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 – 8 th Ave. S.W. Calgary, Alberta

T2P 3M3

June 20, 2002EXECUTIVE 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 (H 2 S), nitrogen (N 2 ), carbon dioxide (CO 2 ) and water vapor (H 2 O). 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 CO 2 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 CO 2 ), and to a lesser extent, non-methane hydrocarbon (NMHC) emissions. All GHG emissions are expressed as CO 2 -equivalent emissions (CO 2 E) 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.

iThe 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 StatesPercent 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 CO 2 E and 9,509.3 t/y (1,369.3 mscfd), respectively. While the primary focus of this study was to identify GHG (methane) lossopportunities, 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

iidioxide 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 CO 2 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

iiiservice 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

ivcauses 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 CO 2 E 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 CO 2 E 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.

vOther 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-controlnatural 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, H 2 S 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.

vi• 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.

viiTABLE 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

viiiTABLE 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

ixLIST 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 HiFlow TM 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 CO 2 E emission reductions at surveyed gas plants

...................................................................................................................... 38

xxiLIST 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

xiiGLOSSARY

Blow-By

Carbon Dioxide Equivalent (CO 2 E) ­

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 (CO 2 ), methane (CH 4 ) and nitrous oxide (N 2 O). 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: CO 2 = 1.0,

CH 4 = 21.0 and N 2 O = 310.

Greenhouse gas emissions are converted to carbon dioxide equivalent (CO 2 E) emissions by multiplying the mass emissions of each gas by the appropriate global warming potential and summing the CO 2 E emissions. CO 2 E emissions are expressed in metric tonnes.

Centrifugal compressors generally require shaft-end sealsbetween 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 H 2 O, CO 2 and SO 2 ). 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.

xiiiConnectors ­

Crankcase ­

Destruction Efficiency ­

Flare and vent systems ­

Fugitive Emissions ­

Gas Plant ­ A connector is any flanged or threaded connection, ormechanical 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 H 2 O, H 2 S and CO 2

xivHeat 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 adual-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 tofacilitate 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

xvPower 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 CO 2 , H 2 O, SO 2 , 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

xviformed).

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 m 3 /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

xviiAlternatively, thermal efficiency may be expressed in terms of energy losses as follows:

⎛ ⎞ Σ Energy 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.

xviiiThe 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.

xixACKNOWLEDGEMENTS

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.

xx1.0 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 evaluatedwith 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 HiFlow TM 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 (10 3 m 3 /y), Estimated Repair Costs ($), Net Present Value of Repair ($), CO 2 E 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.

12.0 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.

2ppt96\Hummel\Jul\GRILOTT\2 

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

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 Equation Correlation Equation

Bagging Data Bagging

1 1 0 1 0 0 1 0 0 0 1 0 0 0 0 1 0 0 0 0 0

S

c r e e n i n g V a l u e ( p p m v )

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 HiFlow TM 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.

3With 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.

43.0 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 andthreaded 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.

6CRANKCASE

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.

7Figure 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 HiFlow TM Sampler was the primary method used to measure emission rates from leaking equipment components. Specific cases where the HiFlow TM Sampler was not used included any components leaking at rates above the upper limit of the unit (i.e., above about 14 m 3 /h for the current HiFlow TM 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 HiFlow TM Sampler.

The HiFlow TM 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 repairopportunity. To bag all leakers in order to differentiate between economic-to8repair 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 HiFlow TM 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 HiFlow TM and bagging measurements contain uncertainties of only about ±10 to 15 percent. Accordingly,

the HiFlow TM Sampler (shown in Figure 4) provides a practicable means of making objective repair decisions. The reliability and use of the HiFlow TM
Sampler has been demonstrated in a number of studies (Howard et al ., 1994; Lott

et al ., 1995).

The operating principle of the HiFlow TM 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 HiFlow TM , measures hydrocarbon concentrations in thecaptured 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 HiFlow TM 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 HiFlow TM 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 m 3 /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 HiFlow TM Sampler were calibrated 100 percent methane and 2.5 percent methane-in-air to cover both

9ranges 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 HiFlow TM Sampler at each site, and then periodically thereafter to ensure that no significant drift occurred. The HiFlow TM Sampler is also calibrated periodically by releasing known flowrates of methane into the sampler inlet and comparing the leak rate measured by the HiFlow TM 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 HiFlow TM 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

10was 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.

113.2.5 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.

12Figure 5.	 Typical crankcase vent configurations recommended by manufacturers for stationary compressor engines.

13Where 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, NO

x , CO 2 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 O 2 , CO, CO 2 , NO x, 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.

143.2.7 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).

153.3 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 CO 2 ­ 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,

16information 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 $158.95/10 3 m 3 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

17compared 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.

184.0 OVERVIEW OF THE RESULTS

This section provides an overview of the atmospheric emissions and natural gas lossesdetermined 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 CO 2 E 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 CO 2 and 21.0 for CH 4 ). 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.

19Figure 6. Distribution of Methane Emissions by Source CategoryFlare Systems1.6%Non-Leaking Components0.1%Amine VentsNRU Vents0.8%0.5%Storage TanksCombustion Equipment0.8%14.3%Leaking Components82.0%Total Methane Emissions = 5,104.4 tonnes per year20Figure 7. Distribution of Non-Methane Hydrocarbon Emissions by Source CategoryAmine VentsFlare Systems2.5%0.4%Non-Leaking Components0.1%Combustion Equipment1.3%NRU Vents0.8%Leaking Components36.9%Storage Tanks58.1%Total NMHC Emissions = 9,509.3 tonnes per year21Figure 8. Distribution of Total GHG Emissions by Source CategoryNon-Leaking Components0.03%NRU VentsFlare Systems0.1%1.8%Amine VentsStorage Tanks2.6%0.2%Leaking Components15.7%Combustion Equipment79.6%Total GHG Emissions = 558,527.7 tonnes CO2E per year224.2 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 $158.95/10 3 m 3 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).

23Table 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 Leakers 1

.

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

241 Excluding leakage into flare systems.

25Figure 9. Distribution of Natural Gas Losses by Source CategoryCombustion Equipment9.9%Amine Vents0.5%Flare Systems24.4%Leaking Components53.1%Non-leaking Components0.1%NRU Vents0.3%Storage Tanks11.8%Total Natural Gas Losses = 501,130 mscf per year26Figure 10. Distribution of Natural Gas Losses from Equipment Leaks by Type of ComponentPressure Relief Valves3.5%Pump SealsOrifice Meters1.9%0.1%Pressure RegulatorsOther Flow Meters0.4%0.2%ValvesOpen-Ended Lines26.0%11.1%Control Valves4.0%Blowdowns0.8%Compressor Seals23.4%Connectors24.4%Crankcase Vents4.2%Total Natural Gas Losses = 266,100 mscf per year27Table 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. EPA 1 U.S. EPA Gas

Facilities 2,3

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 Seals 4 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.

284.3.2 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 room 1 . 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.

29Figure 11. Average THC Emissions for Connectors by Gas StreamEmissions (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

30Figure 12. Average THC Emissions for Compressor Sources, Component TypeEmissions (kg/h/source) 0.00 0.50 1.00 1.50 2.00 2.50 3.00 3.50Emissions (kg/h/source) 1

177 22 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

31On 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 governors 2 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 2COGE N

: R

E CIP (v)

N

R U

( c)

C OMP: R ECI

P

( v)

D EH

Y

: MOLE (t c) HG REMOVAL

REF RI

G: C 3

( c, v

)

R E F RI

G:

TU

RB

O (c, v )

C OMP: ELEC (v ) COMP: TURB (v) SAL ES

S W

E ET

N:

A

MI

N

E FRAC: DEEPCUT (c ) DEHY: T E G

I N

LET SE

PA

RA

T ION

ST

O

R A G

E

NGL

S T AB

I LIZER

U TI

L I T IES

C O

GEN: T UR

B

(v) VRU: ELEC (v)

C

LA

U S Figure 14. Average THC Emissions for Control Valves by Component TypeEmissions (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 80 423 335

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 0.03002151 29511 8422 21811 1103045 59517 9318232601 5882 7272 5643 7121 2952 6543 08597712 549194 0.0100

0.0050

0.0000

33N R

U (c)

C OMP: R E C

I P (v

) REFRIG: C3 (c, v) DEHY: MOLE (tc)

N G

L Sto ra

ge

R

E FR

I G:

TUR B O

( c

, v )

CO

M

P

: TUR B (

v ) COGEN: RECIP (v) DEHY: TEG

COGE N

: TU RB

(v)

INL

E T SE P A

R ATION

FRA C

: DEEPCUT (c) UTILITIES

H G

R E M

OV

A

L

S A

LES SWEETN: AMINE

S T AB

I LIZER

C

O

M

P: ELE C

(v

)

VRU : E LEC ( 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 0.0800Emissions (kg/h/source)3245704519811 5092 3623 433157387411739758167619950379235262 017

35Table 6. Number of components and leak frequency at each of the four gas plants.ComponentSite 1Site 2Site 3Site 4TotalTotalLeakersLeakFreq.TotalLeakersLeakFreq.TotalLeakersLeakFreq.TotalLeakersLeakFreq.TotalLeakersLeakFreq.Connectors12,9362221.7112,1912191.8046,1343970.8610,8851871.7282,1461,0251.25BlockValves2,4272379.771,5671348.558,7714535.162,37124910.5015,1361,0737.09ControlValves1703520.592414719.50632325.061972713.711,24014111.37PressureReliefValves7011.434848.3321952.284812.08385112.86Regulators2900.001100.0010843.702129.5216963.5OrificeMeters1119.093438.828000.0042716.67167116.59OtherMeters5120.000--­--­100.00100.007114.29CrankcaseVents661005510020945.0055100362569.44OpenendedLines3664010.93301196.31384266.775597313.061,6101589.81PumpSeals29827.590--­--­4848.336116.67831315.66Compressor Seals22221004040100925458.705151100.0020616781.0736Blowdown Systems0--­--­0--­--­6233.330--­--­6233.33Total16,0735623.5014,4384653.2256,4969501.6814,1865944.20101,1932,6332.60374.3.4 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 CO 2 -equivalent emission reduction.

38Number 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).

391 

### Figure 18. Emissions from Economically Repairable SourcesNatural 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.

40Net Cost ($/t CO 2 E Reduction)500400300200100-1000020000400006000080000100000-200-300-400-500Figure 19. Net cost curve for cumulative CO2E emission reductions at surveyed gas plants.Cumulative GHG Emission Reduction (tonnes CO2E)Note. The cost of finding and evaluating these emission reduction opportunities is excluded.41Figure 19 shows that the incremental cost per tonne of CO 2 E 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 CO 2 E GHG emission reduction) is the amount of CO 2 E 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 CO 2 E 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.

44Table 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

455.0 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

46vents, 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).

476.0 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 LeakEmission 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.

48Appendix 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.

49Appendix 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.

50Appendix 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 · H 2 O

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

⋅ h

− ⋅ 

# (
m

& FUEL FUEL + m & AIR ⋅ h AIR m & FLUE h FLUE 

# )

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

51accounted. 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.

52The 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.

53Gas 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 (CO 2 ) 50 000 Oxygen (O 2 ) 123 000 Carbon Monoxide (CO) 967 Nitrous Oxide (NO) 1 415 Nitrogen Dioxide (NO 2 ) 609 Oxides of Nitrogen (NO

x ) 2 024 Hydrocarbons (THC) 0

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 259 Air Flow (m 3 /h) 5 167 Exhaust Flow (m 3 /h) 5 381 Combustion Efficiency 1 (%) 97.3

Stack Heat Losses 2 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 827 48 806 Carbon Monoxide (CO) 20.1 738 Oxides of Nitrogen (NO

x ) 0.251 6.80 Hydrocarbons (THC) 0.00 0

54Cost of Unnecessary Excess Air: $163

Value of Unburned Fuel: $6 Total Cost of Improper Operation: $169 Volume of Unnecessary Fuel Consumption: N/A

55Gas 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 (CO 2 ) 114 000 Oxygen (O 2 ) 11 000 Carbon Monoxide (CO) 2663 Nitrous Oxide (NO) 961 Nitrogen Dioxide (NO 2 ) 31 Oxides of Nitrogen (NO

x ) 991 Hydrocarbons (THC) 9 400

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 259 Air Flow (m 3 /h) 2 513 Exhaust Flow (m 3 /h) 2 753 Combustion Efficiency 1 (%) 96.7

Stack Heat Losses 2 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 799 48 637 Carbon Monoxide (CO) 24.35 658.1 Oxides of Nitrogen (NO

x ) 9.88 267.0 Hydrocarbons (THC) 5.55 150.0

Cost of Unnecessary Excess Air: $0

Value of Unburned Fuel: $4 877

56Total Cost of Improper Operation: $4 877 Volume of Unnecessary Fuel Consumption: 5.037 mscfd

57Gas 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 (CO 2 ) 120 000 Oxygen (O 2 ) 0 Carbon Monoxide (CO) 2 428 Nitrous Oxide (NO) 1 124 Nitrogen Dioxide (NO 2 ) 0 Oxides of Nitrogen (NO

x ) 0 Hydrocarbons (THC) 1 124

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 259 Air Flow (m 3 /h) 2 370 Exhaust Flow (m 3 /h) 2 611 Combustion Efficiency 1 (%) 95.2

Stack Heat Losses 2 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 775 47 975 Carbon Monoxide (CO) 20.8 561 Oxides of Nitrogen (NO

x ) 10.30 278 Hydrocarbons (THC) 16.43 444

Cost of Unnecessary Excess Air: $0

Value of Unburned Fuel: $9 420

58Total Cost of Improper Operation: $9 420 Volume of Unnecessary Fuel Consumption: 7.951 mscfd

59Gas 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 (CO 2 ) 24 000 Oxygen (O 2 ) 168 000 Carbon Monoxide (CO) 51 Nitrous Oxide (NO) 71 Nitrogen Dioxide (NO 2 ) 0 Oxides of Nitrogen (NO

x ) 71 Hydrocarbons (THC) 0

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 1 053 Air Flow (m 3 /h) 40 463 Exhaust Flow (m 3 /h) 40 848 Combustion Efficiency 1 (%) 98.2

Stack Heat Losses 2 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 867 50 464 Carbon Monoxide (CO) 2.17 58.5 Oxides of Nitrogen (NO

x ) 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

60Volume of Unnecessary Fuel Consumption: 1.193 mscfd

61Gas 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 (CO 2 ) 23 000 Oxygen (O 2 ) 170 000 Carbon Monoxide (CO) 21 Nitrous Oxide (NO) 50 Nitrogen Dioxide (NO 2 ) 0 Oxides of Nitrogen (NO

x ) 50 Hydrocarbons (THC) 0

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 1 053 Air Flow (m 3 /h) 41 997 Exhaust Flow (m 3 /h) 42 664 Combustion Efficiency 1 (%) 98.2

Stack Heat Losses 2 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 870 50 545 Carbon Monoxide (CO) 0.934 25.3 Oxides of Nitrogen (NO

x ) 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

62Volume of Unnecessary Fuel Consumption: 0.515 mscfd

63Gas 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 (CO 2 ) 120 000 Oxygen (O 2 ) 0 Carbon Monoxide (CO) 12 Nitrous Oxide (NO) 1499 Nitrogen Dioxide (NO 2 ) 8 Oxides of Nitrogen (NO

x ) 1507 Hydrocarbons (THC) 900

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 267 Air Flow (m 3 /h) 2 501 Exhaust Flow (m 3 /h) 2 7471 Combustion Efficiency 1 (%) 97.5

Stack Heat Losses 2 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 841 49 760 Carbon Monoxide (CO) 104.6 2.83 Oxides of Nitrogen (NO

x ) 14.1 381 Hydrocarbons (THC) 4.23 114

Cost of Unnecessary Excess Air: $0

Value of Unburned Fuel: $1 972

64Total Cost of Improper Operation: $1 972 Volume of Unnecessary Fuel Consumption: 1.378 mscfd

65Gas 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 (CO 2 ) 73 000 Oxygen (O 2 ) 83 000 Carbon Monoxide (CO) 207 Nitrous Oxide (NO) 1 246 Nitrogen Dioxide (NO 2 ) 272 Oxides of Nitrogen (NO

x ) 1 518 Hydrocarbons (THC) 3 200

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 267 Air Flow (m 3 /h) 3 704 Exhaust Flow (m 3 /h) 3 939 Combustion Efficiency 1 (%) 95.0

Stack Heat Losses 2 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 795 48 527 Carbon Monoxide (CO) 2.92 78.8 Oxides of Nitrogen (NO

x ) 25.1 678 Hydrocarbons (THC) 20.2 547

Cost of Unnecessary Excess Air: $0

Value of Unburned Fuel: $9 679

66Total Cost of Improper Operation: $9 679 Volume of Unnecessary Fuel Consumption: 6.929 mscfd

67Gas 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 (CO 2 ) 67 000 Oxygen (O 2 ) 94 000 Carbon Monoxide (CO) 189 Nitrous Oxide (NO) 357 Nitrogen Dioxide (NO 2 ) 30 Oxides of Nitrogen (NO

x ) 387 Hydrocarbons (THC) 3 300

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 267 Air Flow (m 3 /h) 3 969 Exhaust Flow (m 3 /h) 4 201 Combustion Efficiency 1 (%) 94.7

Stack Heat Losses 2 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 788 48 319 Carbon Monoxide (CO) 2.89 78.0 Oxides of Nitrogen (NO

x ) 6.59 178 Hydrocarbons (THC) 23.29 629

Cost of Unnecessary Excess Air: $0

Value of Unburned Fuel: $11 085

68Total Cost of Improper Operation: $11 085 Volume of Unnecessary Fuel Consumption: 7.904 mscfd

69Gas Processing Plant 1

Equipment Information

Unit Identifier: TEG Reboiler

Boiler Make and Model:

Rated Power:

Measured Exhaust Gas Composition

Pollutant Concentration (ppm) Carbon Dioxide (CO 2 ) 72 000 Oxygen (O 2 ) 34 000 Carbon Monoxide (CO) 9 Nitrous Oxide (NO) 60 Nitrogen Dioxide (NO 2 ) 0 Oxides of Nitrogen (NO

x ) 60 Hydrocarbons (THC) 0

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 15.3 Air Flow (m 3 /h) 165.1 Exhaust Flow (m 3 /h) 178.9 Combustion Efficiency 1 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 853 50 098 Carbon Monoxide (CO) 93.6 2.53 Oxides of Nitrogen (NO

x ) 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

7071Gas 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 (CO 2 ) 120 000 Oxygen (O 2 ) 0 Carbon Monoxide (CO) 3 137 Nitrous Oxide (NO) 27 Nitrogen Dioxide (NO 2 ) 0 Oxides of Nitrogen (NO

x ) 27 Hydrocarbons (THC) 0

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 229 Air Flow (m 3 /h) 2 124 Exhaust Flow (m 3 /h) 2 339 Combustion Efficiency 1 (%) 97.5

Stack Heat Losses 2 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 801 48 806 Carbon Monoxide (CO) 27.2 738 Oxides of Nitrogen (NO

x ) 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

72Volume of Unnecessary Fuel Consumption: 3.155 mscfd

73Gas 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 (CO 2 ) 120 000 Oxygen (O 2 ) 0 Carbon Monoxide (CO) 164 Nitrous Oxide (NO) 96 Nitrogen Dioxide (NO 2 ) 0 Oxides of Nitrogen (NO

x ) 96 Hydrocarbons (THC) 1 288

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 183 Air Flow (m 3 /h) 1 690 Exhaust Flow (m 3 /h) 1 860 Combustion Efficiency 1 (%) 97.3

Stack Heat Losses 2 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 824 49 439 Carbon Monoxide (CO) 1.42 38.4 Oxides of Nitrogen (NO

x ) 0.888 24.1 Hydrocarbons (THC) 6.26 170

Cost of Unnecessary Excess Air: $0

Value of Unburned Fuel: $2 053

74Total Cost of Improper Operation: $2 053 Volume of Unnecessary Fuel Consumption: 1.459 mscfd

75Gas 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 (CO 2 ) 120 000 Oxygen (O 2 ) 0 Carbon Monoxide (CO) 3 793 Nitrous Oxide (NO) 69 Nitrogen Dioxide (NO 2 ) 0 Oxides of Nitrogen (NO

x ) 69 Hydrocarbons (THC) 0

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 226 Air Flow (m 3 /h) 2 101 Exhaust Flow (m 3 /h) 2 315 Combustion Efficiency 1 (%) 97.3

Stack Heat Losses 2 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 792 48 546 Carbon Monoxide (CO) 32.9 892 Oxides of Nitrogen (NO

x ) 0.641 17.4 Hydrocarbons (THC) 0.00 0

Cost of Unnecessary Excess Air: $0

Value of Unburned Fuel: $2 808

76Total Cost of Improper Operation: $2 808 Volume of Unnecessary Fuel Consumption: 3.764 mscfd

77Gas 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 (CO 2 ) 120 000 Oxygen (O 2 ) 0 Carbon Monoxide (CO) 85 Nitrous Oxide (NO) 61 Nitrogen Dioxide (NO 2 ) 0 Oxides of Nitrogen (NO

x ) 61 Hydrocarbons (THC) 1 134

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 142 Air Flow (m 3 /h) 1 314 Exhaust Flow (m 3 /h) 1 446 Combustion Efficiency 1 (%) 97.5

Stack Heat Losses 2 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 827 49 523 Carbon Monoxide (CO) 0.734 19.9 Oxides of Nitrogen (NO

x ) 0.565 15.3 Hydrocarbons (THC) 5.52 150

Cost of Unnecessary Excess Air: $0

Value of Unburned Fuel: $1 379

78Total Cost of Improper Operation: $1 379 Volume of Unnecessary Fuel Consumption: 0.963 mscfd

79Gas 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 (CO 2 ) 57 000 Oxygen (O 2 ) 111 000 Carbon Monoxide (CO) 556 Nitrous Oxide (NO) 36 Nitrogen Dioxide (NO 2 ) 0 Oxides of Nitrogen (NO

x ) 36 Hydrocarbons (THC) 1 563

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 141 Air Flow (m 3 /h) 2 412 Exhaust Flow (m 3 /h) 2 534 Combustion Efficiency 1 (%) 95.7

Stack Heat Losses 2 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 789 48 497 Carbon Monoxide (CO) 9.96 270 Oxides of Nitrogen (NO

x ) 0.691 18.7 Hydrocarbons (THC) 15.8 427

Cost of Unnecessary Excess Air: $11 615

Value of Unburned Fuel: $4 334

80Total Cost of Improper Operation: $15 949 Volume of Unnecessary Fuel Consumption: 10.304 mscfd

81Gas 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 (CO 2 ) 59 000 Oxygen (O 2 ) 107 000 Carbon Monoxide (CO) 608 Nitrous Oxide (NO) 32 Nitrogen Dioxide (NO 2 ) 0 Oxides of Nitrogen (NO

x ) 32 Hydrocarbons (THC) 1 400

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 171 Air Flow (m 3 /h) 2 834 Exhaust Flow (m 3 /h) 2 991 Combustion Efficiency 1 (%) 96.0

Stack Heat Losses 2 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 794 48 624 Carbon Monoxide (CO) 10.5 285 Oxides of Nitrogen (NO

x ) 0.592 16.1 Hydrocarbons (THC) 13.6 369

Cost of Unnecessary Excess Air: $13 317

Value of Unburned Fuel: $4 678

82Total Cost of Improper Operation: $17 995 Volume of Unnecessary Fuel Consumption: 11.681 mscfd

83Gas 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 (CO 2 ) 59 000 Oxygen (O 2 ) 106 000 Carbon Monoxide (CO) 572 Nitrous Oxide (NO) 12 Nitrogen Dioxide (NO 2 ) 0 Oxides of Nitrogen (NO

x ) 12 Hydrocarbons (THC) 1 913

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 133 Air Flow (m 3 /h) 2 165 Exhaust Flow (m 3 /h) 2 280 Combustion Efficiency 1 (%) 95.3

Stack Heat Losses 2 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 782 48 303 Carbon Monoxide (CO) 9.73 264 Oxides of Nitrogen (NO

x ) 0.219 5.93 Hydrocarbons (THC) 18.3 497

Cost of Unnecessary Excess Air: $10 399

Value of Unburned Fuel: $4 644

84Total Cost of Improper Operation: $15 043 Volume of Unnecessary Fuel Consumption: 9.735 mscfd

85Gas 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 (CO 2 ) 57 000 Oxygen (O 2 ) 111 000 Carbon Monoxide (CO) 479 Nitrous Oxide (NO) 35 Nitrogen Dioxide (NO 2 ) 0 Oxides of Nitrogen (NO

x ) 35 Hydrocarbons (THC) 4 303

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 133 Air Flow (m 3 /h) 2 211 Exhaust Flow (m 3 /h) 2 328 Combustion Efficiency 1 (%) 91.1

Stack Heat Losses 2 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 720 46 608 Carbon Monoxide (CO) 8.29 225 Oxides of Nitrogen (NO

x ) 0.649 17.6 Hydrocarbons (THC) 41.9 1 137

Cost of Unnecessary Excess Air: $9 851

Value of Unburned Fuel: $10 056

86Total Cost of Improper Operation: $19 907 Volume of Unnecessary Fuel Consumption: 12.743 mscfd

87Gas 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 (CO 2 ) 33 000 Oxygen (O 2 ) 153 000 Carbon Monoxide (CO) 31 Nitrous Oxide (NO) 132 Nitrogen Dioxide (NO 2 ) 13 Oxides of Nitrogen (NO

x ) 144 Hydrocarbons (THC) 0

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 7 097 Air Flow (m 3 /h) 175 027 Exhaust Flow (m 3 /h) 180 593 Combustion Efficiency 1 (%) 98.2

Stack Heat Losses 2 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 563 50 255 Carbon Monoxide (CO) 0.844 27.1 Oxides of Nitrogen (NO

x ) 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

88Volume of Unnecessary Fuel Consumption: 3.660 mscfd

89Gas 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 (CO 2 ) 35 000 Oxygen (O 2 ) 149 000 Carbon Monoxide (CO) 28 Nitrous Oxide (NO) 122 Nitrogen Dioxide (NO 2 ) 15 Oxides of Nitrogen (NO

x ) 136 Hydrocarbons (THC) 0

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 7 097 Air Flow (m 3 /h) 164 481 Exhaust Flow (m 3 /h) 170 141 Combustion Efficiency 1 (%) 98.2

Stack Heat Losses 2 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 562 50 232 Carbon Monoxide (CO) 0.713 22.9 Oxides of Nitrogen (NO

x ) 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

90Volume of Unnecessary Fuel Consumption: 3.094 mscfd

91Gas 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 (CO 2 ) 55 000 Oxygen (O 2 ) 113 000 Carbon Monoxide (CO) 0 Nitrous Oxide (NO) 31 Nitrogen Dioxide (NO 2 ) 0 Oxides of Nitrogen (NO

x ) 31 Hydrocarbons (THC) 0

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 56 Air Flow (m 3 /h) 1 008 Exhaust Flow (m 3 /h) 1 056 Combustion Efficiency 1 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 849 50 108 Carbon Monoxide (CO) 0 0 Oxides of Nitrogen (NO

x ) 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

9293Gas 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 (CO 2 ) 90 000 Oxygen (O 2 ) 53 000 Carbon Monoxide (CO) 2 Nitrous Oxide (NO) 63 Nitrogen Dioxide (NO 2 ) 0 Oxides of Nitrogen (NO

x ) 63 Hydrocarbons (THC) 0

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 103 Air Flow (m 3 /h) 1 200 Exhaust Flow (m 3 /h) 1 293 Combustion Efficiency 1 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 845 50 002 Carbon Monoxide (CO) 0.069 1.86 Oxides of Nitrogen (NO

x ) 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

9495Gas 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 (CO 2 ) 81 000 Oxygen (O 2 ) 69 000 Carbon Monoxide (CO) 0 Nitrous Oxide (NO) 38 Nitrogen Dioxide (NO 2 ) 5 Oxides of Nitrogen (NO

x ) 42 Hydrocarbons (THC) 900

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 628 Air Flow (m 3 /h) 8 054 Exhaust Flow (m 3 /h) 8 618 Combustion Efficiency 1 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 828 49 541 Carbon Monoxide (CO) 0 0 Oxides of Nitrogen (NO

x ) 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

9697Gas 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 (CO 2 ) 81 000 Oxygen (O 2 ) 69 000 Carbon Monoxide (CO) 0 Nitrous Oxide (NO) 43 Nitrogen Dioxide (NO 2 ) 7 Oxides of Nitrogen (NO

x ) 50 Hydrocarbons (THC) 500

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 533 Air Flow (m 3 /h) 6 855 Exhaust Flow (m 3 /h) 7 332 Combustion Efficiency 1 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 836 49 755 Carbon Monoxide (CO) 0 0 Oxides of Nitrogen (NO

x ) 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

9899Gas 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 (CO 2 ) 26 000 Oxygen (O 2 ) 165 000 Carbon Monoxide (CO) 140 Nitrous Oxide (NO) 4 Nitrogen Dioxide (NO 2 ) 7 Oxides of Nitrogen (NO

x ) 10 Hydrocarbons (THC) 0

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 24 Air Flow (m 3 /h) 856 Exhaust Flow (m 3 /h) 872 Combustion Efficiency 1 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 851 50 168 Carbon Monoxide (CO) 5.54 150 Oxides of Nitrogen (NO

x ) 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

100101Gas 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 (CO 2 ) 23 000 Oxygen (O 2 ) 170 000 Carbon Monoxide (CO) 9 Nitrous Oxide (NO) 4 Nitrogen Dioxide (NO 2 ) 5 Oxides of Nitrogen (NO

x ) 8 Hydrocarbons (THC) 0

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 24 Air Flow (m 3 /h) 938 Exhaust Flow (m 3 /h) 953 Combustion Efficiency 1 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 861 50 455 Carbon Monoxide (CO) 0.399 10.8 Oxides of Nitrogen (NO

x ) 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

102103Gas 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 (CO 2 ) 51 000 Oxygen (O 2 ) 121 000 Carbon Monoxide (CO) 360 Nitrous Oxide (NO) 265 Nitrogen Dioxide (NO 2 ) 57 Oxides of Nitrogen (NO

x ) 322 Hydrocarbons (THC) 0

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 255 Air Flow (m 3 /h) 4 999 Exhaust Flow (m 3 /h) 5 210 Combustion Efficiency 1 (%) 98.0

Stack Heat Losses 2 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 864 49 615 Carbon Monoxide (CO) 7.42 198 Oxides of Nitrogen (NO

x ) 7.79 207 Hydrocarbons (THC) 0.00 0

Cost of Unnecessary Excess Air: $0

Value of Unburned Fuel: $715

104Total Cost of Improper Operation: $715 Volume of Unnecessary Fuel Consumption: 0.978 mscfd

105Gas 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 (CO 2 ) 49 000 Oxygen (O 2 ) 125 000 Carbon Monoxide (CO) 243 Nitrous Oxide (NO) 151 Nitrogen Dioxide (NO 2 ) 15 Oxides of Nitrogen (NO

x ) 166 Hydrocarbons (THC) 0

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 255 Air Flow (m 3 /h) 5 203 Exhaust Flow (m 3 /h) 5 413 Combustion Efficiency 1 (%) 98.1

Stack Heat Losses 2 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 868 49 720 Carbon Monoxide (CO) 5.24 140 Oxides of Nitrogen (NO

x ) 4.02 107 Hydrocarbons (THC) 0.00 0

Cost of Unnecessary Excess Air: $0

Value of Unburned Fuel: $505

106Total Cost of Improper Operation: $505 Volume of Unnecessary Fuel Consumption: 0.690 mscfd

107Gas 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 (CO 2 ) 49 000 Oxygen (O 2 ) 126 000 Carbon Monoxide (CO) 253 Nitrous Oxide (NO) 302 Nitrogen Dioxide (NO 2 ) 59 Oxides of Nitrogen (NO

x ) 361 Hydrocarbons (THC) 0

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 255 Air Flow (m 3 /h) 5 265 Exhaust Flow (m 3 /h) 5 473 Combustion Efficiency 1 (%) 98.1

Stack Heat Losses 2 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 867 49 712 Carbon Monoxide (CO) 5.53 147 Oxides of Nitrogen (NO

x ) 9.19 245 Hydrocarbons (THC) 0.00 0

Cost of Unnecessary Excess Air: $0

Value of Unburned Fuel: $532

108Total Cost of Improper Operation: $532 Volume of Unnecessary Fuel Consumption: 0.728 mscfd

109Gas 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 (CO 2 ) 51 000 Oxygen (O 2 ) 121 000 Carbon Monoxide (CO) 449 Nitrous Oxide (NO) 265 Nitrogen Dioxide (NO 2 ) 186 Oxides of Nitrogen (NO

x ) 451 Hydrocarbons (THC) 0

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 255 Air Flow (m 3 /h) 5 003 Exhaust Flow (m 3 /h) 5 215 Combustion Efficiency 1 (%) 97.9

Stack Heat Losses 2 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 861 49 538 Carbon Monoxide (CO) 9.28 247 Oxides of Nitrogen (NO

x ) 12.18 324 Hydrocarbons (THC) 0.00 0

Cost of Unnecessary Excess Air: $0

Value of Unburned Fuel: $893

110Total Cost of Improper Operation: $893 Volume of Unnecessary Fuel Consumption: 1.221 mscfd

111Gas 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 (CO 2 ) 47 000 Oxygen (O 2 ) 127 000 Carbon Monoxide (CO) 438 Nitrous Oxide (NO) 326 Nitrogen Dioxide (NO 2 ) 167 Oxides of Nitrogen (NO

x ) 493 Hydrocarbons (THC) 0

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 255 Air Flow (m 3 /h) 5 324 Exhaust Flow (m 3 /h) 5 533 Combustion Efficiency 1 (%) 97.9

Stack Heat Losses 2 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 861 49 541 Carbon Monoxide (CO) 9.70 258 Oxides of Nitrogen (NO

x ) 13.80 368 Hydrocarbons (THC) 0.00 0

Cost of Unnecessary Excess Air: $0

Value of Unburned Fuel: $933

112Total Cost of Improper Operation: $933 Volume of Unnecessary Fuel Consumption: 1.276 mscfd

113Gas 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 (CO 2 ) 110 000 Oxygen (O 2 ) 12 000 Carbon Monoxide (CO) 984 Nitrous Oxide (NO) 39 Nitrogen Dioxide (NO 2 ) 10 Oxides of Nitrogen (NO

x ) 49 Hydrocarbons (THC) 0

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 223 Air Flow (m 3 /h) 2 219 Exhaust Flow (m 3 /h) 2 424 Combustion Efficiency 1 (%) 98.0

Stack Heat Losses 2 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 855 49 384 Carbon Monoxide (CO) 9.20 245 Oxides of Nitrogen (NO

x ) 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

114Volume of Unnecessary Fuel Consumption: 1.057 mscfd

115Gas 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 (CO 2 ) 111 000 Oxygen (O 2 ) 11 000 Carbon Monoxide (CO) 832 Nitrous Oxide (NO) 447 Nitrogen Dioxide (NO 2 ) 14 Oxides of Nitrogen (NO

x ) 461 Hydrocarbons (THC) 0

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 233 Air Flow (m 3 /h) 2 213 Exhaust Flow (m 3 /h) 2 418 Combustion Efficiency 1 (%) 98.0

Stack Heat Losses 2 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 857 49 444 Carbon Monoxide (CO) 7.75 206 Oxides of Nitrogen (NO

x ) 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

116Volume of Unnecessary Fuel Consumption: 0.890 mscfd

117Gas 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 (CO 2 ) 111 000 Oxygen (O 2 ) 11 000 Carbon Monoxide (CO) 332 Nitrous Oxide (NO) 198 Nitrogen Dioxide (NO 2 ) 7 Oxides of Nitrogen (NO

x ) 205 Hydrocarbons (THC) 0

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 233 Air Flow (m 3 /h) 2 214 Exhaust Flow (m 3 /h) 2 419 Combustion Efficiency 1 (%) 98.2

Stack Heat Losses 2 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 865 49 639 Carbon Monoxide (CO) 3.09 82.6 Oxides of Nitrogen (NO

x ) 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

118Volume of Unnecessary Fuel Consumption: 0.355 mscfd

119Gas 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 (CO 2 ) 36 000 Oxygen (O 2 ) 145 000 Carbon Monoxide (CO) 89 Nitrous Oxide (NO) 1 514 Nitrogen Dioxide (NO 2 ) 631 Oxides of Nitrogen (NO

x ) 2 145 Hydrocarbons (THC) 0

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 342 Air Flow (m 3 /h) 9 026 Exhaust Flow (m 3 /h) 9 284 Combustion Efficiency 1 (%) 97.7

Stack Heat Losses 2 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 875 49 931 Carbon Monoxide (CO) 2.55 67.8 Oxides of Nitrogen (NO

x ) 76.07 2 025 Hydrocarbons (THC) 0 0

Cost of Unnecessary Excess Air: $0

Value of Unburned Fuel: $328

120Total Cost of Improper Operation: $328 Volume of Unnecessary Fuel Consumption: 0.449 mscfd

121Gas 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 (CO 2 ) 38 000 Oxygen (O 2 ) 141 000 Carbon Monoxide (CO) 781 Nitrous Oxide (NO) 1 149 Nitrogen Dioxide (NO 2 ) 333 Oxides of Nitrogen (NO

x ) 1 482 Hydrocarbons (THC) 0

Stream Flows at 15oC and 101.325 kPa Fuel Consumption (m 3 /h) 342 Air Flow (m 3 /h) 8 469 Exhaust Flow (m 3 /h) 8 737 Combustion Efficiency 1 (%) 97.3

Stack Heat Losses 2 (%) 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/10 3 m 3 of Fuel Input ng/J of Fuel Input Carbon Dioxide (CO 2 ) 1 846 49 137 Carbon Monoxide (CO) 20.88 556 Oxides of Nitrogen (NO

x ) 47.54 1 265 Hydrocarbons (THC) 0 0

Cost of Unnecessary Excess Air: $0

Value of Unburned Fuel: $2 693

122Total Cost of Improper Operation: $2 693 Volume of Unnecessary Fuel Consumption: 3.681 mscfd

123Appendix IVAverage Equipment Component Schedules for Natural Gas Processing PlantsTable IV-1. Summary of average equipment component schedules for processes at natural gas processing plants.ProcessNumber of Emission Sources Associated with the ProcessGas ServiceLight Liquid ServiceVCVCRPRVOELOMOtherMeterBDCSCCVVCVCPRVOELPSClaus Plant1921191-4-----------Cogeneration:Reciprocating92711------1------Cogeneration: Turbine8922343151----------Compressor:Electric1428866-62--191815---Compressor:Reciprocating67216232419---612-3-1-Compressor:Turbine10010646131116--1-------Dehydration:Mole Sieve141198251513--1-------Dehydration:7743384251----5-13---124Table IV-1. Summary of average equipment component schedules for processes at natural gas processing plants.ProcessNumber of Emission Sources Associated with the ProcessGas ServiceLight Liquid ServiceVCVCRPRVOELOMOtherMeterBDCSCCVVCVCPRVOELPSTEGFlare130123921-2091---------Fractionation:Demethanizer38177--7-----15177121Fractionation:De-ethanizer523211-271----564197-142Fractionation:Depropanizer422152--1-----17151-23Fractionation:De-butanizer23169--6-----3-3-11Hg Removal98262-39-----------Inlet: Header27188--21----5-16---Inlet:Separation462175121----14156---NRU8312189-591----------Refrigeration32340263184441-8236257-2-125Table IV-1. Summary of average equipment component schedules for processes at natural gas processing plants.ProcessNumber of Emission Sources Associated with the ProcessGas ServiceLight Liquid ServiceVCVCRPRVOELOMOtherMeterBDCSCCVVCVCPRVOELPS: Propane1Refrigeration: TurboExpansion778242128---1-1524812-Sales: NG1135490--174----------Sales: NGL351105-12----107441851618Stabilization116648532461---1376406-26Storage: C5-3------------Storage:NGL632125-11-----12-1--2Sweetening:Amine17775411872----4115-1-Utilities141978913233----6118-1-VRU:Electric23218443------------126Appendix 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 CO 2 -equivalent reduction.

127Appendix 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

128Pressure 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 ...

129Table 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

130Valves 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 ...

131Table 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 ...

132Table 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

133Plug 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

134Appendix 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 HiFlow θ 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

135Leak 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 CH 4 10,000 10,000 10,000

scfm of CH 4 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 ____).

1366.2 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.

1377.1.2 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.

1388.2 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-Flow θ 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.

1398.4.6 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 CH 4 FR = sampling flow rate, scfm

140SC = 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