the available control opportunities in 

ranked order from most to least cost effective (i.e., see Table II-1 in Appendix II). 

The point at which the curve crosses over the abscissa axis (i.e., the axis of 

cumulative CO2E GHG emission reduction) is the amount of CO2E emission 

reduction that could be achieved if only opportunities with a zero cost or a 

positive payback are implemented (i.e., 92,622.4 tonnes CO2E reduction per 

year). This reduction amounts to 16.6 percent of total estimated GHG emissions 

from the four gas plants. 

If a value is assigned to GHG emission reduction credits, then companies may 

choose to pursue opportunities even further out on the cost curve. The shape of 

the cost curve shows that there are a few very attractive control opportunities, a 

large number of moderate control opportunities, and eventually a point of 

diminishing returns. 

4.4.2 Control Opportunities With a Payback of 1 Year or Less 

On a purely financial basis, opportunities to reduce natural gas losses must 

compete against other investment opportunities to receive funding. A common 

parameter used to evaluate opportunities is either the effective rate of return on 

the investment or the payback period. To justify equipment upgrades or process 

enhancements, companies often look for a payback period of 1 year or less. 

Accordingly, it is useful to consider only opportunities to reduce natural gas 

losses that have a payback period of 1 year or less. 

If only these control opportunities are implemented, it is estimated that total 

natural gas losses, including unnecessary fuel consumption, would be reduced by 

92.3 percent. Corresponding reductions in methane and GHG emissions would 

amount to 78.1 and 16.3 percent, respectively. Additionally, significant reductions 

in NMHC emissions would be achieved. 

The 10 greatest individual control opportunities in the 1-year payback category 

are listed in Table 7. Collectively, they account for 49.6 percent of total natural 

gas losses in this category and 45.8 percent of total natural gas losses irrespective 

of payback period. The single largest source in the 1-year payback category and 

overall is leakage into the high-pressure flare system at Site 3. 

Losses into flare systems may be minimized by either implementing a flare gas 

recovery system, or targeting the individual sources of the residual gas flow. The 

latter approach can be difficult to implement since causes are often difficult to 

isolate, usually require a major plant shutdown to fix (i.e., resulting in significant 

indirect costs), and are likely to reoccur. Likely candidates are excess purge gas, 

leaking pressure-relief devices, drains and blowdown valves and compressor startgas vents that are connected to the flare header. 

44 
 

 

 

Table 7. Summary of top ten sources of natural gas losses identified. 

Tag Location Source 

Type / Description 

Loss

 Rate 

(mscfd) 

Value of 

Lost Gas 

($/y) 

High-Pressure Flare System, 

Site 3 Residual Flaring 175.397 288,150 

Direct Oil-Water Separator Tank, 

Site 3 

Flashing Losses / 

Venting through Thief 

Hatch 

160.983 264,471 

Flare System, Site 4 Residual Flaring 121.144 199,021 

Direct Compressor Unit 3, Site 2 Compressor seals vent 86.110 141,486 

Direct Residue Gas Comp 4, Site 3 Compressor Seals (4) 22.526 37,007 

Re-Compressor Unit 5, Site 

3 

Unburned Fuel and 

Excess Fuel 

Consumption 

12.743 20,930 

Re-Compressor Unit 3, Site 

3 

Unburned Fuel and 

Excess Fuel 

Consumption 

11.682 19,187 

3824 Re-compressor Yard Piping, 

Site 4 

Plug Valve – leakage 

through valve body at 

bottom 

11.544 18,694 

3910C Re-compressor Unit 3, Site 4 Union – Fuel Gas Line 6 11.100 18,236 

East Heat Medium Heater, 

Site 3 

Unburned Fuel and 

Excess Fuel 

Consumption 

10.652 17,496 

Total 623.881 1,024,678 

45 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

5.0 CONCLUSIONS AND RECOMMENDATIONS
 

5.1 Conclusions 

The sources with the greatest natural gas losses were not necessarily the most economical 

to control. Based on the compiled test results, the greatest opportunities for cost-effective 

reduction of natural gas losses are from the control of leaking equipment components and 

leakage of process gas into vent and flare systems. However, actual opportunities may 

vary greatly between sites and not all gas plants will necessarily offer sufficient 

opportunities to justify the associated identification and control costs. In addition, actual 

economic opportunities are dependent on the value of natural gas, and will therefore vary 

with fluctuations in the market price of natural gas. Nonetheless, it is clear from the 

available data that significant opportunities do exist at some facilities and a rational 

approach to finding these opportunities may be economically attractive to industry. 

While any economical-to-repair leaking components detected by such efforts should be 

repaired, average leak rates based on combined data from the four test sites suggest that 

the most cost-effective approach would be to generally focus on the following types of 

components: 

•	 block and control valves, 

•	 pressure relief valves, 

•	 regulators, 

•	 flange connections, 

•	 crankcase vents, 

•	 compressor seals, and 

•	 compressor valve stems and valve caps. 

Normally, flange connections would not be expected to be a key contributor at gas 

facilities. Their relative importance here is attributed to the use of mole sieve dehydrators 

at each of the sites, and the corresponding high leak potential in these applications (i.e., 

due to the thermal cycling of the mole sieve beds). 

5.2 Recommendations 

Specific recommendations for further work are as follows: 

•	 Additional facility surveys should be conducted to determine the impact of 

facility age on the extent of cost-effective opportunities for reducing natural gas 

losses at gas processing plants. Additionally, the extent of opportunities at 

upstream facilities should be investigated (e.g., at gas-gathering compressor 

stations, gas batteries and well-site dehydration and metering facilities). 

•	 The amount and composition of emissions from engine and compressor crankcase 

vents, and field practices for the design of these vent systems, should be examined 

more closely. In particular, the potential for air-toxic emissions from crankcase 

46 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

vents, especially those on engines, should be determined. Moreover, the practice 

of some companies to allow crankcase vents to exhaust into buildings and work 

areas, a practice manufacturers discourage, should be evaluated. 

•	 There are a wide variety of available technologies as well as design and operating 

practices that would benefit companies in cost effectively reducing natural gas 

losses, however, these technologies and practices are under-utilized. One such 

example is the application of flow sensors, which can be installed on compressor 

seal vents at a relatively low cost. Flow sensors allow easy on-going detection of 

excessive leakage, and may also be applicable to crankcase and other vents. Only 

one of the four sites had installed seal vent flow sensors, and operators did not 

take advantage of the readings from these sensors. Additionally, emergency flare 

systems normally are not equipped with flow meters, so in-leakage and excessive 

purge gas consumption often goes unnoticed until losses produce a noticeably 

enlarged flame size. Historically, meters were not installed because conventional 

obstruction meters do not provide reliable readings over the wide flow ranges 

required and cause excessive backpressure in the system. Today, non-intrusive 

ultrasonic flow meters are available which overcome these problems. Moreover, 

ultrasonic techniques are available for identifying and quantifying leakage past 

valve seats into flare and vent systems. 

It is recommended that a best practices document be developed to better 

disseminate and encourage the compilation and use of this type of information. 

The document could also provide information needed by companies to develop 

site-specific programs for reducing their methane and non-methane hydrocarbon 

losses and greenhouse gas emissions (e.g., delineation of source categories or 

facility areas to focus efforts on for maximum benefit, generic cost data for 

evaluating control options, recommended frequency of monitoring efforts, and the 

typical life expectance of repairs by source type and service category). 

47 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

6.0 REFERENCES CITED 

Howard, T., R. Siverson, A. Wenzlick and B. Lott. 1994. A High Flow Rate Sampling 

System for Measuring Emissions from Leaking Process Components. Presented at the 

1994 International Workshop on Environmental Impacts of Natural Gas Losses, Prague, 

Czech Republic. 

Lott, B., T. Howard and M. Webb. 1995. New Techniques Developed for Measuring 

Fugitive Emissions. Pipe Line and Gas Industry, v 75, n10, October 1995. 

IPCC. 1996. Climate Change 1995: The Science of Climate Change. Cambridge 

University Press. New York, NY. pp.572. 

U.S. EPA (Environmental Protection Agency). 1995. Protocol for Equipment Leak 

Emission Estimates. Available through NTIA. Springfield VA. Publication No. EPA453/R-95-017. Section 2. 

U.S. EPA (Environmental Protection Agency) and GRI. 1996. Methane Emissions from 

the Natural Gas Industry. Volume 8: Equipment Leaks. Available through NTIA. 

Springfield VA. Publication No. EPA-600/R-96-080h. 

U.S. EPA (Environmental Protection Agency). 1997. Method 21 – Determination of 

Volatile Organic Compound Leaks. Available on the EPA website. 

(www.epa.gov/ttn/emc/promgate.html) 

U.S. EPA (Environmental Protection Agency). and GRI (Gas Research Institute).1996. 

Methane Emissions from the Natural Gas Industry Volume 8: Equipment Leaks. Report 

No. EPA-600/R-96-080h. Research Triangle Park, NC. 

48 
Appendix I 

*Site specific field measurement data for this appendix have been removed to protect 

business confidentiality. Please direct any questions to Roger Fernandez, EPA at 

fernandez.roger@epa.gov or (202) 343-9386. 

49 
Appendix II 

*Site specific field measurement data for this appendix have been removed to protect 

business confidentiality. Please direct any questions to Roger Fernandez, EPA at 

fernandez.roger@epa.gov or (202) 343-9386. 

50 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Appendix III 

Combustion Analysis and Efficiency Testing Results 

The compiled combustion data were input into a database to facilitate the calculation of 

the required parameters. Measured fuel and exhaust gas compositions were used to 

determine the air-to-fuel and exhaust-to-fuel ratios. Species mole balances and the 

following simple combustion relation were used: 

Fuel + a · Air → b · Flue + d · H2O 

A carbon mole balance was used to determine b, a nitrogen balance to determine a and a 

hydrogen balance to determine d. These coefficients were then used to determine the flow 

rates of the unknown streams from the known flow. 

Combustion efficiency is defined as the total enthalpy contained in the reactants minus 

the total enthalpy contained in the products divided by the energy content of the fuel. 

This may be written as follows: 

f f f (m& ⋅h − ⋅ FUEL FUEL + m& AIR ⋅hAIR m& FLUE hFLUE )
 m& FUEL ⋅LHV
 

m& is the molar flow rate of the stream (i.e., fuel, air, or flue gas) (kmole/h), 

h f 

is the heat of formation of the stream (MJ/kmole), and 

LHV is the lower heating value of the fuel gas stream (MJ/kmole) 

For ideal operation, combustion efficiencies calculated with this equation are expected to 

be in the range of 95 to 98 percent. 

While combustion efficiency is useful in demonstrating how much of the energy in the 

fuel is converted to heat, it does not provide a complete description of how effectively the 

equipment is utilizing this energy. An energy balance on a typical reciprocating engine 

yields the following (based on manufacturers’ heat load data): 

• Energy from Fuel 100 % 

• Useful Work 30 to 35 % 

• Jacket Water and Oil Cooler 15 to 40 % 

• Radiation 3.5 to 7.5 % 

• Turbocharger After Cooler 1 to 6 % 

• Exhaust 20 to 35 % 

The heat loads for jacket water, oil cooler, turbocharger after cooler and radiation are 

typically determined by design or safe operating conditions. Heat lost to exhaust is a 

function of combustion efficiency and the quantity of combustion air that is required for 

efficient operation. Useful work is whatever is left over after all losses have been 

51 
 

 

 

 

 

 

 

 

 

 

 

 

 

accounted. Since heat losses to jacket water, oil cooler, turbocharger after cooler and 

radiation are typically fixed by design, the amount of heat lost up the stack is a good 

indication of whether or not the unit is being operated in an efficient manner. 

The situation is similar, although less complicated, for heaters/boilers and gas turbine 

engines. For heaters and boilers: 

• Energy from Fuel 100 % 

• Useful Work 70 to 85 % 

• Radiation 2 to 5 % 

• Exhaust 15 to 25 % 

And for gas turbines: 

• Energy from Fuel 100 % 

• Useful Work 30 to 40 % 

• Radiation 2 to 5 % 

• Exhaust 60 to 70 % 

Stack heat losses have been calculated using a simplified heat balance. The equation used 

is: 

Stack Losses Fraction of Heat Lost = Heat Input 

where 

Heat Input = Energy Content of Fuel + Sensible Heat in Fuel 

+ Sensible Heat in Combustion Air 

Stack Losses = Energy Content of the Exhaust Gas 

+ Convective Stack Losses 

+ Sensible Heat in the Exhaust Gas 

The costs associated with the improper operation of combustion units are made up of two 

components: the value of any unburned fuel in the exhaust gas and the incremental fuel 

associated with operating at excessive air-to-fuel ratios. The former is determined by 

calculating the heating value of the unburned or partially burned components of the 

exhaust gas and assigning a value per GJ of energy equal to that of natural gas. 

The cost associated with too much excess air is determined by comparing the measured 

air-to-fuel ratio with typical manufacturers’ values. The loss is then calculated by 

determining the amount of heat required to heat the excess air from ambient temperature 

to the exhaust stack temperature. 

52 
 

The optimum air-to-fuel ratio varies significantly for reciprocating engines according to 

make and model of unit. Accordingly, specific manufacturers’ values were used wherever 

possible. In the absence of manufactures’ data, average values for the types of units tested 

were used. For heaters and boilers, 15 percent excess air was assumed to be sufficient for 

proper operation. 

53 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 1
 

Equipment Information 

Unit Identifier: Refrigerant Compressor 10 

Engine Make and Model: Clark – HRA 8 

Compressor Cylinders: 4 Stages: 2 

Driver Cylinders: 8 Rated Power: 

NOTE:Refrigeration Compressor Unit 10 is operated but a few days per year for peak 

shaving during the summer months, therefore, the cost of improper operation is expressed 

in $ per day rather than $ per year to reflect the limited number days per year the unit is 

in operation. 

Measured Exhaust Gas Composition 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 50 000 

Oxygen (O2) 123 000 

Carbon Monoxide (CO) 967 

Nitrous Oxide (NO) 1 415 

Nitrogen Dioxide (NO2) 609 

Oxides of Nitrogen (NOx) 2 024 

Hydrocarbons (THC) 0 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3

/h) 259 

Air Flow (m3/h) 5 167 

Exhaust Flow (m3/h) 5 381 

Combustion Efficiency1 (%) 97.3 

Stack Heat Losses2 (%) 45.65 

Unburned Fuel (%) 1.24 

1 Air-to-fuel ratio of 10.5. 


2 For well-tuned compressor engines stack heat losses should be in the range of 20 


to 35 percent. 


Combustion Emission Factors 

Pollutant kg/103 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 827 48 806 

Carbon Monoxide (CO) 20.1 738 

Oxides of Nitrogen (NOx) 0.251 6.80 

Hydrocarbons (THC) 0.00 0 

54 
 

Cost of Unnecessary Excess Air: $163 

Value of Unburned Fuel: $6 

Total Cost of Improper Operation:$169 

Volume of Unnecessary Fuel Consumption: N/A 

55 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 1 

Equipment Information 

Unit Identifier: Refrigerant Compressor 11 

Engine Make and Model: Ingersol Rand – KVG 

Compressor Cylinders: 4 Stages: 2 

Driver Cylinders: 10 Rated Power: 

Measured Exhaust Gas Composition 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 114 000 

Oxygen (O2) 11 000 

Carbon Monoxide (CO) 2663 

Nitrous Oxide (NO) 961 

Nitrogen Dioxide (NO2) 31 

Oxides of Nitrogen (NOx) 991 

Hydrocarbons (THC) 9 400 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3/h) 259 

Air Flow (m3

/h) 2 513 

Exhaust Flow (m3

/h) 2 753 

Combustion Efficiency1

 (%) 96.7 

Stack Heat Losses2

 (%) 26.01 

Unburned Fuel (%) 2.25 

1 Air-to-fuel ratio of 10.5. 


2 For well-tuned compressor engines stack heat losses should be in the range of 20 


to 35 percent. 


Combustion Emission Factors 

Pollutant kg/103

 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 799 48 637 

Carbon Monoxide (CO) 24.35 658.1 

Oxides of Nitrogen (NOx) 9.88 267.0 

Hydrocarbons (THC) 5.55 150.0 

Cost of Unnecessary Excess Air: $0 

Value of Unburned Fuel: $4 877 

56 
Total Cost of Improper Operation:$4 877 

Volume of Unnecessary Fuel Consumption: 5.037 mscfd 

57
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 1 

Equipment Information 

Unit Identifier: Refrigerant Compressor 12 

Engine Make and Model: Waukesha 

Compressor Cylinders: 4 Stages: 2 

Driver Cylinders: 12 Rated Power: 

Measured Exhaust Gas Composition 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 120 000 

Oxygen (O2) 0 

Carbon Monoxide (CO) 2 428 

Nitrous Oxide (NO) 1 124 

Nitrogen Dioxide (NO2) 0 

Oxides of Nitrogen (NOx) 0 

Hydrocarbons (THC) 1 124 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3

/h) 259 

Air Flow (m3/h) 2 370 

Exhaust Flow (m3/h) 2 611 

Combustion Efficiency1 (%) 95.2 

Stack Heat Losses2 (%) 19.86 

Unburned Fuel (%) 3.56 

1 Air-to-fuel ratio of 10.5. 


2 For well-tuned compressor engines stack heat losses should be in the range of 20 


to 35 percent. 


Combustion Emission Factors 

Pollutant kg/103 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 775 47 975 

Carbon Monoxide (CO) 20.8 561 

Oxides of Nitrogen (NOx) 10.30 278 

Hydrocarbons (THC) 16.43 444 

Cost of Unnecessary Excess Air: $0 

Value of Unburned Fuel: $9 420 

58 
Total Cost of Improper Operation:$9 420 

Volume of Unnecessary Fuel Consumption: 7.951 mscfd 

59
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 1 

Equipment Information 

Unit Identifier: Solar Turbine CM-503 

Engine Make and Model: Solar Turbine 

Rated Power: 

Measured Exhaust Gas Composition 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 24 000 

Oxygen (O2) 168 000 

Carbon Monoxide (CO) 51 

Nitrous Oxide (NO) 71 

Nitrogen Dioxide (NO2) 0 

Oxides of Nitrogen (NOx) 71 

Hydrocarbons (THC) 0 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3/h) 1 053 

Air Flow (m3

/h) 40 463 

Exhaust Flow (m3/h) 40 848 

Combustion Efficiency1

 (%) 98.2 

Stack Heat Losses2

 (%) 52.69 

Unburned Fuel (%) 0.13 

1 Air-to-fuel ratio of 40. 


2 In the absence of heat recovery, turbine stack heat losses should be in the range of
 

60 to 70 percent. 


Combustion Emission Factors 

Pollutant kg/103

 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 867 50 464 

Carbon Monoxide (CO) 2.17 58.5 

Oxides of Nitrogen (NOx) 3.23 87.3 

Hydrocarbons (THC) 0 0 

Cost of Unnecessary Excess Air: $0 

Value of Unburned Fuel: $860 

Total Cost of Improper Operation:$860 

60 
Volume of Unnecessary Fuel Consumption: 1.193 mscfd 


61
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 1 

Equipment Information 

Unit Identifier: Solar Turbine CM-504 

Engine Make and Model: Solar Turbine 

Rated Power: 

Measured Exhaust Gas Composition 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 23 000 

Oxygen (O2) 170 000 

Carbon Monoxide (CO) 21 

Nitrous Oxide (NO) 50 

Nitrogen Dioxide (NO2) 0 

Oxides of Nitrogen (NOx) 50 

Hydrocarbons (THC) 0 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3/h) 1 053 

Air Flow (m3

/h) 41 997 

Exhaust Flow (m3/h) 42 664 

Combustion Efficiency1

 (%) 98.2 

Stack Heat Losses2

 (%) 52.17 

Unburned Fuel (%) 0.06 

1 Air-to-fuel ratio of 40. 


2 In the absence of heat recovery, turbine stack heat losses should be in the range of
 

60 to 70 percent. 


Combustion Emission Factors 

Pollutant kg/103

 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 870 50 545 

Carbon Monoxide (CO) 0.934 25.3 

Oxides of Nitrogen (NOx) 2.38 64.4 

Hydrocarbons (THC) 0 0 

Cost of Unnecessary Excess Air: $0 

Value of Unburned Fuel: $371 

Total Cost of Improper Operation:$371 

62 
Volume of Unnecessary Fuel Consumption: 0.515 mscfd 


63
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 1
 

Equipment Information 

Unit Identifier: High Pressure Inlet Compressor CM-19 

Engine Make and Model: 

Compressor Cylinders: Stages: 

Driver Cylinders: Rated Power: 

Measured Exhaust Gas Composition
 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 120 000 

Oxygen (O2) 0 

Carbon Monoxide (CO) 12 

Nitrous Oxide (NO) 1499 

Nitrogen Dioxide (NO2) 8 

Oxides of Nitrogen (NOx) 1507 

Hydrocarbons (THC) 900 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3

/h) 267 

Air Flow (m3/h) 2 501 

Exhaust Flow (m3/h) 2 7471 

Combustion Efficiency1 (%) 97.5 

Stack Heat Losses2 (%) 24.32 

Unburned Fuel (%) 0.60 

1 Air-to-fuel ratio of 10.5. 


2 For well-tuned compressor engines stack heat losses should be in the range of 20 


to 35 percent. 


Combustion Emission Factors 

Pollutant kg/103 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 841 49 760 

Carbon Monoxide (CO) 104.6 2.83 

Oxides of Nitrogen (NOx) 14.1 381 

Hydrocarbons (THC) 4.23 114 

Cost of Unnecessary Excess Air: $0 

Value of Unburned Fuel: $1 972 

64 
Total Cost of Improper Operation:$1 972 

Volume of Unnecessary Fuel Consumption: 1.378 mscfd 

65
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 1
 

Equipment Information 

Unit Identifier: Low Pressure Inlet Compressor CM-13 

Engine Make and Model: White Superior 825GTL 

Compressor Cylinders: Stages: 

Driver Cylinders: Rated Power: 

Measured Exhaust Gas Composition
 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 73 000 

Oxygen (O2) 83 000 

Carbon Monoxide (CO) 207 

Nitrous Oxide (NO) 1 246 

Nitrogen Dioxide (NO2) 272 

Oxides of Nitrogen (NOx) 1 518 

Hydrocarbons (THC) 3 200 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3

/h) 267 

Air Flow (m3/h) 3 704 

Exhaust Flow (m3/h) 3 939 

Combustion Efficiency1 (%) 95.0 

Stack Heat Losses2 (%) 29.16 

Unburned Fuel (%) 3.01 

1 Air-to-fuel ratio of 28. 


2 For well-tuned compressor engines stack heat losses should be in the range of 20 


to 35 percent. 


Combustion Emission Factors 

Pollutant kg/103 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 795 48 527 

Carbon Monoxide (CO) 2.92 78.8 

Oxides of Nitrogen (NOx) 25.1 678 

Hydrocarbons (THC) 20.2 547 

Cost of Unnecessary Excess Air: $0 

Value of Unburned Fuel: $9 679 

66 
Total Cost of Improper Operation:$9 679 

Volume of Unnecessary Fuel Consumption: 6.929 mscfd 

67
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 1
 

Equipment Information 

Unit Identifier: Low Pressure Inlet Compressor CM-14 

Engine Make and Model: White Superior 825GTL 

Compressor Cylinders: Stages: 

Driver Cylinders: Rated Power: 

Measured Exhaust Gas Composition
 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 67 000 

Oxygen (O2) 94 000 

Carbon Monoxide (CO) 189 

Nitrous Oxide (NO) 357 

Nitrogen Dioxide (NO2) 30 

Oxides of Nitrogen (NOx) 387 

Hydrocarbons (THC) 3 300 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3

/h) 267 

Air Flow (m3/h) 3 969 

Exhaust Flow (m3/h) 4 201 

Combustion Efficiency1 (%) 94.7 

Stack Heat Losses2 (%) 31.88 

Unburned Fuel (%) 3.43 

1 Air-to-fuel ratio of 28. 


2 For well-tuned compressor engines stack heat losses should be in the range of 20 


to 35 percent. 


Combustion Emission Factors 

Pollutant kg/103 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 788 48 319 

Carbon Monoxide (CO) 2.89 78.0 

Oxides of Nitrogen (NOx) 6.59 178 

Hydrocarbons (THC) 23.29 629 

Cost of Unnecessary Excess Air: $0 

Value of Unburned Fuel: $11 085 

68 
Total Cost of Improper Operation:$11 085 

Volume of Unnecessary Fuel Consumption: 7.904 mscfd 

69
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 1 

Equipment Information 

Unit Identifier: TEG Reboiler
 

Boiler Make and Model:
 

Rated Power:
 

Measured Exhaust Gas Composition 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 72 000 

Oxygen (O2) 34 000 

Carbon Monoxide (CO) 9 

Nitrous Oxide (NO) 60 

Nitrogen Dioxide (NO2) 0 

Oxides of Nitrogen (NOx) 60 

Hydrocarbons (THC) 0 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3/h) 15.3 

Air Flow (m3

/h) 165.1 

Exhaust Flow (m3/h) 178.9 

Combustion Efficiency1

 (%) 98.3 

Stack Heat Losses (%) 33.50 

Unburned Fuel (%) 0.01 

Thermal Efficiency (%) 66.5 

1 Typical excess air of 15 percent. 

Combustion Emission Factors 

Pollutant kg/103

 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 853 50 098 

Carbon Monoxide (CO) 93.6 2.53 

Oxides of Nitrogen (NOx) 0.669 18.1 

Hydrocarbons (THC) 0 0 

Cost of Unnecessary Excess Air: $519 

Value of Unburned Fuel: $1 

Total Cost of Improper Operation:$520 

Volume of Unnecessary Fuel Consumption: 0.317 mscfd 

70 
71
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 3 


Equipment Information 

Unit Identifier: IR Compressor – Unit #1 G-41066/352587 

Engine Make and Model: Waukesha – L7042GSIU 

Compressor Cylinders: 4 Stages: 3 

Driver Cylinders: 12 Rated Power: 1100 kW 

Measured Exhaust Gas Composition
 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 120 000 

Oxygen (O2) 0 

Carbon Monoxide (CO) 3 137 

Nitrous Oxide (NO) 27 

Nitrogen Dioxide (NO2) 0 

Oxides of Nitrogen (NOx) 27 

Hydrocarbons (THC) 0 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3

/h) 229 

Air Flow (m3/h) 2 124 

Exhaust Flow (m3/h) 2 339 

Combustion Efficiency1 (%) 97.5 

Stack Heat Losses2 (%) 23.05 

Unburned Fuel (%) 1.66 

1 Air-to-fuel ratio of 10.5. 


2 For well-tuned compressor engines stack heat losses should be in the range of 20 


to 35 percent. 


Combustion Emission Factors 

Pollutant kg/103 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 801 48 806 

Carbon Monoxide (CO) 27.2 738 

Oxides of Nitrogen (NOx) 0.251 6.80 

Hydrocarbons (THC) 0.00 0 

Cost of Unnecessary Excess Air: $0 

Value of Unburned Fuel: $2 346 

Total Cost of Improper Operation:$2 346 

72 
Volume of Unnecessary Fuel Consumption: 3.155 mscfd 


73
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 3
 

Equipment Information 

Unit Identifier: IR Compressor – Unit #2 G-42003/352241 

Engine Make and Model: Waukesha – L7042GSIU 

Compressor Cylinders: 4 Stages: 3 

Driver Cylinders: 12 Rated Power: 1100 kW 

Measured Exhaust Gas Composition
 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 120 000 

Oxygen (O2) 0 

Carbon Monoxide (CO) 164 

Nitrous Oxide (NO) 96 

Nitrogen Dioxide (NO2) 0 

Oxides of Nitrogen (NOx) 96 

Hydrocarbons (THC) 1 288 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3/h) 183 

Air Flow (m3

/h) 1 690 

Exhaust Flow (m3

/h) 1 860 

Combustion Efficiency1

 (%) 97.3 

Stack Heat Losses2

 (%) 20.61 

Unburned Fuel (%) 0.95 

1 Air-to-fuel ratio of 10.5. 


2 For well-tuned compressor engines stack heat losses should be in the range of 20 


to 35 percent. 


Combustion Emission Factors 

Pollutant kg/103

 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 824 49 439 

Carbon Monoxide (CO) 1.42 38.4 

Oxides of Nitrogen (NOx) 0.888 24.1 

Hydrocarbons (THC) 6.26 170 

Cost of Unnecessary Excess Air: $0 

Value of Unburned Fuel: $2 053 

74 
Total Cost of Improper Operation:$2 053 

Volume of Unnecessary Fuel Consumption: 1.459 mscfd 

75
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 3 


Equipment Information 

Unit Identifier: IR Compressor – Unit #3 G-48897/365094 

Engine Make and Model: Waukesha – L7042GSIU 

Compressor Cylinders: 4 Stages: 2 

Driver Cylinders: 12 Rated Power: 1100 kW 

Measured Exhaust Gas Composition
 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 120 000 

Oxygen (O2) 0 

Carbon Monoxide (CO) 3 793 

Nitrous Oxide (NO) 69 

Nitrogen Dioxide (NO2) 0 

Oxides of Nitrogen (NOx) 69 

Hydrocarbons (THC) 0 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3

/h) 226 

Air Flow (m3/h) 2 101 

Exhaust Flow (m3/h) 2 315 

Combustion Efficiency1 (%) 97.3 

Stack Heat Losses2 (%) 21.48 

Unburned Fuel (%) 2.00 

1 Air-to-fuel ratio of 10.5. 


2 For well-tuned compressor engines stack heat losses should be in the range of 20 


to 35 percent. 


Combustion Emission Factors 

Pollutant kg/103 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 792 48 546 

Carbon Monoxide (CO) 32.9 892 

Oxides of Nitrogen (NOx) 0.641 17.4 

Hydrocarbons (THC) 0.00 0 

Cost of Unnecessary Excess Air: $0 

Value of Unburned Fuel: $2 808 

76 
Total Cost of Improper Operation:$2 808 

Volume of Unnecessary Fuel Consumption: 3.764 mscfd 

77
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 3
 

Equipment Information 

Unit Identifier: Re-Compressor – Unit #1 G-42002/362292 

Engine Make and Model: Waukesha – L7042GSIU 

Compressor Cylinders: 3 Stages: 2 

Driver Cylinders: 12 Rated Power: 1100 kW 

Measured Exhaust Gas Composition
 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 120 000 

Oxygen (O2) 0 

Carbon Monoxide (CO) 85 

Nitrous Oxide (NO) 61 

Nitrogen Dioxide (NO2) 0 

Oxides of Nitrogen (NOx) 61 

Hydrocarbons (THC) 1 134 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3

/h) 142 

Air Flow (m3/h) 1 314 

Exhaust Flow (m3/h) 1 446 

Combustion Efficiency1 (%) 97.5 

Stack Heat Losses2 (%) 19.64 

Unburned Fuel (%) 0.81 

1 Air-to-fuel ratio of 10.5. 


2 For well-tuned compressor engines stack heat losses should be in the range of 20 


to 35 percent. 


Combustion Emission Factors 

Pollutant kg/103 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 827 49 523 

Carbon Monoxide (CO) 0.734 19.9 

Oxides of Nitrogen (NOx) 0.565 15.3 

Hydrocarbons (THC) 5.52 150 

Cost of Unnecessary Excess Air: $0 

Value of Unburned Fuel: $1 379 

78 
Total Cost of Improper Operation:$1 379 

Volume of Unnecessary Fuel Consumption: 0.963 mscfd 

79
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 3 

Equipment Information 

Unit Identifier: 

Engine Make and Model: 

Compressor Cylinders: 

Driver Cylinders: 

Re-Compressor – Unit #2 210598 

Waukesha – L7042GSIU 

3 Stages: 

12 Rated Power: 

2 

1100 kW 

Measured Exhaust Gas Composition 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 57 000 

Oxygen (O2) 111 000 

Carbon Monoxide (CO) 556 

Nitrous Oxide (NO) 36 

Nitrogen Dioxide (NO2) 0 

Oxides of Nitrogen (NOx) 36 

Hydrocarbons (THC) 1 563 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3

/h) 141 

Air Flow (m3/h) 2 412 

Exhaust Flow (m3/h) 2 534 

Combustion Efficiency1 (%) 95.7 

Stack Heat Losses2 (%) 22.95 

Unburned Fuel (%) 2.79 

1 Air-to-fuel ratio of 10.5. 


2 For well-tuned compressor engines stack heat losses should be in the range of 20 


to 35 percent. 


Combustion Emission Factors 

Pollutant kg/103 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 789 48 497 

Carbon Monoxide (CO) 9.96 270 

Oxides of Nitrogen (NOx) 0.691 18.7 

Hydrocarbons (THC) 15.8 427 

Cost of Unnecessary Excess Air: $11 615 

Value of Unburned Fuel: $4 334 

80 
Total Cost of Improper Operation:$15 949 

Volume of Unnecessary Fuel Consumption: 10.304 mscfd 

81
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 3 

Equipment Information 

Unit Identifier: 

Engine Make and Model: 

Compressor Cylinders: 

Driver Cylinders: 

Re-Compressor – Unit #3 

Waukesha – L7042GSIU 

3 Stages: 

12 Rated Power: 

2 

1100 kW 

Measured Exhaust Gas Composition 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 59 000 

Oxygen (O2) 107 000 

Carbon Monoxide (CO) 608 

Nitrous Oxide (NO) 32 

Nitrogen Dioxide (NO2) 0 

Oxides of Nitrogen (NOx) 32 

Hydrocarbons (THC) 1 400 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3

/h) 171 

Air Flow (m3/h) 2 834 

Exhaust Flow (m3/h) 2 991 

Combustion Efficiency1 (%) 96.0 

Stack Heat Losses2 (%) 22.55 

Unburned Fuel (%) 2.52 

1 Air-to-fuel ratio of 10.5. 


2 For well-tuned compressor engines stack heat losses should be in the range of 20 


to 35 percent. 


Combustion Emission Factors 

Pollutant kg/103 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 794 48 624 

Carbon Monoxide (CO) 10.5 285 

Oxides of Nitrogen (NOx) 0.592 16.1 

Hydrocarbons (THC) 13.6 369 

Cost of Unnecessary Excess Air: $13 317 

Value of Unburned Fuel: $4 678 

82 
Total Cost of Improper Operation:$17 995 

Volume of Unnecessary Fuel Consumption: 11.681 mscfd 

83
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 3 

Equipment Information 

Unit Identifier: 

Engine Make and Model: 

Compressor Cylinders: 

Driver Cylinders: 

Re-Compressor – Unit #4 400400 

Waukesha – L7042GSIU 

2 Stages: 

12 Rated Power: 

2 

1100 kW 

Measured Exhaust Gas Composition 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 59 000 

Oxygen (O2) 106 000 

Carbon Monoxide (CO) 572 

Nitrous Oxide (NO) 12 

Nitrogen Dioxide (NO2) 0 

Oxides of Nitrogen (NOx) 12 

Hydrocarbons (THC) 1 913 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3

/h) 133 

Air Flow (m3/h) 2 165 

Exhaust Flow (m3/h) 2 280 

Combustion Efficiency1 (%) 95.3 

Stack Heat Losses2 (%) 23.87 

Unburned Fuel (%) 3.13 

1 Air-to-fuel ratio of 10.5. 


2 For well-tuned compressor engines stack heat losses should be in the range of 20 


to 35 percent. 


Combustion Emission Factors 

Pollutant kg/103 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 782 48 303 

Carbon Monoxide (CO) 9.73 264 

Oxides of Nitrogen (NOx) 0.219 5.93 

Hydrocarbons (THC) 18.3 497 

Cost of Unnecessary Excess Air: $10 399 

Value of Unburned Fuel: $4 644 

84 
Total Cost of Improper Operation:$15 043 

Volume of Unnecessary Fuel Consumption: 9.735 mscfd 

85
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 3 

Equipment Information 

Unit Identifier: 

Engine Make and Model: 

Compressor Cylinders: 

Driver Cylinders: 

Re-Compressor – Unit #5 400442 

Waukesha – L7042GSIU 

2 Stages: 

12 Rated Power: 

2 

1100 kW 

Measured Exhaust Gas Composition 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 57 000 

Oxygen (O2) 111 000 

Carbon Monoxide (CO) 479 

Nitrous Oxide (NO) 35 

Nitrogen Dioxide (NO2) 0 

Oxides of Nitrogen (NOx) 35 

Hydrocarbons (THC) 4 303 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3

/h) 133 

Air Flow (m3/h) 2 211 

Exhaust Flow (m3/h) 2 328 

Combustion Efficiency1 (%) 91.1 

Stack Heat Losses2 (%) 25.71 

Unburned Fuel (%) 6.31 

1 Air-to-fuel ratio of 10.5. 


2 For well-tuned compressor engines stack heat losses should be in the range of 20 


to 35 percent. 


Combustion Emission Factors 

Pollutant kg/103 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 720 46 608 

Carbon Monoxide (CO) 8.29 225 

Oxides of Nitrogen (NOx) 0.649 17.6 

Hydrocarbons (THC) 41.9 1 137 

Cost of Unnecessary Excess Air: $9 851 

Value of Unburned Fuel: $10 056 

86 
Total Cost of Improper Operation:$19 907 

Volume of Unnecessary Fuel Consumption: 12.743 mscfd 

87
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 3 

Equipment Information 

Unit Identifier: Co-Gen #1 (West)
 

Engine Make and Model:
 

Rated Power:
 

Measured Exhaust Gas Composition 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 33 000 

Oxygen (O2) 153 000 

Carbon Monoxide (CO) 31 

Nitrous Oxide (NO) 132 

Nitrogen Dioxide (NO2) 13 

Oxides of Nitrogen (NOx) 144 

Hydrocarbons (THC) 0 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3/h) 7 097 

Air Flow (m3

/h) 175 027 

Exhaust Flow (m3/h) 180 593 

Combustion Efficiency1

 (%) 98.2 

Stack Heat Losses2

 (%) 27.90 

Unburned Fuel (%) 0.06 

1 Air-to-fuel ratio of 35. 


2 In the absence of heat recovery, turbine stack heat losses should be in the range of
 

60 to 70 percent. 


Combustion Emission Factors 

Pollutant kg/103

 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 563 50 255 

Carbon Monoxide (CO) 0.844 27.1 

Oxides of Nitrogen (NOx) 4.40 142 

Hydrocarbons (THC) 0 0 

Cost of Unnecessary Excess Air: $0 

Value of Unburned Fuel: $2 257 

Total Cost of Improper Operation:$2 257 

88 
Volume of Unnecessary Fuel Consumption: 3.660 mscfd 


89
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 3 

Equipment Information 

Unit Identifier: Co-Gen #2 (East)
 

Engine Make and Model:
 

Rated Power:
 

Measured Exhaust Gas Composition 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 35 000 

Oxygen (O2) 149 000 

Carbon Monoxide (CO) 28 

Nitrous Oxide (NO) 122 

Nitrogen Dioxide (NO2) 15 

Oxides of Nitrogen (NOx) 136 

Hydrocarbons (THC) 0 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3/h) 7 097 

Air Flow (m3

/h) 164 481 

Exhaust Flow (m3/h) 170 141 

Combustion Efficiency1

 (%) 98.2 

Stack Heat Losses2

 (%) 22.65 

Unburned Fuel (%) 0.05 

1 Air-to-fuel ratio of 35. 


2 In the absence of heat recovery, turbine stack heat losses should be in the range of
 

60 to 70 percent. 


Combustion Emission Factors 

Pollutant kg/103

 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 562 50 232 

Carbon Monoxide (CO) 0.713 22.9 

Oxides of Nitrogen (NOx) 3.96 127 

Hydrocarbons (THC) 0 0 

Cost of Unnecessary Excess Air: $0 

Value of Unburned Fuel: $1 908 

Total Cost of Improper Operation:$1 908 

90 
Volume of Unnecessary Fuel Consumption: 3.094 mscfd 


91
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 3 

Equipment Information 

Unit Identifier: Glycol Reboiler (East) E2801/311-5-02 

Boiler Make and Model: Taylor Forge Engineering Systems 

Rated Power: 350 kW 

Measured Exhaust Gas Composition 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 55 000 

Oxygen (O2) 113 000 

Carbon Monoxide (CO) 0 

Nitrous Oxide (NO) 31 

Nitrogen Dioxide (NO2) 0 

Oxides of Nitrogen (NOx) 31 

Hydrocarbons (THC) 0 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3/h) 56 

Air Flow (m3

/h) 1 008 

Exhaust Flow (m3/h) 1 056 

Combustion Efficiency1

 (%) 98.3 

Stack Heat Losses (%) 23.51 

Unburned Fuel (%) 0.00 

Thermal Efficiency (%) 76.49 

1 Typical excess air of 15 percent. 

Combustion Emission Factors 

Pollutant kg/103

 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 849 50 108 

Carbon Monoxide (CO) 0 0 

Oxides of Nitrogen (NOx) 0.620 16.8 

Hydrocarbons (THC) 0 0 

Cost of Unnecessary Excess Air: $6 539 

Value of Unburned Fuel: $0 

Total Cost of Improper Operation:$6 539 

Volume of Unnecessary Fuel Consumption: 3.980 mscfd 

92 
93
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 3 

Equipment Information 

Unit Identifier: Glycol Reboiler (West) E2802/803790-2 

Boiler Make and Model: Taylor Forge Engineering Systems 

Rated Power: 350 kW 

Measured Exhaust Gas Composition 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 90 000 

Oxygen (O2) 53 000 

Carbon Monoxide (CO) 2 

Nitrous Oxide (NO) 63 

Nitrogen Dioxide (NO2) 0 

Oxides of Nitrogen (NOx) 63 

Hydrocarbons (THC) 0 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3/h) 103 

Air Flow (m3

/h) 1 200 

Exhaust Flow (m3/h) 1 293 

Combustion Efficiency1

 (%) 98.3 

Stack Heat Losses (%) 17.95 

Unburned Fuel (%) 0.00 

Thermal Efficiency (%) 82.05 

1 Typical excess air of 15 percent. 

Combustion Emission Factors 

Pollutant kg/103 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 845 50 002 

Carbon Monoxide (CO) 0.069 1.86 

Oxides of Nitrogen (NOx) 0.774 21.0 

Hydrocarbons (THC) 0 0 

Cost of Unnecessary Excess Air: $3 280 

Value of Unburned Fuel: $3 

Total Cost of Improper Operation:$3 283 

Volume of Unnecessary Fuel Consumption: 1.999 mscfd 

94 
95
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 3 

Equipment Information 

Unit Identifier: Heat Medium Heater (East) L-73026 

Boiler Make and Model: Cleaver Brooks CB700x-250 

Rated Power: 3072 kW 

Measured Exhaust Gas Composition 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 81 000 

Oxygen (O2) 69 000 

Carbon Monoxide (CO) 0 

Nitrous Oxide (NO) 38 

Nitrogen Dioxide (NO2) 5 

Oxides of Nitrogen (NOx) 42 

Hydrocarbons (THC) 900 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3/h) 628 

Air Flow (m3

/h) 8 054 

Exhaust Flow (m3/h) 8 618 

Combustion Efficiency1

 (%) 97.3 

Stack Heat Losses (%) 6.99 

Unburned Fuel (%) 0.00 

Thermal Efficiency (%) 93.01 

1 Typical excess air of 15 percent. 

Combustion Emission Factors 

Pollutant kg/103

 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 828 49 541 

Carbon Monoxide (CO) 0 0 

Oxides of Nitrogen (NOx) 0.627 17.0 

Hydrocarbons (THC) 6.49 176 

Cost of Unnecessary Excess Air: $9 713 

Value of Unburned Fuel: $6 984 

Total Cost of Improper Operation:$16 697 

Volume of Unnecessary Fuel Consumption: 10.652 mscfd 

96 
97
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 3 

Equipment Information 

Unit Identifier: Heat Medium Heater (West) L-73025 

Boiler Make and Model: Cleaver Brooks CB700x-250 

Rated Power: 3072 kW 

Measured Exhaust Gas Composition 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 81 000 

Oxygen (O2) 69 000 

Carbon Monoxide (CO) 0 

Nitrous Oxide (NO) 43 

Nitrogen Dioxide (NO2) 7 

Oxides of Nitrogen (NOx) 50 

Hydrocarbons (THC) 500 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3/h) 533 

Air Flow (m3

/h) 6 855 

Exhaust Flow (m3/h) 7 332 

Combustion Efficiency1

 (%) 97.7 

Stack Heat Losses (%) 7.31 

Unburned Fuel (%) 0.50 

Thermal Efficiency (%) 92.69 

1 Typical excess air of 15 percent. 

Combustion Emission Factors 

Pollutant kg/103

 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 836 49 755 

Carbon Monoxide (CO) 0 0 

Oxides of Nitrogen (NOx) 0.740 20.1 

Hydrocarbons (THC) 3.619 98.1 

Cost of Unnecessary Excess Air: $9 389 

Value of Unburned Fuel: $3 301 

Total Cost of Improper Operation:$12 690 

Volume of Unnecessary Fuel Consumption: 7.963 mscfd 

98 
99
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 3 

Equipment Information 

Unit Identifier: Heater Treater (East)
 

Boiler Make and Model:
 

Rated Power:
 

Measured Exhaust Gas Composition 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 26 000 

Oxygen (O2) 165 000 

Carbon Monoxide (CO) 140 

Nitrous Oxide (NO) 4 

Nitrogen Dioxide (NO2) 7 

Oxides of Nitrogen (NOx) 10 

Hydrocarbons (THC) 0 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3/h) 24 

Air Flow (m3

/h) 856 

Exhaust Flow (m3/h) 872 

Combustion Efficiency1

 (%) 98.1 

Stack Heat Losses (%) 27.64 

Unburned Fuel (%) 0.34 

Thermal Efficiency (%) 72.36 

1 Typical excess air of 15 percent. 

Combustion Emission Factors 

Pollutant kg/103

 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 851 50 168 

Carbon Monoxide (CO) 5.54 150 

Oxides of Nitrogen (NOx) 0.624 16.9 

Hydrocarbons (THC) 0 0 

Cost of Unnecessary Excess Air: $5 855 

Value of Unburned Fuel: $50 

Total Cost of Improper Operation:$5 905 

Volume of Unnecessary Fuel Consumption: 3.632 mscfd 

100 
101
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 3 

Equipment Information 

Unit Identifier: Heater Treater (West)
 

Boiler Make and Model:
 

Rated Power:
 

Measured Exhaust Gas Composition 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 23 000 

Oxygen (O2) 170 000 

Carbon Monoxide (CO) 9 

Nitrous Oxide (NO) 4 

Nitrogen Dioxide (NO2) 5 

Oxides of Nitrogen (NOx) 8 

Hydrocarbons (THC) 0 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3/h) 24 

Air Flow (m3

/h) 938 

Exhaust Flow (m3/h) 953 

Combustion Efficiency1

 (%) 98.3 

Stack Heat Losses (%) 29.61 

Unburned Fuel (%) 0.02 

Thermal Efficiency (%) 70.39 

1 Typical excess air of 15 percent. 

Combustion Emission Factors 

Pollutant kg/103

 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 861 50 455 

Carbon Monoxide (CO) 0.399 10.8 

Oxides of Nitrogen (NOx) 0.554 15.0 

Hydrocarbons (THC) 0 0 

Cost of Unnecessary Excess Air: $6 464 

Value of Unburned Fuel: $4 

Total Cost of Improper Operation:$6 468 

Volume of Unnecessary Fuel Consumption: 3.940 mscfd 

102 
103
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 4 

Equipment Information 

Unit Identifier: Re-Compressor 1 

Engine Make and Model: BA Clark – Integral HBA-T 

Compressor Cylinders: 4 Stages: 2 

Driver Cylinders: 6 Rated Power: 

Measured Exhaust Gas Composition 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 51 000 

Oxygen (O2) 121 000 

Carbon Monoxide (CO) 360 

Nitrous Oxide (NO) 265 

Nitrogen Dioxide (NO2) 57 

Oxides of Nitrogen (NOx) 322 

Hydrocarbons (THC) 0 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3

/h) 255 

Air Flow (m3/h) 4 999 

Exhaust Flow (m3/h) 5 210 

Combustion Efficiency1 (%) 98.0 

Stack Heat Losses2 (%) 35.00 

Unburned Fuel (%) 0.44 

1 Air-to-fuel ratio of 30. 


2 For well-tuned compressor engines stack heat losses should be in the range of 20 


to 35 percent. 


Combustion Emission Factors 

Pollutant kg/103

 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 864 49 615 

Carbon Monoxide (CO) 7.42 198 

Oxides of Nitrogen (NOx) 7.79 207 

Hydrocarbons (THC) 0.00 0 

Cost of Unnecessary Excess Air: $0 

Value of Unburned Fuel: $715 

104 
Total Cost of Improper Operation:$715 

Volume of Unnecessary Fuel Consumption: 0.978 mscfd 

105
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 4 

Equipment Information 

Unit Identifier: Re-Compressor 2 

Engine Make and Model: BA Clark – Integral HBA-T 

Compressor Cylinders: 4 Stages: 2 

Driver Cylinders: 6 Rated Power: 

Measured Exhaust Gas Composition 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 49 000 

Oxygen (O2) 125 000 

Carbon Monoxide (CO) 243 

Nitrous Oxide (NO) 151 

Nitrogen Dioxide (NO2) 15 

Oxides of Nitrogen (NOx) 166 

Hydrocarbons (THC) 0 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3/h) 255 

Air Flow (m3

/h) 5 203 

Exhaust Flow (m3

/h) 5 413 

Combustion Efficiency1

 (%) 98.1 

Stack Heat Losses2

 (%) 35.03 

Unburned Fuel (%) 0.31 

1 Air-to-fuel ratio of 30. 


2 For well-tuned compressor engines stack heat losses should be in the range of 20 


to 35 percent. 


Combustion Emission Factors 

Pollutant kg/103

 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 868 49 720 

Carbon Monoxide (CO) 5.24 140 

Oxides of Nitrogen (NOx) 4.02 107 

Hydrocarbons (THC) 0.00 0 

Cost of Unnecessary Excess Air: $0 

Value of Unburned Fuel: $505 

106 
Total Cost of Improper Operation:$505 

Volume of Unnecessary Fuel Consumption: 0.690 mscfd 

107
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 4 

Equipment Information 

Unit Identifier: Re-Compressor 3 

Engine Make and Model: BA Clark – Integral HBA-T 

Compressor Cylinders: 4 Stages: 2 

Driver Cylinders: 6 Rated Power: 

Measured Exhaust Gas Composition 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 49 000 

Oxygen (O2) 126 000 

Carbon Monoxide (CO) 253 

Nitrous Oxide (NO) 302 

Nitrogen Dioxide (NO2) 59 

Oxides of Nitrogen (NOx) 361 

Hydrocarbons (THC) 0 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3

/h) 255 

Air Flow (m3/h) 5 265 

Exhaust Flow (m3/h) 5 473 

Combustion Efficiency1 (%) 98.1 

Stack Heat Losses2 (%) 34.51 

Unburned Fuel (%) 0.33 

1 Air-to-fuel ratio of 30. 


2 For well-tuned compressor engines stack heat losses should be in the range of 20 


to 35 percent. 


Combustion Emission Factors 

Pollutant kg/103 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 867 49 712 

Carbon Monoxide (CO) 5.53 147 

Oxides of Nitrogen (NOx) 9.19 245 

Hydrocarbons (THC) 0.00 0 

Cost of Unnecessary Excess Air: $0 

Value of Unburned Fuel: $532 

108 
Total Cost of Improper Operation:$532 

Volume of Unnecessary Fuel Consumption: 0.728 mscfd 

109
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 4 

Equipment Information 

Unit Identifier: Re-Compressor 4 

Engine Make and Model: BA Clark – Integral HBA-T 

Compressor Cylinders: 4 Stages: 2 

Driver Cylinders: 6 Rated Power: 

Measured Exhaust Gas Composition 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 51 000 

Oxygen (O2) 121 000 

Carbon Monoxide (CO) 449 

Nitrous Oxide (NO) 265 

Nitrogen Dioxide (NO2) 186 

Oxides of Nitrogen (NOx) 451 

Hydrocarbons (THC) 0 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3

/h) 255 

Air Flow (m3/h) 5 003 

Exhaust Flow (m3/h) 5 215 

Combustion Efficiency1 (%) 97.9 

Stack Heat Losses2 (%) 32.94 

Unburned Fuel (%) 0.55 

1 Air-to-fuel ratio of 30. 


2 For well-tuned compressor engines stack heat losses should be in the range of 20 


to 35 percent. 


Combustion Emission Factors 

Pollutant kg/103 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 861 49 538 

Carbon Monoxide (CO) 9.28 247 

Oxides of Nitrogen (NOx) 12.18 324 

Hydrocarbons (THC) 0.00 0 

Cost of Unnecessary Excess Air: $0 

Value of Unburned Fuel: $893 

110 
Total Cost of Improper Operation:$893 

Volume of Unnecessary Fuel Consumption: 1.221 mscfd 

111
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 4 

Equipment Information 

Unit Identifier: Re-Compressor 5 

Engine Make and Model: BA Clark – Integral HBA-T 

Compressor Cylinders: 4 Stages: 2 

Driver Cylinders: 6 Rated Power: 

Measured Exhaust Gas Composition 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 47 000 

Oxygen (O2) 127 000 

Carbon Monoxide (CO) 438 

Nitrous Oxide (NO) 326 

Nitrogen Dioxide (NO2) 167 

Oxides of Nitrogen (NOx) 493 

Hydrocarbons (THC) 0 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3

/h) 255 

Air Flow (m3/h) 5 324 

Exhaust Flow (m3/h) 5 533 

Combustion Efficiency1 (%) 97.9 

Stack Heat Losses2 (%) 34.44 

Unburned Fuel (%) 0.58 

1 Air-to-fuel ratio of 30. 


2 For well-tuned compressor engines stack heat losses should be in the range of 20 


to 35 percent. 


Combustion Emission Factors 

Pollutant kg/103 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 861 49 541 

Carbon Monoxide (CO) 9.70 258 

Oxides of Nitrogen (NOx) 13.80 368 

Hydrocarbons (THC) 0.00 0 

Cost of Unnecessary Excess Air: $0 

Value of Unburned Fuel: $933 

112 
Total Cost of Improper Operation:$933 

Volume of Unnecessary Fuel Consumption: 1.276 mscfd 

113
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 4 

Equipment Information 

Unit Identifier: Generator 1 


Engine Make and Model:
 

Driver Cylinders: 12 Rated Power:
 

Measured Exhaust Gas Composition 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 110 000 

Oxygen (O2) 12 000 

Carbon Monoxide (CO) 984 

Nitrous Oxide (NO) 39 

Nitrogen Dioxide (NO2) 10 

Oxides of Nitrogen (NOx) 49 

Hydrocarbons (THC) 0 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3/h) 223 

Air Flow (m3

/h) 2 219 

Exhaust Flow (m3/h) 2 424 

Combustion Efficiency1

 (%) 98.0 

Stack Heat Losses2

 (%) 27.25 

Unburned Fuel (%) 0.55 

1 Air-to-fuel ratio of 10.5. 


2 For well-tuned compressor engines stack heat losses should be in the range of 20 


to 35 percent. 


Combustion Emission Factors 

Pollutant kg/103

 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 855 49 384 

Carbon Monoxide (CO) 9.20 245 

Oxides of Nitrogen (NOx) 0.544 14.5 

Hydrocarbons (THC) 0.00 0 

Cost of Unnecessary Excess Air: $0 

Value of Unburned Fuel: $773 

Total Cost of Improper Operation:$773 

114 
Volume of Unnecessary Fuel Consumption: 1.057 mscfd 


115
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 4 

Equipment Information 

Unit Identifier: Generator 2 


Engine Make and Model:
 

Driver Cylinders: 12 Rated Power:
 

Measured Exhaust Gas Composition 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 111 000 

Oxygen (O2) 11 000 

Carbon Monoxide (CO) 832 

Nitrous Oxide (NO) 447 

Nitrogen Dioxide (NO2) 14 

Oxides of Nitrogen (NOx) 461 

Hydrocarbons (THC) 0 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3/h) 233 

Air Flow (m3

/h) 2 213 

Exhaust Flow (m3/h) 2 418 

Combustion Efficiency1

 (%) 98.0 

Stack Heat Losses2

 (%) 24.76 

Unburned Fuel (%) 0.46 

1 Air-to-fuel ratio of 10.5. 


2 For well-tuned compressor engines stack heat losses should be in the range of 20 


to 35 percent. 


Combustion Emission Factors 

Pollutant kg/103

 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 857 49 444 

Carbon Monoxide (CO) 7.75 206 

Oxides of Nitrogen (NOx) 4.67 124 

Hydrocarbons (THC) 0.00 0 

Cost of Unnecessary Excess Air: $0 

Value of Unburned Fuel: $651 

Total Cost of Improper Operation:$651 

116 
Volume of Unnecessary Fuel Consumption: 0.890 mscfd 


117
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 4 

Equipment Information 

Unit Identifier: Generator 3 


Engine Make and Model:
 

Driver Cylinders: 12 Rated Power:
 

Measured Exhaust Gas Composition 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 111 000 

Oxygen (O2) 11 000 

Carbon Monoxide (CO) 332 

Nitrous Oxide (NO) 198 

Nitrogen Dioxide (NO2) 7 

Oxides of Nitrogen (NOx) 205 

Hydrocarbons (THC) 0 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3/h) 233 

Air Flow (m3

/h) 2 214 

Exhaust Flow (m3/h) 2 419 

Combustion Efficiency1

 (%) 98.2 

Stack Heat Losses2

 (%) 25.97 

Unburned Fuel (%) 0.18 

1 Air-to-fuel ratio of 10.5. 


2 For well-tuned compressor engines stack heat losses should be in the range of 20 


to 35 percent. 


Combustion Emission Factors 

Pollutant kg/103

 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 865 49 639 

Carbon Monoxide (CO) 3.09 82.6 

Oxides of Nitrogen (NOx) 2.08 55.4 

Hydrocarbons (THC) 0.00 0 

Cost of Unnecessary Excess Air: $0 

Value of Unburned Fuel: $260 

Total Cost of Improper Operation:$260 

118 
Volume of Unnecessary Fuel Consumption: 0.355 mscfd 


119
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 4 

Equipment Information 

Unit Identifier: Refrigerant Compressor 3 


Engine Make and Model:
 

Compressor Cylinders: 5 Stages: 2 


Driver Cylinders: 10 Rated Power:
 

Measured Exhaust Gas Composition 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 36 000 

Oxygen (O2) 145 000 

Carbon Monoxide (CO) 89 

Nitrous Oxide (NO) 1 514 

Nitrogen Dioxide (NO2) 631 

Oxides of Nitrogen (NOx) 2 145 

Hydrocarbons (THC) 0 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3

/h) 342 

Air Flow (m3/h) 9 026 

Exhaust Flow (m3/h) 9 284 

Combustion Efficiency1 (%) 97.7 

Stack Heat Losses2 (%) 35.93 

Unburned Fuel (%) 0.15 

1 Air-to-fuel ratio of 30. 


2 For well-tuned compressor engines stack heat losses should be in the range of 20 


to 35 percent. 


Combustion Emission Factors 

Pollutant kg/103 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 875 49 931 

Carbon Monoxide (CO) 2.55 67.8 

Oxides of Nitrogen (NOx) 76.07 2 025 

Hydrocarbons (THC) 0 0 

Cost of Unnecessary Excess Air: $0 

Value of Unburned Fuel: $328 

120 
Total Cost of Improper Operation:$328 

Volume of Unnecessary Fuel Consumption: 0.449 mscfd 

121
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Processing Plant 4 

Equipment Information 

Unit Identifier: Refrigerant Compressor 4 


Engine Make and Model:
 

Compressor Cylinders: 5 Stages: 2 


Driver Cylinders: 10 Rated Power:
 

Measured Exhaust Gas Composition 

Pollutant Concentration (ppm) 

Carbon Dioxide (CO2) 38 000 

Oxygen (O2) 141 000 

Carbon Monoxide (CO) 781 

Nitrous Oxide (NO) 1 149 

Nitrogen Dioxide (NO2) 333 

Oxides of Nitrogen (NOx) 1 482 

Hydrocarbons (THC) 0 

Stream Flows at 15oC and 101.325 kPa 


Fuel Consumption (m3

/h) 342 

Air Flow (m3/h) 8 469 

Exhaust Flow (m3/h) 8 737 

Combustion Efficiency1 (%) 97.3 

Stack Heat Losses2 (%) 33.83 

Unburned Fuel (%) 1.25 

1 Air-to-fuel ratio of 30. 


2 For well-tuned compressor engines stack heat losses should be in the range of 20 


to 35 percent. 


Combustion Emission Factors 

Pollutant kg/103 m 3 of Fuel Input ng/J of Fuel Input 

Carbon Dioxide (CO2) 1 846 49 137 

Carbon Monoxide (CO) 20.88 556 

Oxides of Nitrogen (NOx) 47.54 1 265 

Hydrocarbons (THC) 0 0 

Cost of Unnecessary Excess Air: $0 

Value of Unburned Fuel: $2 693 

122 
Total Cost of Improper Operation:$2 693 

Volume of Unnecessary Fuel Consumption: 3.681 mscfd 

123
 
Appendix IV 

Average Equipment Component Schedules for Natural Gas Processing Plants Table IV-1. Summary of average equipment component schedules for processes at natural gas processinProcess 

Number of Emission Sources Associated with the Process Gas Service Light Liquid SerV CV C R PR V OE L OM 

Othe r Mete r 

BD CS CC V V CV C 

Claus Plant 19 2 119 1 - 4 - - - - - - - - 

Cogeneration : Reciprocatin g 

9 2 71 1 - - - - - - 1 - - - 

Cogeneration : Turbine 89 2 234 3 1 5 1 - - - - - - - 

Compressor: Electric 142 8 866 - 6 2 - - 1 9 1 8 1 5 

Compressor: Reciprocatin g 

67 21 623 2 4 19 - - - 6 1 2 - 3 

Compressor: Turbine 100 10 646 1 3 11 16 - - 1 - - - - 

Dehydration: Mole Sieve 141 19 825 1 5 13 - - 1 - - - - 

Dehydration: 77 4 338 4 2 5 1 - - - - 5 - 13 

124 
Table IV-1. Summary of average equipment component schedules for processes at natural gas processin

Process 

Number of Emission Sources Associated with the Process Gas Service Light Liquid SerV CV C R PR V OE L OM 

Othe r Mete r 

BD CS CC V V CV C 

TEG Flare 130 12 392 1 - 20 9 1 - - - - - - 

Fractionation : Demethanizer 38 1 77 - - 7 - - - - - 15 1 77 

Fractionation : De-ethanizer 

52 3 211 - 2 7 1 - - - - 56 4 197 

Fractionation : Depropanizer 42 2 152 - - 1 - - - - - 17 1 51 

Fractionation : De-butanizer 

23 1 69 - - 6 - - - - - 3 - 3 

Hg Removal 98 262 - 3 9 - - - - - - - - 

Inlet: Header 27 1 88 - - 2 1 - - - - 5 - 16 

Inlet: Separation 46 2 175 1 2 1 - - - - 14 1 56 NRU 83 12 189 - 5 9 1 - - - - - - - Refrigeration 323 40 263 1 8 44 4 1 - 8 2 36 2 57 

125 
Table IV-1. Summary of average equipment component schedules for processes at natural gas processin

Process 

Number of Emission Sources Associated with the Process Gas Service Light Liquid SerV CV C R PR V OE L OM 

Othe r Mete r 

BD CS CC V V CV C 

: Propane 1 Refrigeration : Turbo Expansion 

77 8 242 1 2 8 - - - 1 - 15 2 48 

Sales: NG 113 5 490 - - 17 4 - - - - - - - 

Sales: NGL 35 1 105 - 1 2 - - - - 107 4 418 

Stabilization 116 6 485 3 2 4 6 1 - - - 137 6 406 

Storage: C5 - 3 - - - - - - - - - 

Storage: NGL 63 2 125 - 1 1 - - - - - 12 - 1 

Sweetening: Amine 177 7 541 1 8 7 2 - - - - 4 1 15 

Utilities 141 9 789 13 2 3 3 - - - - 6 1 18 

VRU: Electric 23 2 184 4 3 - - - - - - - - - 

126 
 

Appendix V 

Financial Considerations and Assumptions 

Financial Discount Rate 

The discount rate and opportunity cost of equity in the gas industry is arbitrarily taken to 

be six percent. Most oil and gas ventures are expected to yield better than bank interest 

to compensate for the added risk involved. 

Net Present Value (NPV) 

The net present value of each target control option is the present value of benefits minus 

the present value of costs. The analysis period in each case is the expected life of the 

control measure (e.g., the average repair life or mean time between leak occurrences). 

Payout Period 

The payout period of each target control option is the number of periods (years) required 

to payout the net present value of the repair costs based on annual payments equal to the 

value of the net benefit of repairs. 

Equalized Annual Value 

The equalized annual value of each control option is the total value of the option (after 

capital and operating costs) expressed as an equivalent series of equal annual payments 

spread over the life of the project. Negative values indicate a net cost. 

Value of GHG Reduction 

The value of a GHG emission reduction option is simply calculated as the equalized 

annual value divided by the average annual CO2-equivalent reduction. 

127 
 

 

 

 

 

 

 

Appendix VI 

Basic Component Repair Costs and Mean Repair Life 

Table VI-1. Summary of repair costs and mean life of repair for equipment 

components in natural gas and non-methane hydrocarbon service. 

Source Category Size (inches) Basic 

Repair 

Cost 

($/source) 

Mean 

Repair Life 

(years) 

Compressor Seals Reciprocating - 2 000 1 

Centrifugal - 2 000 1 

Compressor Valve 

Covers 

All - 200 1 

Compressor Variable 

Volume Pocket Stem 

All - 400 1 

Compressor Cylinder 

End 

All - 400 1 

Flanges All 0.5 - 0.75 

1 - 2.5 

3 - 4 

6 - 8 

10 - 14 

16 - 20 

24 - 30 

32 

25 

50 

75 

100 

150 

200 

300 

400 

2 

Lube Oil Vent - - 4 000 1 

Open-Ended Lines All 0.5 - 0.75 

1 - 1.5 

2 

3 

4 

6 

8 

10 

12 

14 

16 

20 

24 

30 

60 

75 

100 

120 

190 

245 

350 

500 

595 

780 

890 

1 115 

1 340 

1 670 

2 

Orifice Meters All - 150 1 

Other Flowmeters All - 150 5 

128 
Pressure Relief Valves Threaded 0.5 - 0.75 

1 – 2 

2.5 

3 

4 

6 

8 

10 

12 

79 

84 

95 

107 

135 

203 

270 

338 

405 

2 

Continued ...
 

129 
 

 

 

Table VI-1. Summary of repair costs and mean life of repair for equipment 

components in natural gas and non-methane hydrocarbon service (continued). 

Source Category Size (inches) Basic 

Repair 

Cost 

($/source) 

Mean 

Repair Life 

(years) 

Pressure Relief Valves Flanged 1 

1.5 

2 

2.5 

3 

4 

6 

8 

10 

12 

16 

20 

124 

130 

135 

146 

180 

214 

253 

290 

363 

435 

580 

725 

2 

Pump Seal All - 500 1 

Regulators All - 175 5 

Threaded Connections Pipe Thread 0.125 - 0.75 

1 - 2.5 

3 - 4 

6 - 8 

10 - 14 

16 - 20 

24 - 30 

32 

10 

15 

25 

50 

100 

150 

200 

300 

2 

Union 0.5 - 0.75 

1 - 2.5 

3 - 6 

50 

100 

150 

2 

Tubing Connections All 0.5 - 0.75 

1 - 2.5 

15 

25 

4 

130 
Valves Ball 0.5 - 0.75 

1 - 1.5 

2 

3 

4 

6 

8 

10 

12 

14 

16 

20 

60 

75 

100 

120 

190 

245 

350 

500 

595 

780 

891 

1 114 

4 

Continued ...
 

131 
 

 

Table VI-1. Summary of repair costs and mean life of repair for equipment 

components in natural gas and non-methane hydrocarbon service (continued). 

Source Category Size (inches) Basic 

Repair 

Cost 

($/source) 

Mean 

Repair Life 

(years) 

Valves Butterfly 0.5 - 0.75 

1 - 1.5 

2 

3 

4 

6 

8 

10 

12 

14 

16 

20 

120 

150 

200 

240 

380 

490 

700 

1 000 

1 190 

1 560 

1 783 

2 229 

2 

Control (all types) 0.5 - 2 130 2 

3 141 

4 177 

6 282 

8 353 

10 459 

12 560 

14 653 

16 747 

20 933 

24 1120 

Gate 0.5 - 0.75 60 4 

1 - 1.5 75 

2 100 

3 120 

4 190 

6 245 

8 350 

10 500 

12 595 

14 780 

16 920 

20 1 000 

Continued ... 

132 
 

 

 

Table VI-1. Summary of repair costs and mean life of repair for equipment 

components in natural gas and non-methane hydrocarbon service (concluded). 

Source Category Size (inches) Basic 

Repair 

Cost 

($/source) 

Mean 

Repair Life 

(years) 

Valves Globe 1 - 1.5 

2 

3 

4 

6 

8 

10 

12 

16 

20 

24 

75 

100 

120 

190 

245 

350 

500 

600 

800 

1 000 

1 200 

4 

Governor All 200 4 

Injector (fuel gas) All 200 4 

Needle 0.125 - 0.75 60 4 

1 - 1.5 75 

2 100 

2.5 125 

3 150 

4 200 

Orbit 0.5 - 0.75 60 4 

1 - 1.5 75 

2 100 

3 120 

4 190 

6 245 

8 350 

10 500 

12 595 

14 780 

133 
Plug 0.5 - 0.75 60 4 

1 - 1.5 75 

2 120 

3 150 

4 200 

6 255 

8 300 

10 394 

12 480 

14 560 

16 640 

20 800 

24 960 

30 1 200 

Vents 1 - 4 

6 - 30 

2 000 

5 000 

1 

134 
 

Appendix VII 

WORK PRACTICE 

Alternative Means for Leak Detection and Repair in Natural Gas Processing 

(High Flow Sampler Procedure) 

1.0 Scope and Application. 

1.1 Analytes. 

Analyte CAS No. 

Volatile Organic Compounds (VOC) No CAS number assigned 

1.2 Scope. This work practice is applicable for the determination of VOC 

leaks from process equipment. These sources include, but are not limited to, valves, 

flanges and other connections, pumps and compressors, pressure relief devices, process 

drains, open-ended valves, pump and compressor seal system degassing vents, 

accumulator vessel vents, agitator seals, and access door seals. 

1.3 Data Quality Objectives. Adherence to the requirements of this method 

will enhance the quality of the data obtained from air pollutant sampling methods. 

2.0 Summary of Work Practice. 

2.1 The work practice involves pre-screening using soap bubble testing (alternative 

screening procedure of Method 21) and, where the soap bubble procedure cannot be used, 

Method 21. If concentrations above the leak definition of 500 ppm are detected, the HiFlowθ sampler is used to determine the mass emission rate. This determination differs 

from Method 21, which measures concentrations only. 

2.2 Components with mass emissions equal to or greater than the equivalent leak 

definition in ppm are repaired. The equivalent mass rates are listed in Table 1 in Section 

3.0. 

3.0 Definitions. 

3.1 The definitions listed in Method 21 also applies to this work practice. 

3.2 Leak definition mass rate means the local VOC mass rate that is 

equivalent to the leak definition concentration that indicates that a VOC emission (leak) 

is present. These equivalent mass rates were based on the 1995 Protocol for Equipment 

Leaks Emission Estimation and Demonstrating Alternative Work Practices for Fugitive 

135 
Leak Detection and Repair Programs.. The equivalent emission mass rates of methane in 

terms of "scfm" are presented in Table 1. 

Table 1. Equivalent Mass Rate Leak Definition 

Component/Service 

Leak Definition Valves/LL&G Pump Seals/LL Pressure Relief Devices/G 

NSPS, ppm CH4 10,000 10,000 10,000 

scfm of CH4 0.0018 0.0115 0.0026 

4.0 Interferences. [Reserved] 

5.0 Safety. 

5.1 Disclaimer. This work practice may involve hazardous materials, operations, and 

equipment. This work practice may not address all of the safety problems associated 

with its use. It is the responsibility of the user of this test method to establish appropriate 

safety and health practices and determine the applicability of regulatory limitations prior 

to performing this test method. 

5.2 Hazardous Pollutants. Several of the compounds, leaks of which may be determined 

by this method, may be irritating or corrosive to tissues (e.g., heptane) or may be toxic 

(e.g., benzene, methyl alcohol). Nearly all are fire hazards. Compounds in emissions 

should be determined through familiarity with the source. Appropriate precautions can 

be found in reference documents, such as reference No. 4 in Section 16.0. 

6.0 Equipment and Supplies. 

A VOC monitoring instrument meeting the following specifications is required: 

6.1 Detector. The VOC instrument detector shall respond to the compounds being 

processed. Detector types that may meet this requirement include, but are not limited to, 

catalytic oxidation, flame ionization, conductivity, infrared absorption, and 

photoionization. 

Note: Two detectors may be used to shorten sampling time by simultaneously analyzing 

the source and the background air. 

6.1.1 The instrument shall be capable of measuring the leak definition concentration 

specified in the regulation. 

6.1.2 The scale of the instrument meter shall be readable to ±2.5 percent of the 

specified leak definition concentration or its equivalent (see ____). 

136 
 

 

 

 

6.2 Pump. A 10-scfm battery-powered pump. An electric or pneumatic pump with a 

capacity of 10 scfm or greater to provide good capture efficiency may also be used. 

(Note: Several pumps in parallel may be used to provide the capacity.) 

6.3 Flow Meter. An intrinsically safe thermal anemometer capable of measuring flow 

rates over the full range with an accuracy of ±10 percent for air. Other flow meters, such 

as rotameters, turbine meters, venturi meters, orifices, and pitot tubes, may also be used. 

6.4 Flow Regulator. Throttling valve, a bypass valve, or different number of pumps 

in parallel may be used to control the sample flow rate. 

6.5 Sampling Hoses. An 8-ft primary sampling hose and a 12-ft extension hose made 

of a smooth-bore flexible urethane with a conductive wire (grounded) braided into the 

coils, approximately 1.5-inch inside diameter, and for collecting background air, a 1/4 

inch polyvinyl plastic tubing "piggy-backed" on the hoses. Other flexible plastic hoses 

that are formulated and constructed to prevent static charge build up may also be used. 

6.6 Probe Tip/Extensions. Probe or probe extension with outside diameter not to 

exceed 6.4 mm (1/4 inch), with a single end opening for admission of sample, for use in 

Method 21 sampling mode. 

6.7 Probe Tip Attachments. Attachments that aid in the total capture of 

emissions from leaks. Some attachments that have been used successfully in 

developmental tests are: (a) a cone-shaped attachment that is split down one side for most 

valve sampling; (b) a long strap of Mylar plastic with Velcro to wrap around flange faces; 

and (c) a large sheet of anti-static plastic with patches of Velcro around the edges for 

large or odd shaped components. A tight fit is not necessary in these attachments. 

However, the areas open to the atmosphere must be small enough to provide leaking 

VOC from escaping the attachment. 

6.8 Intrinsically Safe Equipment. The instrument shall be intrinsically safe for 

operation in explosive atmospheres as defined by the National Electrical Code by the 

National Fire Prevention Association or other applicable regulatory code for operation in 

any explosive atmospheres that may be encountered in its use. The instrument shall, at a 

minimum, be intrinsically safe for Class 1, Division 1 conditions, and/or Class 2, 

Division 1 conditions, as appropriate, as defined by the example code. The instrument 

shall not be operated with any safety device, such as an exhaust flame arrestor, removed. 

7.0 Reagents and Standards. 

7.1 Calibration and Performance Evaluation. 

7.1.1 Zero Gas. Air, less than 10 parts per million by volume (ppmv) VOC. 

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7.1.2 Calibration Gas. Methane, ____ ppmv, certified by the manufacturer to be within 

±2 percent accuracy and with a specified shelf life. Cylinder standards must be either 

reanalyzed or replaced at the end of the specified shelf life. 

7.2 Soap Solution. Obtain commercially leak detection solution, or prepare by using 

concentrated detergent and water. Place in pressure sprayer or squeeze bottle. 

8.0 Sample Collection, Preservation, Storage, and Transport. 

8.1 Instrument Performance Evaluation. 

8.1.1 Prepare the VOC instrument according to the procedures in Method 21, except 

that a response factor need not be determined. The gas being measured is natural gas and 

the instrument is being calibrated with methane, the principal component of natural gas. 

8.1.2 Calibrate the instrument with methane. Introduce the calibration gas 

mixture to the analyzer and record the observed meter reading. Introduce zero gas until a 

stable reading is obtained. Make a total of three measurements by alternating between 

the calibration gas and zero gas. 

8.1.3 Calibration Precision. The calibration precision test must be completed prior to 

placing the analyzer into service and at subsequent 3-month intervals or at the next use, 

whichever is later. 

8.1.3.1 Make a total of three measurements by alternately using zero gas and the 

specified calibration gas. Record the meter readings. Calculate the average algebraic 

difference between the meter readings and the known value. Divide this average 

difference by the known calibration value and multiply by 100 to express the resulting 

calibration precision as a percentage. 

8.1.3.2 The calibration precision shall be equal to or less than 10 percent of the 

calibration gas value. 

8.1.4 Response Time. The response time test is required before placing the instrument 

into service. If a modification to the sample pumping system or flow configuration is 

made that would change the response time, a new test is required before further use. 

8.1.4.1 Introduce zero gas into the instrument sample probe. When the meter reading 

has stabilized, switch quickly to the specified calibration gas. After switching, measure 

the time required to attain 90 percent of the final stable reading. Perform this test 

sequence three times and record the results. Calculate the average response time. 

8.1.4.2 The instrument response time shall be equal to or less than 30 seconds. The 

instrument pump, dilution probe (if any), sample probe, and probe filter that will be used 

during testing shall all be in place during the response time determination. 

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8.2 Pre-Screening Using Soap Solution. Use the following procedure for 

those sources that do not have: 

•	 Continuously moving parts, e.g., rotating shaft seals where soap solution is slung off. 

•	 Very hot components (above boiling point of soap solution) 

•	 Very cold components (below the freezing point of the soap solution) 

•	 Components with seal area facing down (where soap solution will not readily pool) 

•	 Components that process fluids that are liquid at ambient conditions (where liquid can 

leak through and float to the top of the soap solution before evaporating) 

•	 Components with seal areas not easily accessible for observation. 

8.2.1 Spray the soap solution over potential leak source and observe for soap 

bubbles. 

8.2.2 If soap bubbles are not observed, the source is presumed to have no detectable 

emissions or leaks. If soap bubbles are observed, use the procedure in Section 8.2. 

8.3 Pre-Screening Using Method 21. Use the following procedure for the following 

sources: 

•	 All applicable sources. 

•	 Those sources listed under Section 8.1. 

•	 Those sources where soap bubbles are observed. 

8.3.1 Use Method 21 to determine VOC concentration. 

8.3.2 If the concentration is ≤500 ppm, the source is presumed to have no leaks. If the 

concentration is >500 ppm, use the procedure in Section 8. to determine whether 

corrective action should be taken. 

8.4 Determination of Mass Emission Rate. Use the following procedure 

whenever the Method 21 prescreening results indicate a concentration of >500 ppm. 

8.4.1 Use the Hi-Flowθ to determine the mass emission rate 

8.4.2 Attach the probe tip attachments suitable for the applicable source. 

8.4.3 Turn on the pump, set the flow rate to 2 scfm, and record the concentration 

in ppm. 

8.4.4 Reset the flow rate to 3 scfm, and record the concentration in ppm. 

8.4.5 Measure the background concentration. 

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8.4.6 Calculate the mass emission rate according to the equation in Section 12. 

Compare the mass emission rates at each flow rate. If the difference is greater than 10 

percent, do one of the following until the mass emission rates at two flow rates agree to 

within ±10 percent. 

• check the probe attachment for tightness of fit and repeat the test, 

• repeat the test at higher flow rates, 

8.4.7 When the mass emission flow rates agree to within ±10 percent, average 

the results and compare the results to the criteria in Section 3. If greater, repair the leak. 

9.0 Quality Control. 

10.0 Calibration and Standardization. 

10.1 VOC Monitoring Instrument. Calibrate the VOC monitoring instrument as 

follows. After the appropriate warm-up period and zero internal calibration procedure, 

introduce the calibration gas into the instrument sample probe. Adjust the instrument 

meter readout to correspond to the calibration gas value. 

Note: If the meter readout cannot be adjusted to the proper value, a malfunction of the 

analyzer is indicated and corrective actions are necessary before use. 

10.2 Flow Meter. Calibrate the thermal anemometer according to the 

procedure in Method 2, except use the thermal anemometer in place of the Type S pitot 

tube. Measure the cross-sectional area of the manifold. 

11.0 Analytical Procedures. [Reserved] 

12.0 Data Analyses and Calculations. 

12.1 Mass Emissions. Calculate the mass emissions by the following equation: 

ER = FR * (SC - BC) * 10-6 

where: 

ER = emission rate, scfm of CH4 

FR = sampling flow rate, scfm 

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SC = sample concentration, ppm
 

BC = background concentration, ppm
 

13.0 Method Performance. 

13.1 Lower Detection Limit. The lower detection limit shall be at 100 ppm at a 

flow rate of 2 scfm. 

13.2 

14.0 Pollution Prevention. [Reserved] 

15.0 Waste Management. [Reserved] 

16.0 References. 

1. Dubose, D.A., and G.E. Harris. Response Factors of VOC Analyzers at a Meter 

Reading of 10,000 ppmv for Selected Organic Compounds. U.S. Environmental 

Protection Agency, Research Triangle Park, NC. Publication No. EPA 600/2-81051. 

September 1981. 

2. Brown, G.E., et al. Response Factors of VOC Analyzers Calibrated with Methane 

for Selected Organic Compounds. U.S. Environmental Protection Agency, Research 

Triangle Park, NC. Publication No. EPA 600/2-81-022. May 1981. 

3. DuBose, D.A. et al. Response of Portable VOC Analyzers to Chemical Mixtures. 

U.S. Environmental Protection Agency, Research Triangle Park, NC. Publication No. 

EPA 600/2-81-110. September 1981. 

4. Handbook of Hazardous Materials: Fire, Safety, Health. Alliance of American 

Insurers. Schaumberg, IL. 1983. 

17.0 Tables, Diagrams, Flowcharts, and Validation Data. [Reserved] 

141