# I EPA Phase II Aggregate Site Report Cost-EffectiveDirectedInspection andMaintenance Control Opportunities at'Five GasProcessingPlants and Upstream Gatllering C0111pressorStations and WellSites

PREPARED FOR: Project Manager: Roger Fernandez U.S. Environmental ProteCtion Agency Natural Gas STAR Program U.S. EPA GrantNo: XA-83046001-1



### PREPARED BY: National Gas Machinery Laboratory, An Institute ofKansas State University 245 Levee Drive Manhattan, KS 66502 Clearstone Engineering Ltd. 700,900-6 Avenue S.W. Calgary, Alberta T2P 3K2 Innovative Environmental Solutions, Inc. P.O. Box 177, Cary, IL60013 CLEARSTONE ENGUmBRfNG 

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### EXECUTIVE SUMMARY A cdmprehensive measurement program has been conducted at five natural gasprocessing plants in the United States to identify cost.;.effective opportunities for reducing natural gas losses due to fugitive equiplnent leaks and avoidable process inefficiencies or wastage. This program, referred to as Phase II, followed a Phase I program that surveyed four gas plants in 2000

.. The second Phase study included upstrealn facilities such as well sites and gathering compressor stations in addition to the gas processing plants. The additional gas processing plants were selected to give a range ofplant size, locations, throughput, plant age, and both sweet and sour gas facilities to ensure that the results represented the entire natural gas processing industry. Raw natural gas is predominantly lnethane but lnay contain varying amounts ofnonmethane hydrocarbons (NMHC) and contaminants, such as hydrogen sulfide (H2S), nitrogen (N2), carbon dioxide (C02 ) and water vapor (H2 0). Natural gas losses to the atmosphere are direct emissions ofthese constituents. Natural gas losses into flare· systems or excess fuel consumption result in atmospheric emissions ofC02 and other combustion byproducts including unburned methane. Here, cost effective opportunities to reduce natural gas losses are seen priJnarily as a sensible means ofreducing methane and other greenhouse gas (OHO) emissions (predOlninantly CO2 ), and to a lesser extent, NMHC emissions. All OHOemissions are expressed as C02-equivalent emissions (C02 E) using a global warming potential of21 for methane. A baseline'assessment ofthe fugitive natural gas losses and target air pollutant elnissions at each host facility is provided, and the potential savings and emission reductions from natural 'gas loss decreases are highlighted. Additionally, total hydrocarbon (THC) elnission factors are presented for fugitive equiplnent leaks and the active natural gas-fuefed process equiplnent surveyed. All fieldwork was conducted duringthe first quarter 2004 and second quarter 2005. The work cOlnprised a fugitive-elnissions survey ofequipnient components in**hy~rocarbon** gas service, lneasurement and characterization offlows into all key vent arid flare systelns, and liJnited perfonnance testing ofnatural gas-fueled cOlnbustion equipment at three ofthe five surveyed sites. Elnissions from selected pressure reliefvalves vented to the flare were lneasured at two sites. Residual flaring activities were also determined. Although not specifically targeted, any components in hydrocarbon-liquid or air service thatwere noticeably leaking were tagged and broughtto the attention ofsite personnel. Complete cOlnponent co,unts were prepared for the surveyed equiplnent. The plants were also surveyed with an optical passive infrared Call1era designed specifically for leak detection. A cOlnparison between leak detection lnethods isincluded in this second Phase report.
.A total of74,438 individual equipment components from five gas processing facilities, 12 well sites, and**s~ven** upstreaJn gathering compressor stations were surveyed. Sufficient process information was collected to determine total annual emissions from the compiled measurementresults. Additionally, specific emission-control opportunities were identified, and apreliminary cost-benefitanalysis was performed to evaluate these opportunities. The analysis considered the estimated cost ofrepair and corresponding lifetime and the conserved gas value. Site personnel were solicited to provide input and assistance in identifyingsite-specific constraints and to help ensure that cost data were satisfactorily considered. 

### EMISSIONS INVENTORY OVERVIEW Total atmospherk methane elnissions from all sources atthe combined sites are estimated at 8,071 tonnes peryear. Corresponding GHG and NMHC emissions are estimated at 598,184tonnesperyear C02E and 3,625 tonnes peryear, respectively. The majority of total methane emissions resulted from fugitive equipInent leaks (55%). Incomplete combustion by natural gas-fuelled equipment and process venting arealso noteworthy Inetqane emissions sources (17% and 16%, respectively). The major GHG emissions sources are fuel consumption by COlnpressor engines and process heaters (74%), fugitive equipment leaks (17%), process venting (5%), and flare/vent systems (3%). Fugitive equipment leaks are the prilnary NMHC emissions source (73%). In general, gathering COlnpressor stations offered cost-effective opportunities with the Inajority ofthe methane elnissions frOln fugitive leaks associated with leaking COlnpressors. From the twelve wells surveyed, opportunities exist at well heads that have separators, tanks, and heater treaters. 

### NATURAL GAS LOSSES OVERVIEW The value ofall five sites natural gas losses

- including direct atInospheric emissions, gas leakage into flare systems, and excess fuel consUlnption by process equipment

- is estimated to be $8.4 Inillion peryear (an average of$1.7 Inillion peryearper.plant). The fugitive emission opp0l1unities totalled $2.9 Inillion dollar or $580,000perfacility per year. The costto survey and repairthese leaks is approximately $ 74,200 per facility (Le. survey cost for one site at $25,000 plus cost ofrepairs for leakers with positive net present value, averaged $49,200per site). These estimates do not include the cost ofidentifying and evaluating natural gas loss reduction opportunities; however, such costs are typically SInal] compared to the net benefit obtained. For example,the current five site survey costs;, when expressed in terms ofthe total number ofconlponents in gas service, were approxiInately $1.5 per cOlnponent, which is Inore than the cost ofconventional VOC 

### LDARprograms. This per cOlnponent cost Inay be reduced ifaroutine survey were to beimplemented and maybe aJ1ificially high as a result ofthe 

### R&D activities. Actual per-cOlnponent costs vary between facilities and tend to increase with the operation c0111plexity, facility remoteness, work condition severity, and the relative number ofvents, combustion' sources and control opportunities identified. The current study identified more than $3,200 in annual

iigross**savings~** or $3,000 in net savings (including afterrepair or control costs), per componentfor control opportunities having a less than a I-yearpaybackbased on a gas value of$7.15/Mscf($6.78/GJ). Considering opportunity ide'ntificationcostsreduces the net savings by only about 4%. Ifa value is assigned to the resulting GHG credits, work is done as a routine commercial service ratherthan as a study, and efforts are focused on the plant areas most likely to offermeaningful control opportunities, improved economics would be**realized~** Overall, it is.estimated that up to 96.60/0 oftotal fugitive natural gas losses are costeffective to reduce with no net financial burden to surveyed sites. Ifthe cost ofnatural gas increases, the number ofcomponents that are cost effective to repairwill not increase significantly however, the savingrealized will scale commensurate with the price increase. These reductions wouldresult in.emission reductions of61 % for methane, 17% for GHG C02E, and 67% forNMHC considering emissions from all sources. The relatively low impact on GHG C02E emissions is due to the significant contribution of CO2 emissionsfrom fuel consUlnption to total GHG emissions. The main**cost~effective** control opportunities identified atthe sites are:



### • Fugitive EquipmentLeaks: Approximately 2.2% ofthe equiplnent cOlnponents (approximately 1,629 out of 74,438) in**hydro~arbon** service were detennined to be leaking (Le., had a screening value of 10,000 ppm or more) atthe cOlnbined sites. Commensurate with the findings from the initial gas plant surveys, components in vibrational, high-use, and thermal-cycle gas services were the most leakprone. The majority ofthe identified natural gas losses from fugitive equipment leaks were attributed to a relatively slnall number ofleaking cOlnponents. Open-ended'lines emissi'ons were the greatest contributorto this source category, accounting for 320/0 ofthe total, followed by connectors (300/0), COlnpressor seals (20%), and blockvalves (15%). The relnaining 3% were from pressure reliefvalves, regulators, orifice meters, control valves, and crank case vents. It is estiJnated that iJnplementing all cost-effective equiplnent-repair or replacelnent opportunities identified would reduce natural gas losses from

### fugitive equipment leaks by 96.6% and result in gross annual cost savings of approximately $2.9 million (based ona gas value $7.l5/Mscfor $6.78/GJ). This equates to an average gross annual savings ofapproxiJnately $580,000 per site. Site-specific values ranged from $75,646 to $1.2 million. Lower losses and fewer loss-reduction opportunities would be expected at newerplants. Conversely, higher losses and more loss-reduction opportunities would likely be found at older and/orpoorly lnaintained plants. Repairs to the 1

# ° largest elnitting cost-effective-to-repair cOlnponents at-each site (referto AppendixI for a CQlnponents listranked by elnission rate) would reduce natural gas losses by approximately 521 Mscfd, or 58%.

iii

### • Flaring: The five sites flare or main vent systems residual gas flows (i.e., flows excluding blowdown andelnergency reliefevents) totalled 496 Mscfd. In several cases, the system flows were sufficientto potentiallyjustify installing av.ent- or flare-gas recovery unit. Alternatively, the residual gas flow source or sources (e.g., excess purge gas consumption and leakingpressure-reliefdevices, drains, andblowdown .valves connected to the flare header) could be repaired. However; these sources are often difficult to isolate, usually require a Inajorplant shutdown to fix, and are likely to reoccur. Installing economically feasible flare-gas recov.ery units would reduce surveyed plants GHG emission by approximately 16,609 tonnes 

### C02E per year, and take less than ayeartopay out.
.



### • Natural**Gas~Fueled** 

### Process Equipment: While several ofthe compressor engines tested would have benefited from tuning, Inost units proved to be operating efficiently (Le., air-to-fuelratios and flue gas cOlnbustibles concentrations.were at or near Inanufacturers recommended values). This likely reflects the high attention level typically given to cOlnbustion equipment at continuously Inanned facilities such as those surveyed. Greater cOlnbustion efficiency improvelnent opportunities are believed to existfor tuning heaters and engines'atumnanned field facilities. Total avoidable fuel consumption from servicing all econOlnic-to-tune engines and heaters atthe five sites is estiJnated to be 446 Mscfd, which equals GHG emission reductions of 13,100 tonnes 

### C02E peryear. The natural gas-fueled engines surveyed were all properly matched with the current process load requirelnents' (i.e., the units**w~re** operating within the optitnmn portion oftheirperformance curve). Notwithstanding this, situations Inay arise where engines are operated outside theirperformance curve optimum area (e.g., due to changes in original load requirements caused by production changes or initial equipment misInatching with process applications) causing significantexcessive operating costs. 

### KEY FINDINGS

• The value ofnatural gas losses from all five facilities in the Phase II DI&M survey - including direct atn10spheric emissions, gas leakage into**flar~** systems, and excess fuel consumption by process equipInent _.is estimated to be $8.4 n1illion peryear (an average of$1.7Inillion peryearperplant). The findings from these additional 5 plant surveys solidify the econOlnic benefits ofvoluntarily

, adopting a!1d initiating Dl&M.

IV.The table below summarizesthe finding from the Phase II 

### DI&M site surveys.

2 Sweet 28 12,330 23 $75,646 206 0.01 3 Sweet 39 18,353 117 $612,593 130 0.09 4 Sour 27 16,687 69 $193,978 45 0.15 5 Sour 57 4,778 423 $1,296,5-10' 87 0.48**'/~\,~I~~~.** ...:.,,}."<:;i<

... I".

... .. ... 14,887» .903{ 

### :<...**$~87;197A>·<Ig3.6.i\"I::",·:O.16/** 

### .... A This value excludes sources from combustJOn, flare actIvIties, well sItes and storage tanks.

• The results show that facilities surveyed with more than 30 years ofservice have significantly higher In.ethane emissions per volume gas throughput, and higher overall leak frequencies than facilities with less than 30 years ofservice. The facilities survey during this Phase ofthe prograJn ranged from 6 to 57 years with an average of30.4 years. Facilities processing sour gas havehigher methane elnissions pervolume gas throughout and leak frequencies than facilities processing sweet gas streaJns. Statistical comparisons for surveyed sites on the

. effects ofgas plant service years and process stream type were not attempted due to the limited number ofsites surveyed. 

### It is recommended that additional analyses, includingresults frOln the Phase I and other surveys, be conducted to develop statistically significant correlations offugitiveequiplnent leakrates with service years and process gas type
..

• A targeted 

### DI&M program aiJned atpro.ven opportunities can significantly reduce the tilne and resources required to identify and repairthose leaks thatrepresent the "low hanging fruit" within the facility. COlnponents associated with vibration (i.e. cOlnpressors) and heat-cycle (i.e. mole sieve) services contributed 97% ofthe total fugitive equiplnent leaks. These results again elnphasize that elnploying a targeted 

### DI&M program would significantly reduce the cost ofinitiating a

### DI&M program. However, significant additional opportunities were discovered at each site that would have been oV'erlooked ifthe scope was narrowed to only include these targeted sources.

• A Phase] test site was selected for retest in Phase II to determine changes in fugitive leaks characteristics. Ptocess changes at this site resulted in thirty percent ofthe Phase I components being decolnn1issioned. These process units were replaced priorto the Phase

# nsurvey. While fugitive emissions frOln the new process units cOlnponents tested in Phase

# nwere only 20% ofthe fugitive elnissions frOln thedecomlnissioned cOlnponents tested in Phase 

### I, the overall Phase 

## n site level fugitive elnissions were still 

### SO% higher than in Phase 

### 1. This

vindicates higher Phase II fugitive elnission leaks from 

### 700/0 ofcomponents that were notreplaced between Phases, and suggests thatthe facility DI&Mprogram has notbeen effective at controlling fugitive equipment leaks at this site. In addition, a comparison ofthe average Phase I and Phase II emission factors.by componenttype shows a very different distribution between Phase I and II sites.

vi

### TABLE OF CONTENTS Section EXECUTIVE SUMMARY ; i TABLE ·OF CONTENTS· vii LIST OF FIGURES ix LIST OF TABLES· xi GLOSSARY xii ACKNOWLEDGEMENTS ; xix 1 2 3

4

5 INTRODUCTION ; 1 BACKGROUND 2 METHODOLOGY 5 3.1 Elnissions Survey 5 3.1.1 COlnponent Screening ·6 3.1.2 LeakDetection Methods ._.._ ..

### 1 3.1.3 Leak-Rate Measurements 12 3.1.4 Vents and Open-ended Lines Elnissions Measurements 14 3.1.5 Residual Flaring Rates Determination 15 3.1.6 Natural Gas-Fueled Equipment Performance Testing 15 3.1.7 Compression EquipmentAnalysis 18 3.1.8 Storage Tanks Excess Emissions Evaluations : 19 3.1.9 COlnponent**Counts.~** 20 3.1.10 Average Emission Factors Developlnent. 21 3.1.11 Emission Control Guidelines**:.~** 21 3.2 Equipment Repair Cost-BenefitAnalyses 21 3.2.1 EquiplnentRepair CostEstimating 21 3.2.2 Natural Gas Value 22 3.2.3 RepairLife 22 3.2.4 Cost Curves 22 RESULTS ; 23. 4.1 Emission Inventory 23 4.2 Natural Gas Losses 27 4.3 Fugitive Equiplnent Leaks 27 4.3.1 Average Elnission Factors 27 4.3.2 Average Leak-Rate Trends 31 4.3.3 .LeakFrequencies 38 4.4 TankEmissions._ _.__.. .__. ._.__.__.__.. _.__._.._._ 40

. 4.5 .Results for Retested Site 40 4.5.1 Overall Plant 40 4.5.2 Replaced Process Units : 4] 4.6 Control Opportunities 43 4.6.1 CostCurve for Reduction ofGHG Emissions 43 4.6.2 Control Opportunities With a Payback of 1 Year orLess : 46 CONCLUSIONS AND RECOMMENDATIONS 47 5.1 Conclusions 47

vii·5.2 Recoirllnendations for FurtherWork. 48 

### 6 . REF·ERENCES C-lTED

.. ..; ;.; ;;;..; ..;**;.~;** 

### ;.; ; 50 Appendix I Measured THC Eluission Rates Sorted by Emission Rate 51 Appendix II Measured THC Emission Rates Sorted by PayoutPeriod 94 Appendix 

### III COlnbustion Analysis·and Efficiency TestingResults .134 Appendix IV
.Average Equipment COlnponent Schedules forNatural Gas Processing Plants .....................•............................•...............................367 Appendix V Financial Considerations and Assumptions 368 AppendixVI Basic COlnponentRepairCosts and Mean RepairLife 369 Appendix VII V-Pac Measurement 373

Vlll

### LIST OF FIGURES Figure Figure 

### 1 Leak Rate Vetsus Concentration 3 Figure 2 Survey Team Using Gas Detector To,Quantify Concentration And Screen 6 Figure 3 Physical Acoustics VPAC '\. 7 Figure 4 Residual Flaring 7

J Figure 5 Soap Solution Screening on a Two Inch Leaking Threaded Connector 10 Figure 

### 6 Tagged Leaking Components 10 Figure 7 Cut-Away View OfA Natural Gas COlTIpreSSor Showing The Potential Leak Points Including The COlTIpreSSor Seals And Crankcase Vent 

### 11 Figure 8 Prototype GRI HiFlowTM Sampler 

### 14 Figure 9 Typical Stationary CompressqrEngines Crankcase Vent Configurations Recommended By**Man~facturers** ..: 17 Figure 10 Distribution OfMethane By' Source Category For All Sources 24

Figure 15 Average THC Emissions For Connectors By Gas StremTIS 33 Figure 16 Average THC Emissions For Open-Ended Lines By Gas StremTI 33 Figure 17 Average THC Elnissions ForBlock Valves By Gas Stream 34 Figure 18 Average THC emissions**forco~nectors** by process unit. :.. 34 Figure 19 Average THC E1TIissions For Open-Ended Line By Process Unit 35 Figure 20 Average THC E1TIissions For Block Valves By Process Unit. : 35 Figure 21 Methane Emissions Per Unit Gas ThroughputFor Plants With Different Service Duration 36

ixFigure 22 Figure 

### F Methane Emissions Per Unit Gas ThroughputForPlants With -Different-Raw Gas·Type: : : ;; ;: : 37 Figure. 23 Methane Elnissions Percentage By Process Units 38 Figure 24 Total THC Emissions Between Phases 4] Figure 25 Component Emission Rate Between Phases 4]
I Figure 26Total THC Emissions Between Phases ; 42 Figure 27 COlnponentEmission Rate Between Phases 42 Figure 28 Emissions From'Economically Repairable Sources 45 Figure 29 Incremental Net Cost Curve For Cumulative C02E Emission Reductions At Surveyed Gas Plants 45

x

### LIST OF TABLES

Table I Sumlnary ofPlants Surveyed in Phase II v Table 1 Summary ofSurveyed Plants 5

. Table 2 Sumlnary ofFugitive Losses from the Top Ten Leakers 28

Table 3 Summary ofFugitive Leaks for Gas Plants, Gathering Compressor Stations, and Well ·Sites 28 Table 4 Comparison ofAverage THC Emission Factors Derived from Data Collected at the Test Sites to OtherPublished Values 31 Table 5 Number ofcon1ponents and leak frequency at each ofthe five gas plants

......... 39 Table 6 Losses frOln Storage Tanks 40 Table 7 Summary ofTop Ten Sources ofNatural Gas Losses Identified 46

XlBlow-By

CarbonDioxide Equivalent (C02E)

-

Centrifugal COlnpressor Seal SystelnsCombustion Efficiency

- GLOSSARY

Gas from apiston cylinderthat leaks pastthe piston rings into the crankcase. Carbon dioxide equivalentis an expressionofthe total elnissions frOln all the greenhouse gases; based on the gases relative ability to trap heat in the atmosphere. Greenhouse gases (GHGs) are atmospheric compounds that trap heat in the atmosphere by absorbing long-wave radiation frOln the earth's surface while allowing the sun's energy topass through. The mostrelevant GHGs for natural gas systelns are carbon dioxide (C02 ), methane (CH4) and nitrous oxide (N20). Global warming potentials (GWPs) were developed as a silnple measure ofthe global warming effects ofvarious greenhouse gases emissions relative to carbon ·dioxide emissions. The currentpractice (IPCC, 1996) is to use a 1OO-yeartilne horizon for global warming potentials. Therefore, the GWPs used in this document are: C02 

### = 1.0, CH4

### =21.0 and N2 0 

### = 310. Greenhouse gases emissions are converted to carbon dioxide equivalent (C02E) elnissions by multiplying the mass elnissionsofeach gas by the appropriate global warming potential and sUlnmingthe C02 E emissions. C02 E emissions are expressed in metric tonnes. Centrifugal cOlnpressors generally require shaft-end seals between the compressor and bearing housings. Either facecontact oil-lubricated Inechanical seals or oil-ring shaft seals, or dry-gas shaft seals are used. Seal leakage will tend to increase with wearbetween the seal and compressor shaft, operating pressure, and shaftrotational speed. The extentto which all input combustible Inaterial has been cOlnpletely oxidized (i.e., to produce H2 0, CO2and S02). COlnplete cornbustion is often approached but is never actually achieved. The main factors that contribute to incomplete combustion are thermodynmnic, kinetic, mass transfer and heatti"ansfer limitations. In fuel rich systems, oxygen deficiency is also a factor.

xiiConnectors

-

Crank CaseDestruction Efficiency

-

Flare and vent systems
-

Fugitive EmissionsGas PlantA connector is any flanged orthreaded connection, or mechanical coupling, but excludes all welded orbackwelded connections. Ifproperly installed and maintained" a connectorcanprovide essentially leak-free servicefor extended time periods. Howeyer, there are manyfactors '

,that can cause leakage problems. Common leak causes include vibration, thermal stress and cycles; dirty or damaged contact surfaces, incorrect sealing material, impropertightening, misalignment, and external abuse. The crank case on reciprocating engines and compressors houses the crank shaft and associated parts, and**typic~lly** an oilsupply to lubricate the crank shaft. Integral compressors have'a single crankcase because the engine and compressor share a c.ommon crank shaft. Non-integral compressors typically have two crank cases, one on the engine side and another on the compression side. The extentto which a target substance present in the input combustibles has been destroyed (i.e., converted to intermediate, partially-oxidized, and fully-oxidized products ofcombustion). DE is typically expresses as a percentage: 100 

## * (in

- out)/in. Venting and flaring are common disposal methods for gas processing plants waste gas. The stacks are designed to provide safe effluent dispersion. :F,lares are normally used where the waste gas contains odorous ortoxic components (e.g., hydrogen sulfide). Otherwise, the gas is usually vented. Typically, separate flare/vent systems are used for high- andlow-pressure waste gas streams. Unintentional leaks frOID equipment components including, butnot limited to, valves, flanges and other connections, pumps and compressors, pressure reliefdevices, process drains, open-endedvalves, pump and compressor seals, system degassing vents, accumulatorvessel 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 upgradingthe gas quality to market specifications (i.e.,**r~moving** contaminants such as H20, H2S and CO2and possibly adjusting the heatingvalue).

xiiiHeatRateIntegral Compressor

Methane Leak

Molecular Sieve

Long-Term Natural Gas ContractPrice - '

Open-ended Valves and LinesThe heat energy (based on thefuel net or lowerheating value) which Inustbe inputto a combustion device to produce the rated power output. H'eatrate is usually expressed in terms ofnetJ/kW·h. A reciprocating cOlnpressorthat shares a common· crankshaftand crankcase withthe engine. Greaterthan 10,000 parts per million as measured by a dual-element hydrocarbon detector (i.e., catalyticoxidation/thermal-conductivity). Absorbers composed ofzeolites (aluminosilicate crystalline polymers) used to relnove watervaporfrom natural gas. Zeolites are**r~generated** periodicallyby heating. Historically, long-term contracts have been used by buyers to secure a natural gas supply and by sellers to reduce large reserve developmentrisk. During the 1960s and 70s, these contracts wert: established for terms ofup to 20 to 25 years andthe gas price was detennined by periodic negotiations. The recent trend is towards shorter contract durations, and Inost new long-tenn contracts index the gas price to spot Inarketrates. Today, a typical long-term contractwith a cogenerationplant is about 15 years. Given the sellers and buyers interest in risk management, there is also a trend towards**great~r** standardization oflong-tenn contracts to facilitate hedging activity in the financial orthe over-thecountermarkets. An open-ended valve is any valve thatreleases process fluids directly to the atmosphere from valve seat leakage. The leakage may be caused by improper seating due to an obstruction or sludge accumulation, or a damaged orWorn seat An open-ended line is apipe ortube segment attached to a leaking valve and that opens to the atmosphere. Few open-ended valves and lines are designed into process systelns. However, actual numbers can be quite significant at SOlne sites due to poor operating practices and various process modifications that may occur overtime. Sonle commonexamples ofopen ended valves and lines are:

XIVPower Output

-

Pressure-Reliefor Safety Valves

-

Products ofIncOlnplete COlnbustion (PICs)

- e scrubber, compressor-unit, station, and mainline blowdown valves; e, supply-gas valve for a gas-operated engine starter (Le., where natural gas is the supply medium);
e instrumentblockvalves where the instrument has been removed for repair or otherreasons; and Ii purge or sampling points. The-net shaftpower available from an engine after all losses and powertake-offs (e.g., ignition-system power generators, cooling fans, turbo chargers and pumps for fuel, lubricating oil, and liquid coolant) have been subtracted. Forheaters and boilers, it is the netheattransferred t.o, a targetprocess fluid orsystem. Pressure reliefor safety valves are used to protectprocess 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 setpoint, and only open when the setpoint is exceeded. Reliefvalves open in proportion to the overpressure to provide modulated venting. Safety valves pop to a full-open position on activation. When reliefor safety valves reseat after activation, they often leak because the origiTlal tight seat iS Inotregained eitherdue to seating surface damage or foreign material build-up on the seatplug. As a result, they are often responsible for fugitive emissions. Anotherproblem develops ifthe operating pressure is too close to the set pressure, causingthe valve to "simmer" or "pop" atthe set pressure. Gas that leaks from apressure-reliefvalve may be detected atthe ventpipe (or horn) end. Additionally, there normally is a lnonltoring port located on the bottom ofthe horn near the valve. These are any compounds, excluding CO2 , H2 0, S02, HCI

- and HF, which contain C, H, S, CI orF and occur in combusted gases. These cOlnpounds may result from thermodynamic, kinetic ortransport lilnitations in the. various cOlnbustion zones. All input cOlnbustibles are potential PICs. Intermediate substances formed by dissociation and recombination effects may also occur as PICs (CO is often the lnost abundant combustible PIC

xvBlow-By

CarbonDioxide Equivalent (C02E)

-

Centrifugal COlnpressor ' Seal Systems

-

COlnbustion Efficiency

- GLOSSARY

Gas from apiston cylinderth3;t leaks pastthe piston rings into the crankcase. Carbon dioxide equivalent is an expressionofthe total elnissions from all the greenhouse gases, based on the gases relative ability to trap heat in the atmosphere. G'reenhouse gases (GHGs) are atmospheric compounds that trap heat in the atmosphere by'absorbing long-wave radiation from the earth's surface while allowing the sun's energy to pass through. The mostrelevant GHGs for natural gas systelns are carbon dioxide (C02 ), methane (CH4) and nitrous oxide (N20). Globalwarming potentials (GWPs) were developed as a simple measure ofthe global warming effects ofvarious greenhouse gases emissions relative to carbon dioxide emissions. The currentpractice (IPCC, 1996) is to use a 100-yeartime horizon forglobal warming potentials. Therefore, the GWPs used in this docUlnent are: C02 = 1.0, CH4 = 21.0 and N2 0 ='310. Greenhouse gases emissions are converted to carbon dioxide equivalent (C02 E) emissions by multiplying the mass**elnission~** ofeach gas by the appropriate global warming potential and summing the C02E emissions. C02 E elnissions are expressed in metric tonnes. Centrifugal cOlnpressors generally require shaft-end seals between the COlnpressor and bearing housings. Either facecontact oil-lubricated mechanical seals or oil-ringshaft seals, or dry-gas shaft seals are used. Seal leakage will tend to increase with wearbetweenthe. seal and COInpressor shaft, operating pressure, ,and shaftrotational speed. The extentto which all input combustible material has been cOInpletely oxidized (Le., toproduce H20, C02 and S02). Complete combustion is often approached but is never actually achieved. The main factors thatcontribute to incOInplete combustion are thennodynamic, kinetic, lnass transfer and heat transfer limitations. In fuel rich systelns,**o~ygen** deficiency is also a factor.

xiiConnectors

-

CrankCase

-

Destruction Efficiency

-

Flare and vent systelns

-

Fugitive ElnissionsGas PlantA connector is any flanged orthreaded connection, or Inechanical coupling, but excludes all welded orb.ackwelded connections. Ifproperly installed and maintained,a connector can provide essentially leak-free service for extended time periods. However, there are many factors that cancause leakage problems. Common leak causes include vibration, thermal stress and cycles, dirty or dmnaged contact surfaces, incorrect sealing material, ilnpropertightening, Inisalignment, and external abuse. The crank case on reciprocating engines and compressors

.houses the crank shaft and associated parts, and typically

an oil supply to lubricate the crank shaft. Integral

. COlnpressors have a single crank case because the engine and compressor share a comlnon crank shaft. Non-integral cOlnpressors typically have two crank cases, one on the engine side and another on the compression side. The extentto which a target substance present in the input combustibles has been**dest~oyed** (i.e., converted to intennediate, pmiially-oxidized, and fully-oxidized products ofcOlnbustion). DE is typically expresses as a percentage: 100 

## * (in

- out)/in. Venting and flaring are COlnmon disposal methods for gas processing plants waste gas. The stacks are designed to provide safe effluent dispersion. Flares are normally used wherethe waste gas contains odorous ortoxic components (e.g., hydrogen sulfide). Otherwise, the gas is usually vented. Typically, separate flare/vent systems are used for high- and low-pressure waste gas streams. Unintentional leaksfrOln equipment components including, but not limited to, valves, flanges and other connections, pumps and cOlnpressors, pressure reliefdevices, process drains, open-ended valves, pUlnp and compressor seals, systeln degassing vents, accumulatorvessel 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 gas quality to market specifications (i.e., renioving contan1inants such as H20,H2S and CO2 and possibly adjusting the heating value)

..
xiiiHeatRateIntegral COlnpressor

Methane Leak

Molecular Sieve

Long-Term Natural Gas ContractPrice ,;.

Open-ended Valves and LinesThe heat energy (based on thefuel net or lowerheating value) which mListbe inputto 

### a: combustiondevic'e to produce the rated power output. Heatrate is usually expressed in terms ofnetJ/kW·h. A reciprocating compressorthat shares a common crankshaft and crankcase with the engine. Greaterthan 10,000 parts permillion as measured by a dual-elementhydrocarbon detector (i.e., catalyticoxidation/thermal-conductivity). Absorbers composed ofzeolites (alUlninosilicate crystalline polylners) used to remove water vapor from natural gas. Zeolites areregenerated periodically by heating. Historically, long-tenn contracts have been used by buyers

.to secure a natural gas supply and by sellers to reduce large reserve developmentrisk. During the 1960s and 70s, these conti"acts were established for terms of up to 20 to 25 years andthe gas price was determined by periodicnegotiations. The recenttrend is towards shorter contract durations, and Inost new long-:tenn contracts index the gas price to spot marketrates. Today, atypical long-termcontractwith a cogeneration plant is about 15 years. Given the sellers and buyers interest in risk Inanagement, there is also atrend towards greater standardization oflong-term contracts to facilitate hedging activity in the financial orthe over-thecountermarkets. An open-ended valve is any valve thatreleases process fluids directly to the atmosphere from valve seat leakage. The leakage Inay be caused by iInproper seating due to an obstruction or sludge accumulation, or a damaged orworn seat. An open-ended line is apipe ortube segmentattached to a leaking valve and that opens to the atmosphere. Few open-ended valves and lines are designedinto process systems. However, actual numbers can be quite significant at some sites due to poor operating practices and various process·modifications that may occur overtime. Some common examples ofopen ended valves**~nd** lines are:

xivPower Output

-

Pressure-Reliefor Safety Valves

-

Products ofIncomplete COlnbustion (PICs)

- • scrubber, cOlnpressor-unit, station, and mainline blowdown valves;

• supply-gas valve for a gas-operated engine starter (i.e., where natural gas is the supply medium);

-. instrUlnentblockvalves where the instrumenthas been removed for repair or otherreasons; and

• purge or sampling points. The net shaftpower available from an engine after all losses and powertake-offs (t\g., ignition-systempower generators, cooling fans, turbo chargers and pumps for fuel, lubricating oil, and liquid coolant) have been subtracted. Forheaters and boilers, it is the net heattransferred to a targetprocess fluid orsystem. Pressure reliefor safety valves are used to protectprocess piping and vessels frOln being accidentally over-pressured. They are spring loadedso that they are fully closed when the upstremn pressure is below the setpoint, and only open when the setpoint is exceeded. Reliefvalves openin proportion to the overpressure to provide modulated venting. Safety valves pop to a full-open position on activation. When reliefor safety valves reseat after activation, they often leakbecause the original tight seat is;notregained either due to seating surface damage or foreign material build-up on the seatplug. As a result, they are often responsible for fugitive elnissions. Anotherproblem develops ifthe operating pressure is t60closeto the set pressure, causing the valve to "simlner" or "pop" atthe set pressure. Gas thatleaks from apressure-reliefvalve may be detected at the ventpipe (orhorn) end.**Add~tionally,** there normally is a lnonitoring port located on the bottOln ofthe horn near the valve. These are any cOlnpounds, excludingCO2 , H2 0, S02, HCl and HF, which contain C, H, S, Cl orF and occur in cOlnbusted gases. These,cOlnpoun'ds Inay result from thennodynamic, kinetic ortransport liInitations in the various cOlnbustion zones. All input cOlnbustibles are potential PICs. Intermediate substances formed by dissociation and reconlbination effects lnay also occur as PICs (CO is often the lnost abundant combustible PIC

xvPump SealsReciprocating Compressor Packing Systems

-

StandardReference Conditions

-

Thermal Efficiency

- formed). PositIve displacementpumps are normally used for pUlnping hydrocarbon liquids at oil and gas facilities. Positive displacementpumps have a reciprocating piston, diaphragm orplunger; or else arotary screw or gear. Packing, with or without a sealant, is the simplestmeans bf controlling leakage aroundthe pUlnp shaft. Itmay be used on both rotating and reciprocating pumps. Specially designed packing materials are available for different service types. 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 tighteningand periodic packing replacelnent. Particulate contmnination, overheating, seal wear, sliding seal leakage, and vibration will contribute to increased leakage rates overtiIne. Packings are used on reciprocating COlnpressors to control leakage around the piston rod on each cylinder. Conventional packing systelns have always been prone to leaking a certain mnount, even underthe best ofconditions. According to one Inanufacturer, leakage from within the cylinder orthrough any ofthe various vents will be on the order of 1.7 to 3.4 In3/h under nonnal conditions and for IllOst gases. However, these rates Inay increase-rapidly with nonnal systeln wear and degradation.

. Most equipmentmanufacturers reference flow, concentration, and equipInentperformance datato ISO standard conditions of 15°C, 101.325 kPa, sea level an'd 0.0 % relative hUlnidity. The percentage orpOliion ofinput energy converted to useful work orheat output. For combustion equipment, typical convention is to express the input energy in terms of the net (lower) heating value ofthe fuel. This results in the following relation for thermal efficiency: Th I**E~(fi'** . Useful Work/Heat Output 100% 

### 7J

### = 1 ,erma . :JJlClency

### = x 0 Net Heat/Energy Input Alternatively, thermal efficiency may be expressed in terms

xviTotal Hydrocarbons

-

Total Organic COlnpounds (TOC)

-

Valves

- ofenergy losses as follows: 

## .r;=

# (1- ""LEnergyLosses Jx 100% Net Heat/Energy Input " Thermal efficiency losses can occur due to the following factors:

It cOlnbustion exhaustheat losses (i.e., residual heat value in the exhaust gases);
It heatrejected to coolingjacketwater and lubrication oil;
It "radiation from equipmenthot surfaces;
It air infiltration;
It incomplete combustion; and
It mechanical losses (e.g., friction losses and energy needed to run cooling fans and lubricating-oil pumps). All cOlnpounds containing at leastone hydrogen atom and one carbon**~tom,** with the exception of**carbonat~s** and bicarbonates. TOC cOlnprises all VOCs plus all non-reactive organic cOlnpounds (Le., methane, ethane, Inethylene chloride, "Inethyl chlorofonn, n1any fluorocarbons, and certain classes ofperfluorocarbons). There are three main locations on a typicalvalve where leakage Inay occur: (1) from the valve body and around the valve stem, (2) around the end connections, or (3) pastthe valve seat. Leaks ofthe first type are referred to as valve leaks. Elnissions frOln the end connections are classified as connector leaks. Leakage pastthe valve seat is only a potential elnissions source ifthe valve, or any downstream piping, is open to the atmosphere. This is referred to as an open-ended valve or line. The potential leakpoints on the differentvalve types 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 stem packing systeln monitoring ports. Typically, the most likely partto leak is the valve-stem packing.

"The differentvalve types include gate, globe, butterfly, ball, and plug. The first two types are a rising-stem design

xviiVented Emissions

-

Volatile Organic Compounds (VOC)

- and the rest are quarter-turn valves. Valvesmay eitherbe equipped with ahand-wheel or'leverfor manual operations, or an actuator or motor for automated operation. 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 vented emissions causes or sources are gas-operated devices that' use natural gas as the supply medium (e.g., compressor startlnotors, chemical injection and odorization pumps, instrument control loops, valve actuators, and some types ofglycol circulation pUlnps), equiplnentblowdowns and purging activities, andglycol dehydrators still-column offgas venting. Any compound ofcarbon, excluding carbon monoxide, and carbon dioxide, which participates in atmospheric chemical reactions. This excludes methane, ethane, methylene chloride, lnethyl chlorofonn, many fluorocarbons, and certain classes ofperfluorocarbons.

xviii

### ACKNOWLEDGEMENTS The funding providedby US Environmental Protection Agency (GrantNumberXA8304-6001-1)" in support ofthisproject is gratefully**acknowledged~** Special thanks are given to the personnel at each ofthe host facilities for theirhelp, interest in the work being done, and useful feedback, and to all the sponsors for their constructive review COlnments.

xix

### 1 INTRODUCTION An intensive fugitive emissions screening and measurelnentprogram was conducted during the first quarter 2004 and second quarter 2005 at five gas processing facilities in the USA. The selected facilities were ofvarious ages, types, and throughputs and were evaluated with a strong emphasis on identifying and quantifying natural gas losses from leaking equipInentcOlnponents in heat-cycle and vibration services. The facilities included sweet and sourgas processing, and a variety ofprocesses including cOlnpression, separation, storage, and flare systelns. The study's primary objective was to demonstrate the cost-effectiveness ofconducting a**~OJnprehensive** leak detection and repair (LDAR) program at domestic gas production and processing facilities using HiFlowTM Sampler-technology. Field measurements also included an assessment ofelnissions from continuous vents, combustion equipment, and flare systelns and natural gas-fuelled equipment diagnostic checks. Such efforts are eInployed to achieve sensible and verifiable reductions in methane, GHG, and NMHC elnissions, while providing industry with potentially noteworthy emissions reduction opp0J1unities with comlnensurate financial incentives. These opportunities were presented to surveyed plants in the plant level reports. Based on the compiled testresults, the greatest opp0l1unities for cost-effective reduction ofnatural gas losses are from the control ofleaking equipment conlponents and leakage ofprocess gas into vent and flare systems. Therefore, the report eInphasizes fugitive leak opportunities. Background information, on key differences between the conventional EPA Method 21 approach to leak detection and repair and the approach used here, is provided in Section**2~A** Inore detailed description ofthe current approach and other Ineasurement techniques enlployed plus an overview ofthe basic assessment methodology are presented in Section 3. Section 3 also delineates the econOJnic criteria used to evaluate the identified emission cqntrol opportunities. , The IneasurementprograJn results are presented inSection 4. These results include an overview ofthe identified control opportunities, measured elnissions and natural gas loss inventories, average emission factors, and leak statistics. The study conclusions and recOJnInendations are presented in Section 

### 5, and cited references are listed in Section 6. Detailed listings ofall the identified equipment leaks are provided in Appendices I and II,

-- rankedby emission rate and payoutperiod, respectively. The following information'is prov'ided foreach component: Site No., Tag No., Process Unit, ComponentDescription, Elnission Rate (l03 In3/yr), Estimated Repair Costs ($), NetPresent Value ofRepair ($), 

### C02E Emissions (tonne/yr), and Repair Payback Period (yr). Appendix 

### III presents detailed accounts ofthe combustion analysis and efficiency testing results for each tested unit. Average equipment component schedules by process unittype are provided in Appendix IV. The financial considerations and assumptions applied are summarized in Appendix V while the assumed component repair costs and Inean repair lives are provided in Appendix VI. Physical Acoustics V-Pac measurelnents are detailed in Appendix VIl.

### 2 BACKGROUND Underthe settlementterms ofa recent Consent Decree, deadlines are estaplished for EPA to review and, ifappropriate, revise the NSPS standards for Subparts J, VV and GGG, 40 CFR 60.100-109, 60.480-498, 60.590-593. TheNew Source Performance' Standards in 40 CFRPart 60 KKK (backreference VV) provides the regulatory requirements for conducting a leak detection and repair (LDAR) program for the onshore natural gas processing industry. This standard is directed at controlling/reducing volatile organic compound (VQC) emissions and specifically excludes methane and ethane. Therefore, gas-processing facilities have typically only included the light liquid and refrigeration' areas in leak detection programs. Subsequently, very little information pertaining to, potential leakage from the remainder ofthe facility (i.e. non-regulated) was available. the primary project objectives were to evaluate leakpotentials and the cost-effectiveness ofimplelnenting LDARprograIns at natural gas processing facilities. Mostnatural gas industry LDARprograIns rely onU.S. EPA Method 21. Depending upon the leak screening instrument detector, the concentration ofeithertotal hydrocarbons (THe) or VOCs in the air from a leaking cOlnponent is measured, and then the leakrate is**estim~ted** using a correlation equation or Ineasured using the bag and sample procedure. In a conventional LDAR prograIn for fugitive emissions control, U.S. EPA's Method 21 is utilized to screen the facility for leaks at aprescribed frequency (e.g. quarterly, bi-annually or annually). All components that screen above a given threshold (typically'] 0,000 parts permillion)are to be repaired. There are a nUlnerous shortcomings with the Method 2] approach. The uncertainties in emissions estimates calculated using the correlation equation are very high. Additionally, the correlation equations only go to screening concentrations of 10,000 or 100,000parts per Inillion

- any leak above these screening concentrations has the same estimated leak rate (known as a "pegged source" elnission factor). Figure 1 shows the correlation equation and screening concentration values measured using Method 21 plotted against the leak rate Ineasured with the bag and saInple procedure. The data scatter is about ±'two orders ofInagnitude. The bag and saInple procedure directly measures leakrates; however, is verytiIne intensive and expensiveand the correlation equation approach is therefore used for Inost large scale LDAR prograIns. Data collected in Phase 1 showed that 65% ofthe natural gas facilities fugitive cOlnponents that screened above 10,000 P&rts pet Inillion are cost-effective to repair. Consequently, by repairing,all components thatscreen above] 0,000 parts perInillion perMethod 21, resources are wasted by repairing components
- 35% ofthe total b&sed on the Phase I results

- whose repair costs exceedthe value ofgas saved. Another shortcoming ofthe conventional Method 2] approach is that it does not accuratelyIneasure either the facility baseline emissions or the elnissions reduction (erroris 

### ± 300%). Because the elnissions reduction cannotbe accurately detennined, the benefits ofiInplementing an LDARprogram cannotbe evaluated.

2The HiFlowTM Sampler, describedin Section 3.1.2, quickly and accurately quantifies fugitive emissions leakrates"Rnd

### has signtfic"antlyreduce"d""natural gas"plants LDAR programs costs. Cost-effective repairs, those with repair costs less than the saved gas value, can be identified and cOl11pleted while non cost-effective repairs are notperformed and,111aintenance resources are optimized. The Phase I data showed that 80 to 90 

### % of facility emissions are often e111itted from a s111all fraction ofthe leaks; thus, significant emissions reductions can be achieved by repairing a few big leakers. In addition, a HiFlowTM SaJ11plerLDARprogram accurately measures the facility" baseline emissions I and the emissions reduction can be accurately deten11ined.Therefore, the LDARprogram implementation benefits can be evaluated. 

### Figure 1 LeakRate versus Concentration



# - 1.0E+01 0 J: I- 1.0E+00 >. Carel8tion Equation rn "'C lIb/day 

## :a 1.0E'()1 Bagging Data or 

# J 1.0E'()2 0.001 lb/day? I: 1.0E.Q3 

### .2 

# .1 1.0E.Q4 

# di 

# B 1.0E'()5 :I 1.0E.Q6 1 10 100 1000 10000 100000 Screening Value (ppmv) ppl96\Hunnd\Jd\OrolDlT11 The primary objective ofthe overall study is to assess baseline methane (CH4) emissiqns atnatural gas processing arid production facilities,. and delineate and quantify the extent ofcost-effective opportunities for reducing these e111issions. A secondary objective is to evaluate the potential for cost-effective reduction ofother GHG e111issions (primarily CO2) through process efficiency gains, and to establish a BestManage111ent Practice for conducting DI&M programs. Primary sources of111ethane e111issions include, leakage, venting, storage losses, incomplete combustion (fuel use and flaring). Other methane losses includes, increased fuel use due t,o avoidable inefficiencies, thermal efficiency offired equipment, con1pression efficiency, tail gas incinerators, electric power generation, and horsepower 111ismatch to required work. Phase 

## n addressed data gaps identified during the Phase J study and improved the overall statistical significance ofthe Phase I study for syste111 wide extrapolation ofresults and

3serves as the basis for developing an industry specific bestmanagementpraCtices guidance ,document. Phase II provided the following:

II An increased number and type ofgas processing facilities and components within the current database giving an improved statistical basis for extrapolation of the results systeln--wide.
II An indication ofthe effectiveness ofrepairs to the major leakers at a Phase I facility and the increases in leakage overtiIne at gas plants.
II An initial indication ofCH4 and GHG emission reduction opportunities atgas production facilities upstream ofthe gasprocessing plant (e.g., gas-gathering systelns including compression and well-site facilities). Although the primary goal ofPhase II was to expand the results ofthe priorPhase I Dl&M study through broader industry participation and an increased emissions database, 

### a secondary goal was to assess and integrate a suite oftools for improving survey efficiency. The scope ofwork and project approach for the second Phase was consistent with the Phase 1 study and allows for directcomparison with the previous results.

4

### 3 METHODOLOGY ·This section describes the methodology used by the study team to identify and evaluate' cost-effective elnission-reduction'opportunities at the gas processing facilities.· The different lneasurementtechniques considered for each primary source type are delineated. 'The five**sel~cted** test facilities were chosen to provide a representative cross section of gas plant ages with significant on-site cOlnpression since these types offacilities were expected to offerthe greatest opportunities for cost-effective reduction ofnatural gas losses. As shown in Table 1, three sweet and two sourgas processing plants were seJected. These plants ranged from 6 to 57 years in age, for an average age of31, and all ofthem have compression facilities and mole sieve dehydration units. In comparison, the average age ofgas processing facilities in the United States is estimated at 26 years.

] Sweet 6 22,290 500 2 Sweet 28 ]2,330 206 3 Sweet 39 ]8,353 130 4 Sour 27 ]6,687 45 5 Sour 57 4,778 87 ····Average..•.. The cOlnponent counts presented inTable 1 above include cOlnponents less than 0.5" nonlinal pipe size. Overall, 

### 14.5% ofthese cOlnponent counts are cOlnponents less than 0.5" nOlninal pipesize. 

### 3.1 Emissions Survey The site surveys included all or SOlne ofthe following elements, as applicable:

CD screening equipmentcomponents to detect leaks;

• measuring leaking equiplnent cOlnponents (i.e., leakers) emission rates;

• rneasuring continuous vents emissions and eJnergency vents residual flows during passive periods;

• counting the surveyed equipment conlponents;

• measuring residual flare-gas rates;
• performancetesting naturalgas-fueled combustion equipment;
CD performance testing ofcOlnptessors (newly added for Phase II);

• sampling process and waste**stre~ms;** • .determining site-specific average emission factors for fugitive equipment leaks; and
CD conducting an identified control opportunities cost-benefit analysis.

5

### 3.1.1 Component Screening Equipment components on mostprocess-, fuel- and**waste~gas** systems were screened for leaks. Components types surveyed included flanged and threaded connections (i.e., connectors), valves, pressure-reliefdevices, open-ended lines, blowdownvents (i.e., during passive periods), instrument fittings, regulator and actuator diaphragms, COlnpressor seals, engine and compressor crankcase vents \ (see Figure 2), sewer drains, SUlnp, drain tank vents and tank hatch seals. Figure 2 Survey Team Using Gas Detectorto Quantify Concentration and Screen Compressor Leaks

COlnponents in light-liquid service generally were not screened since the program focus was natural gas losses. Furthermore, light-liquid service components do not contribute significantly to total hydrocarbon losses at gasprocessing plants due to their low average leakrates (U.S. "EPA, 1995) and relative nUlnbers. Leak detection (or screening) was conductedusing bubble tests withsoap solution, portablehydrocarbon gas detectors (BascOln-Turner Gas Sentry CGI-201 and CGI-211 and a GMI Gas Surveyor3) and an acoustic leak detector (SDT International, SDT-120). Bubble tests, shown in Figure 3, were perforined on the lnajority ofcOlnponents

. (including pipe threads, tubing connections, and valves) because it is usually the fastest screening technique.**~Olnponents** that could notbe screened using bubble tests included any in high-telnperature service, certain flanged connections and open-ended lines. These were screened using the gas detectors. COlnponent determined to be leaking by the bubble tests were then screened using a hydrocarbon vapor analyzer. Hydrocarbon analyzerscreening values of 10,000 parts perlnillion or greater defined con1ponents as leaking or "leakers."

6Undernormal operation, waste gas volumes from blowdown or depressurization events are sentto the flare system. Ifthe valves do notproperly reseat after one of these events, gas will continuously leakthrough the valves. The Physical Acoustics Corporation VPACTM model 5131 ultrasonic detectors were used to detectthrough- valve leakage into closed loop vent systelns routed to flares. Figure**3~** PhysicalAcoustics VPAC Figure 4. Residual Flaring

Ultrasonic measurements coupled with data on valve size, type, and differential pressure is used to derive lnass rate loss estimates. The hand held instrumentuses an acoustically coupled sensorthat is held against the pipe upstream and downstream ofthe pressure reliefvalve and the reliefvalve body. At each location the sound levelin decibels is detected. Leaking valves will have a larger signal than completely sealed valves. Appendix VII provides lneasurement details. All identified leaking cOlnponents were tagged (shown in Figure 4}and the specific leak source and date were noted on the tag. The emission rates for all leakers were determined using the procedures described in Sections 3.1.2 and 3.1.3. Allleakertags were left in place afterthe leakrate measurelnentto allow follow-up action by facility persOl'inel. A total of74,438 individualequipment conlponents and numerous process vents, natural gas-fueled compressor and generator engines, process heaters, and flare/vent systems were surveyed. Sufficientprocess infonnation was collected to deternline total annual emissions from the cOlnpiled lneasurementresults. Additionally, specific elnission-control opportunities were identified, and a preliminary cost-benefit analysis was performed to evaluate these opportunities

.

.The analysis considers**th~** estilnated cost ofrepair and corresponding lifetime and the conserved gas value. Site personnel were solicited to provide input and assistance in identifying site-specific constraints and to help ensure thatcost data were satisfactorily considered. 

### 3.1.2 LeakDetection Methods Conventional leak detection techniques, including bubble tests, handheld organic vapor analyzers and acoustic ultrasonic leak detection equipment, have traditionally been used to screen equipment conlponents forleaks in accordance with Method 21 (U.S. EPA, 1997): These traditional leak detectiontechniques are

7thorough; however, they tend to be quite tilue consuming. More recently, optical**'p~.s_siv~. il}f.~~n:~_d~qm~nl** **te9.h.lJpJogi~s** h£lye**Q~en. qey~19P~<:lj;n.** **.~n.~ffoli** to iluprove the leak detection process efficiency. Although the optical IR cameras have performed wellduring numerous field trials, there arenot yet sufficient data to demonstrate thatthe technology should be adopte<i in lieu oftraditional screening techniques. Although separated and excluded frOlu theEPA portionofthe scope ofwork, al'1 five facilities integrated apassive luidwave infrared camera in the leaksurveys. A secondary program objective was to COlupare the performance ofthe passive IR camera optical leak detection luethod with conventional leak detection methods. Although individual DI&M surveys didnot"yield sufficient datato provide a quantitative comparison ofthe conventional methods and the camera, sufficient information for a qualitative cOluparison oftheluethodologies and perfonuance exists. As optical infrared technology advancements rapidly progress the state ofthe science, it is likely thatEPA will consider addressing reluote leak detection luethods within future revisions to the New Source Perfonuance Standard (Under the settlementtenus ofa recent Consent Decree, deadlines are established for EPA to review and, ifappropriate, revise the NSPS standards for Subparts J, VV and GGG, 40CFR 60.1 00-1 09, 60.480-498, 60.590-593.) The findings discussed below highlight considerations for future method developluent. Noteworthy findings from integrating optical remote sen·sing in DI&M include:

I • The IRcamera is capable ofscreening leaks approximately 3 tiJues faster than conventional methods (fortwo people: typically 2,400 cOluponents/day for conventional versus 6,400 cOluponents/day for the optical);

• The IR cmuera is not currently capable ofquantifying a leak and can only be used to identify leak sources. The camera is capable ofidentifying leaks (using a variety oflenses) that are inaccessible to conventional techniques thatprincipally rely on direct access.
• The camera offers visual confinuation ofleaking eluissions sources and allows rapid source identification; however, mubienthydrocarbon concentrations may interfere with the camera ability to isolate a leak source. Engine magnetos caused interference and precluded leak screening on fuel gas headers, individual cylinder connections, and fuel injectors, significant leakage sources on older engines;

• Watervapor overlays the hydrocarbon absorption spectra and therefore steam plumes are visually comparable to hydrocarbon leaks and very difficultto differentiate;

• Rain and fog limitthe IR camerautilization; and

• The IR canlera cost is approxiluately $75,000 to $100,000 cOlupared to $5,000 to $10,000 for conventi"onalleak screening tools. Typjcal daily costs for a conventional leak screening teanl is $1,500 plus expenses while a typical daily charge f<?r an experienced IR camera temu is $3,000 plus expenses.

8Leaks can occurthrough valves and pressure reliefvalves thathave not seatedproperly after activation. This leak is notout ofthe process equiplTIent and so cannotbe seen with optical methods orby organic vapor analyzers. Instead an acoustic method has been developed thatmeasures the noise generated by gas flowing through a slTIall gap. The acoustic detector yompares the sound before the valve; atthe valve and downstream frOlTI the valve and compares the sound to a database ofpreviously measured leaks. This instrument was used to measure leaks atpressure reliefvalves. Due to the high volume offlared hydrocarbons at several sites and the large numberof possible sources tied into the flare systelTI (e.g., leaking pressure-reliefdevices, drains, and blowdown valves corme'cted to the header), connecting the flare to avaporrecovery unit should be considered as a cost effective option for capturingthe residual gas flow. Another option isto targetthe individual residual gas flow sources; however, these. sources are often difficultto isolate, usually require a majorplant shutdownto fix (i.e., resulting in significant indirect costs), and are likely to reoccur.

9Figure 5. Soap Solution Screening on a Two Inch Leaking**Thr~aded** Connector

Figure 6. Tagged Leaking Components

10

### Figure 7. 

### Cut-Away View OfA Natural Gas Co.mpressor Showing The Potential -:Lea-k-Pointslncluding-The-Compressor"Seals And-Crankcase Vent.

CRANKCASE VENT



# • VentVent
RECIPROCATING COMPRESSOR PACKING 

### & VENT SYSTEM

Oil

EXPANDED 

### VIEW OF THE COMPRESSORHEAD

11 PACKING CASE



# ,Leakage

Leakage

LeakageThe following basic information was recorded for each leaking component:

• Type
• Model or Style

• Service

• Size

• Process Unit

• Process Stream

• Pressure and Temperature 

### 3.1.3 Leak-Rate Measurements The HiFlowTM Samplerwas the priInary emission rates

### ~easurement Inethod for leaking equipment components. The HiFlowTM Samplerwas not used for cOlnponents leaking at rates above the equiplnentupper limit (i.e., about 14 m3 /h for the currentHiFlowTM design) and for most open-ended lines and vents. Either bagging or direct measurement techniques, as appropriate, were used in these cases (see. Section 3.] .3). The SaIne HiFlowTM prototype was used between Phase I and PhaseII for consistency. The' following provides a briefdescription ofthe HiFlowTM Sampler.

. The HiFlowTM Salnpler is an econonlic Ineans ofIneasuring individual leaking equipnlent cOlnponents emission rates vvith sufficient accuracy for objective repair opportunities cost-benefit aIialyses. Baggingall leakers to differentiate between econOlnic-to-repair and uneconOlnic-to-repair cOlnponents is expensive and, therefore, is not nonnally done (typica1l

# 1M]Oto 30 leak-rate aneasurements perhour can be perfonned using the HiFlow SaInpler cOlnpared to only 2 per hour using bagging techniques). Furthermore, compiling Method 21 (U.S. EPA, ]997) cOlnponents screening data and then applying leak-rate correlations or stratified elnission factors to detennine leakrates does notprovide sufficient accuracy for econOlnic analysis. The correlation leakrate uncertainty for jndividual cOlnponents is ± two orders ofInagnitude and the stratified emission factors are even .less reliable. In cOlnparison, the HiFlowTM SaInpler and bagging measurelnents uncertainties are only about ± 10 to ]5%. Accordingly, the HiFlowTM SaInpler (shown in Figure 6) provides apracticable means ofmaking objective repair decisions. The reliability and use ofthe HiFlowTM Samplerhas been delnonstrated in a nUlnber ofstudies (Howard eta/., 1994; Lott etal., 1995). The HiFlowTM Sampleroperating principle is siInple - a variable-rate inducedflow samplingsysteln provides total orneartotal leaking cOlnponent emissions capture. Specially-designed attachnlents are used to encapsulate the leaking conlponent and allow ambient airto flow overthe cOlnponent; the air-leakinggas mixture is drawn into the Sanlpler with a vacuum pUlnp. A dual-elelnent hydrocarbon detector (Le., catalytic-oxidation/thennal-conductivity), inserted directly in the HiFlowTM sample line, Ineasures hydrocarbon concentrations in the captured air-gas stream ranging frOln 

### 0.0] to ]

### 000/0. A background satnple-.

]2

### colle,ction line and hydrocarbon detector allow the sample readings to be correctedfor-'ambient gase-oncentrBtions, which,is-Fa'rt-icJ;llarly-important in ,buildings and confined areas. A'thernialanemometer, also inserted directly into the**sam~le** 

### line, monitors the sampled air-h)/drocarbongas mixture'flow rate. The HiFlow M 

### Sampleris intrinsically safe and is equipped with agrounding wire to dissipate st,atic charge formed as air passes through the saJnplecollectiori line and instrument

..**Th~** 

### HiFlowTM Samplerbattery-operatedfan can generate am'aximum sampling velocity ofapproximately 366 

### m/min (1200 ft/min), which corresponds to a maximum leak rate measurement capacity of] 4 n;3/h (8.5 scfm). It)creasing the sampling rate generally improves the leak capture efficiency up

## to the point of total capture. Increasing sampling rates beyond this point causes increased' emissions dilution \vith ambient air. Excessive dilution may cause the pollutant concentration to eitherfall below the sample detector range orto decrease to backgrouncilevels resulting in azero reading. The sampling rate is'adjusted manually using abackpressure valve mounted on the fan outlet. Forlarge leaks, the**backpressure~/alve** 

### is left open; \vhile for small leaks, the airflow rate is reduced so that the hydrocarbon concentration is within the detector sensing range. The HiFlowTM Sampler sample andbackground hydrocarbon detectors were calibrated with] 000/0 methane and 2.50/0 methane-in-airto coverboth ranges of the dual-element detector system. The detectors were zeroed using ambient air upwind ofthe facilities. The ca,librations \vere done priorto HiFlowTM Sampler use at each site, and then periodically thereafter-tb;ensure that n6isignificant drift occurred. The HiFlowTM Sampler was also periodically calibrated by releasing known methane flows, determined using abubblometer or diaphragm meter, into the sampler and comparing the leak rate measured by the HiFlowTM to the metered gas release rate. Three correction factors are applied to the raw data.

13Figure 8. 

### Pro1otype GRI**HiFlowTI\~** 

### Sampler

3.1.4 Ven1s and Open-ended J..Iines Emissions J\1easurements 

### The emission rates from open-ended lines and vents werellleasured using an**appropriat~** 

### flo\v-through measurement device (i.e., aprecision rotary meter,
.

.diaphragm flo\\! meter, orrotameter, depending on the flow rate) if

### total flow capture \\ias safe and practicable to achieve and the resulting backpressure on the vent system did not impact the gas flow. Otherwise, flo\vs \\Ieredetermined by

. measuring the flow area and velocity profile across the vent line.

\\There total flow capture was possible, the vent or open ended line pipe ortube \vas connected to the flow-through measurement device with PVC tubing. The tubing-pipe and tubing-flov./**met~r** 

### connections were sealed \\Iith customfabricated slip-on sheaths made ofneoprene orplastic sheeting. Each flow measurement \va.s averaged over a 2 to 20 minute interval, depending on the flow volume and variability. \\Then measuring flo\vs from vents, a distinction was made bet\;veen continuous and intermittenl vent systems. Emissions from imerminent vents during inactive periods (i.e. non-venting operation) were defined as leakage

..Emissions from continuous vent systems and intermittent vent systems during active periods were defined as venting emissions. Vent and open-ended line leaks were detected by hydrocarbon sensor screening.

]4**~~1.5 Re~idu31**  FI3ring Rates Deterniination Flare line flows were determined using two methods:

• Flare Line Velocity ,Profile and Flow Area l\1easurement

- Flow velocities 'were measured using a pitot tube,hot-\vire anemometer orthermaldispersion anemometer. The traverse points \vere selected in 'accordance with U

### .S.EPA Methods land lA. Safe-to-access POI1S on the stack, the common line to the! I flare, or on each branch line connected to the flare system are req.uired.

• Flow Rate C3lculated from Pressure Drops l\1easurements

- the pressure drop between the flaretip and a suitable upstream point on the flare line is measured and the gas flow required to produce that pressure drop is' calculated. Several**inc~hes** of\vatercolumn pressure drop is neededfor reasonable flow rate estimation. Low flo\\' veloc.ities in large diameterpipes may not produce measurable pressure drops despite significant volumetric flows. The direct measurement method is more accurate and was used when sample ports were accessible. The gas stream hydrocarbon concentrations were either determined using aportable combustible-gas detector or frOln flare gas laboratory analyses (where available). Continuous flare systems flows include purge gas flows and equipnientfugitive leaks into the, flare system. To distinguish bet\veen purge gas flows and leakage, the minimum required purge gas rate was calcu'latedusing the prdcedure presented by Stone 

### etaZ. (1992). The difference bet\veen the total flare system gas flow rate and the calculated purge gas flow rate was assumed to be the leakage or potentially avoidable natural gas loss. The 'econOlnics ofconserving the gas losses can thenbe determined. P-rimary sources offlaring aild vented emissions include disposal ofwaste associated gas at oil production**fac;ilities~** casing gas vents at heavy oil wells, gas operated**devices~** still column off-gas vents on glycol dehydrators, leakage into vent/flare header (5-] 00/0ofvalves leak and 1-20/0 ofthese contribute 75%),

,excessive purge gas rates and inspection and maintenance activities including well**testing~** servicing, and pipeline tie-ins.

3.1.6**N~Hur31** Gas-Fueled Equipment Performance Testing Natural gas-fueled engines, process**heaters~** and boilers were tested to identify avoidable inefficiencies causing excessive fuel consumption and enlissions. The focus \vas,on identifying situations where equipment required tuning, optimization, or repairs, orv·/as mismatched \\/jth the current process demands causing operation outside the performance curve. The identification of

15

### Oppo11uilities to recoup \vaste heat ftomthe units orto redl!ce energy requirements through process modifications \:vas beyc;md'the projectscope. The testing on each unit involved analyzing theflue gas,meas'urlng the flU'e gas,**temperature~** 

### obtaining afuel gas composition analysis, and where possible, measuring the flow rate ofone or more ofthe following: fuel gas, combustion air, and flue gas. The flue gas analyses \vere conducted using an Enerac 2000E P011able Combustion Analyzer equipped \vith detectors for 

### 02, CO, CO2, 

### NOx, I 

### andcombustibles and thermocouples'for measuring ambient and stack-gas temperatures. The flue gas was sampled through either an exhauststack sampling p011 or at the stack top.**Additionally~** 

### the**unit~** 

### make: and model and site ambient conditions (i.e.: temperature and barometric pressure) were**recor~ed. Typically~**  

### insufficient process data \vere available to reliably estimate the total useful process \votk done by each**unit~** 

### orto determine overall unit performance. Consequently: a simplified approach was used where the following parameters were evaluated and their deviationsfro111 proper operating cOllditions were' indicators ofimprovement opportunities:

• flue gas residual heat content (i.e.: stack losses);

• excess air setting; and , , • flue ,gas concentrations ofcarbon monoxide and unburned**hydroc~rbons. ,Additionally~**  

### reciprocating engines crankcas,e vents weTe checked for significant blow-by (i.e.: leal<age pastthe piston rings into the crankcase) because blow by reduces cylinder compression that causes**ineffici~nt** 

### operation at;ld contributes to unburned and partially burned fuel emissions. As a first approximation ofthe resulting performance loss:**m~asurel11ents** 

### were performed to quantify the combustible gases emitted as crankcase vent blo\v-by. These results are presented as fugitive equipment leaks. On integral compressor units (i.e.: compressorunits \vhere the engine and compressor share a conlmon crankshaft and crankcase)," crankcase ventemissions potentially include engine cylindersblow-by and compressor seals leakage which enters the crankcase through the distance piece. This is shown in Figure 5. ]n ma,ny**cases~** 

### the engine crankcase \vas vented inside abuilding orwork area. This poses apotential health and safety risk. Figure 7 depicts various venting configurations**l~ecommended** 

### by the engine manufacturers. Key sources ofcombustion emissions**ijlclude~** 

### oversized engines, heaters and**boilers~** 

### poorlUning (e.g., air/fuel ratio), leakage pastpistons in engines: lack of waste heat**utiljzation~and** 

### fouledburnertubes.

]6Figure 9. Typical S1a1ionaD7 Compressor Engines CnmkC3&e Vent Configurations Recommendedb)1 lVhmufacturers.

Building ROOf---,

....

### ..±.

__...:.-_'-----:- 

### ...:.--I-==:::::;-Crankcase Breather Line

.----.,t--Clean-outPort

Building**ROOf~r--L-:.:._'_ ~!::=::::;~Crankcase**  Breather Line

+---,-J--P-trap

:" I "- ('-

# ~)**4-LU~e_OiI** Drain Tank,

Building**ROOf~~.L --J~==:;_crankcase**  Breather Line I.---t--Electric Fan +---t--Risers from Other Engines +-----.j-- Pressure Relief Valve

1/ "\ I, I+-- Lube Oil Drain Tanh \\

.......**~----** .../I

17\\There possible, equipment-specific emissions factors on either a kilogram;.percubic-meter fuel basis (ifthe unit fuel consumption rate was known)or on a kilogram-per-day basis (ifthe flue gas flow rate was known) were generated for estimating CO, NOx, C02 and combustibles emissions. A detailed calculations· summary and a discussion ofnormal operating efficiencies and losses are provided in Appendix 

### ]ll.

. 3.1.7**Compre~sion** Equipment Anahrsis This section outlines calculation methodology used in analyzing the compressor effidencies and presents detailedresults ofthe calc.ulations. A reciprocating gas compression equipment analysis was conducted to identify avoidable compression inefficiencies caused by pulsation losses and internal gas leakage past**thev~lves** and piston rings. An acceptable energy loss from compr.ession inefflcie.ncies is 5% ofthe ideal energy requirement and excessive losses are generally avoidable (Hanlon, 200]). Another avoidable inefficiency associated with gas compression is excessive pressure drop through interstage coolers. Typically, interstage coolers have a design pressure drop orabout ]01 kPa, and**exces~ive** pressure drops may

. indicate cooler fouling.

The compression process is nearly adiabatic when no attempt is made to cool the gas int'ernallyas it is being compressed. Ifthe process is assumed tobe adiabatic and changes to**th~** -kinetic. and potential energies ofthe gas are neglected, the work ofcompression varies withthe changein enthalpy according to the following equation:
I I 

### (D.I) Where: fiJI is the compressor ,vork ·is the mass flow rate ofgas

. is the suction enthalpy

.**is~he** dischar,ge enthalpy Thefollowing property data was collected for each stage ofcompression:. Ps,m - nieasured suction pressure Ts,m

- measured suction temperatore Pd,m

- measured diseharge pi'essure Td.m

- measured discharge temperature For a simple compressible system the state is specified by two independent intensive properties. Therefore: other propenies ofinterest such as enthalpy and entropyfollow from the temperature and pressure measurements and the actual work ofcompression can be calc.ulated using Equation D.1.

18

### For adiabatic compression the ideal**pro~,ess** 

### is isentrQpic. The suction state for the ideal process is still defined by the measured suction properties. Where as the ideal discharge state is defined is defined by the discharge entropyand measured discharge pressure. Foran isentropic. process entropy is conserved and the discharge entropyis determined from the suction state. The suction enthalpy follows from the state definition and theideal compression work can be calculated using EquationD.l. This ideal compressorwork iscorrected to account for valve pressure drop based on the method presented in Figure 13-14 

### ofGas Processors Suppliers Association Engineering Data Book Volume'l. The corrected ideal state is thendefined by the enthalpy calculated using equation D.l and the measured discharge pressure. The corrected 'idealdischarge temperature follows from the state definition. In practice the extent to which the, corrected ideal compressor efficiency tan be achieved is limited by physical constraints such as pulsation losses and valve slippage. Forthe purpose ofthis analysis an acceptable energy loss is taken as 5% ofthe corrected ideal energyrequire,ments (Hanlon, 2001). 

### The acceptable discharge state is then defined by the enthalpy calculated using Equation D.1 and the measure discharge pl;essure. The acceptable discharge temperature follows froill the acceptable discharge state. For situatiOlls where the actual compressor\\lork is greaterthen the acceptable compressorwork apotential savings is estimated. This estimate takes into account the efficiency ofthe compressor driver and the price ofnatural gas. I i I I 

### Key sources ofcompressor inefficiencies include, internal valve andcylinder leakage in reciprocatingconlpressors, pulsation losses, excessive gas recirculation, non-optimal loading. 3.].8 S10rage Tanks Excess Emissions Evaluations 

### Storage tanks are apotentially significailt emission sources due to evaporation losses, paI1icularly where intentional product boiling orflashing occurs. Primary sources ofstorage tank emissions include:

• Flashing losses atproduction facilities;

• Unintentional gas carry-through to storage tanks;

• Leaking drain and dump valves;

• J\1alfunctioning level controllers;

• Inefficient upstream gas/liquid separation;

• Piping changes resiJlting in unstabilized product going to tanks;

• J\1alfullctioning -vaporrecovery systems;
It 

### Faulty blanket gas regulators orpressure controllers; and

• Fouled vapor collection lines.

19However, other less recognized, and often unnoticed; contributions ,to atmospheric emissions orvapor losses from storage**t~nks** include the following:

• Process gas or volatile product leakage past drainor blowdcrwn valves seats into the product header ,leading to the tanks;

• lneffident upstream gas/liquid separation allowing some gas carry'. through (by entrainment) to the tanks. This usually occurs where facility inlet liquid production (e.g., produced water} has increased significantly! over time causing inlet separators to be undersized for current conditions;

• Piping modifications causing unintentional routing ofhigh ,vaporpressure product to tanks not equipped with appropriate vapor controls; -Storage tanks overheating or hot product rundown to tanks containing volatile material;

• ,J\1alfunctioning or improperly set blanket gas regulators and vapor control valves can cause excessive,blanket. gas use and, consequently, increased flows to a vent or control device (e.g., flare or vapor recovery compressor). The blanket gas is both a product vapors carrier and a potential pollutant itself(Le., natural gas is usually used as the blanket medium for blanketed tanks at gas processing plants); al1d

• Leaking hatches and pressure-vacuum valves on tanks equipped with gas blanketing**syst~ms** result indirect atnl0spheric emissions ofproduct vapors and blanketgas. The last two leaks are repo11ed under flare systems and fugitive equipment leaks, respectively. The other leaks were determined by measuring venting rates (see Section 3.1.3) and comparing the observed emissions to cakulated working losses for conditions at the time oftesting. 3.1..9 Component Counts Equipment component counts were prepared based on an initial review ofthe process and instrumentation drawings, followed by a s'ite walk-though inspection ofeac.'h process unit. The following component information ",'-as collected:

• type (e.g., connector, valve, control valve,pressure reliefvalve, pressure regulator, orifice meter, other flow meter, blowdown, open-ended line, etc.);

• style (e.g., threaded and flanged conner,tion, eoup1ing, ball valve, plug valve, globe valve, gate valve, butterfly valve, pump seal, compressor seal, regulator, sampling connection, etc.);

• nominal size;
18 process temperature and pressure;
• service (i.e., natural gas, light hydrocarbon liquid); and

• application (i.e. process stream and unit).

203.1.1 0 Average**Emj~sjon** Factors Development The average emission factor for each component type was detennined,by dividing the aggregate component emissions by the number ofcomponents:.Total emissions are the sum ofemissions from both leaking and non-leaking components. Leaking components (i.e., those with screening values of?] 

### 0,000 ppm) en1ission rates were quantified using the methods described in Section 3.1.2. Non·leaking components \,,-'ere assigned the average non-Ieakirigemission rates presented in the Protocol for Equipl11ent Leak EmissionEstimates (U.S. EPA, 

### 1995). ' '3.1.11 Emission Control Guidelines

There are currently no regulations or codes ofpi"actice that apply specifically to fugitive equipment leaks emissions control for natural gas processing facilities. Guidelines typically used are maximuin leak**frequenci~s** of]0% forcompressor seals, 

### 0.50/0 for connectors, and 

### 20/0 for other component types 3.2 Equipmen1 Repair Cost·Benefit AnaJvses Practicable oppo11unities forreducing fugitive equipment leak and processventing emissions were assessed on a source·by·source basis. The net cost/benefitsofidentified control options were determined in dollars per tonne ofC02-equivalent annual emissions reduction. The information and assumptions regarding the cost estimates, the lost gas value, and repair lives used in these analyses are summarized below. The'financial discount j"ate and other financial considerations applied In these analyses are summarized in Appendix V. 3.2.1 Equipment Repair Cost Estimating Detection and control costs are assessed on an individual-source or percomponent basis according to estimated average site·specfic costs. Actual costs \\li11 vary with the facility location and**layout~** the required work, the service type**(i.e.~** sweet or sour), and the actual repairs or control measures required. The basic cost torepair or replace a leaking equipment component is ,estimated 'based on the component type and size, typical billing rates quoted by the service providers (e.g., compressor maintenance a'nd repair companies, and valve repair and servicing'comp31iies) and the estimated labour and materials requirements. \\There**possible~** both direct and indirect costs are considered. Direct costs are the actual costs**forparts~** onsile labour,**equipment~** tools and disbursements, and are summarized in Appendix Vl. Indirect costs are re\/enue losses due to any process shutdov/ns.or il1lerruptions beyond normally scheduled facility turnarounds, and the value ofgas vellled or flared during the specified repair or replacement activity. \\There indirect costs render the repair or replacement cost ineffective, it is assumed that the \vork will 'be delayed until the next scheduled plant

21

### turnaround. Otherwise, it is assumed that the repairs are made soon afterthe leak detection and evaluation. 3.2.2 Natura) Gas Value 

### Tne value ofnatural gas was assumed to be $7.] 5/1\1scf($6.78/GJ). The propane, butane and condensate values ,vere assumed to be: propane $8.l3/GJ; butanes $9.63/GJand condensate $9.63/GJ. The actual value ofavoided natural gas losses is very site-specific and can depend on many factors including:

• Local marketpricing;

• ]mpact ofemission reductions on specific energy consumption, equipm,ent life, ,vorkplace safety, and system operability, reliability and deliverability;

• Contract terms; , • Facility remoteness;
. • Gas concentrations ofcontamiilants and NMHCs;

• Applicahle taxes and tax shields. 3.2.3 Repair Life It

### ,vas assumed that aleak, once repaired, will remain fixed for some finite time period, and then will reoccur. The meantime between failures depends on the component type, style, quality, appHcation, and activity levels (e.g., number of valve operations) and site maintenance practices. Estimates ofthe 'mean time 'between failures for each component type are pro\(ided 

### hi Appenpix Vl. These values are very crude estimates based on the author's experiences and**l~mited** 

### host fad1ities feedback. The relatively low mean tillle between faill:lres for connectors reflects wear and tear from inspection 'and maintenance ofassociated equipment units. ]n aformal leak detection and repair program, information on maintenance practices and mean times betyveen failures is tracked and is used to identify problem service applications and to evaluate the need to change to component specifications and maintenance practices. 3.2.4 Cost Curves 

### A cost curve shows the estimated net cost required for different levels ofsite emission reductions. Each point on the curve represents the impact of implementing a different emissi0n-reduction measure. The costs are'based on a mix offacility and vendor data and consensus estimates developed in consultation ,vith the facilities The presented costs do not include those to find and**e\~aluate** 

### emissions 'reduction opportullities and are therefore biased slightly low (typically, these costs are small compared to the control costs). Different control actions have different lifelimes; therefore, for comparison purposes, the credited emission reduction for each control option on the cost curve only includes the first year emission redLiction (forthese analyses, the'shonest repair lifetime is assumed to

22

### be one yea'r). Control measures \vith lifetimes greaterthan one yearwill have reduced costs per unit emission reduction. 

### 4 RESULTS This section provides an overview ofthe atmospheric emissions and natural gas losses determined for each ofthe five sites. and delineate the main cost-effective loss-reduction opportunities.

### Additionally~ average'total hydrocarbon (THC) emission factors and

### lea~ statistics are presented for fugitive equipment leaks atthese facilities. Tagged-component information and individual leak rates for all leaking components are presentedin Appendices I and II. Detailed resultsofthe performance tests done on all active combustion sources are provided in Appendix lll. ' 4.1 Emission Inventory 

### Total atmospheric emissions' ofmethane, NJ\1HC and GHG emissions from the five host gas processing plants amounted to "8,072 and**3~625** 

### tonnes per year and 598,] 84 tonnes C02E peryear, respectively. Therelative distributions o(these emissions by source category are presented in Figures 8to ]O. The carbon dioxide equivalent GHG emissions \vere calculated usin'g the most recent] OO-year global warming potentials OPCC, ]996) (Le., ] for C02 and 2ffor CH4). 

### GHGemissions consider methane ,and C02 0n1y and do not include Nitrous Oxide (N20) emissions from combustion sourGes. The methane content Gfthe measured THC emissions \vasdetermined based on typical ga.s 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/contributeonly a few**o/~** 

### to total GHG emissions at each site. As shov·,7n in Figure 8, fugitive equipnlent leaks (leaking components) are the dominant source ofmethane emissions, accounting for 600/0 from all sources. This is followed by incomplete fuel combustion (170/0), process venting (16%),\vells (4%), incomplete flare gas combustion (2%), and a small amount (1 0/0)**fl~om** 

### storage tanks and gas operated devices. Figure 9 sho\vs fugitive leaks (leaking components) are the major source ofNMHC emissions (730/0). The rest (27%) \vas contributed primarily bycombustion equipment and wells. The C02 E GHG emissions are predominantly from fuel consU111ption by combustion equipment (740/0) as shown in Figure] O. However, fugitive equipment leaks (17%), as well as process vents (50/0) may generally offer more cost-effective control opporturiities

..

23Figure 10 Distrihution ofMethane hy Source Category for All Sources.

<?as Q:Jeration [)::Nice

O°fc, StorageTankt; 1%
Corrbustion

Equiprrent 17% Recess Venting 16% Rares 2°fc, V\ells 4%

Leaking Corrponents 60%

Methane Emissions = 8,072 tonne/yr

24Figure!1 Distribution, OfNon-Methane'Hydrocarhon Emissions By Source Category

Leaking. /'

### Corrponents~

73°t'o Corrbustion

EquiprrEnt: 5°t'o R-ocess Venting O°t'o Rares 1%> \/\ells, 21°t'o

NMHC Emtssions 

## =3,625 tonne/yr

25Figure 12 Distribution OfTotal GHG Emissions By Source Category.

Recess Venting 

### 5°16 StorageTanks 

### 0°16

Corrbustion

.

Equiprrent

# ~~ 74°k Rares 

### 3°16 V\efls 

### 1°k Leaking Cbrrponents 

### 17016

GHG Emissions = 598,184 C02E tonne/yr

264.2 Natura) Gas Losses The value ofnatural gas is taken to be $7.15 J\1scf($6.78/GJt The values for propane, butane and condensate are taken to be as follows: propane $8.13/G]; butanes' $9.63/GJ and condensate $9.63/G.1. The detenl1ined gas losses include directleakage and venting ofnatural 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 s)'stems). These latter losses lead to increased combustion emissions I without any net process benefit. The relative distribution ofnatural gas losses by source category is shown in Figure] 

### 1. Leaking equipment components are the greatest source ofnatural gas losses at the gas plants, accounting for 550/0 ofthe total. Other major sources include leakage into flare systems (240/0), process venting (9%) and wells (8%). As sho\\ln in figure 12, natural gas losses from equipment leaks are contributed by open-ended lines, connectors, compressor seals and block valves, accounting for 32, 30,20 and] 5%, respectively. The top ten leakers at e.ach site (other than site]) contributed over halfofthe total natural gas losses from fugitive equipment leaks (referto Table 2). 4.3 Fugitive Equipment Leaks The following subsections characterizethe fugitive equipment leaks for components in natural gas service at the surveyed gas plants. An overview ofthe fugitive leaks from gas processing plants, gathering compressor**stations~** and we]] sites is shown in Table 3. The lost values from these sources are $536,270 from gas plants,$49,O] 8 from gathering compressor**stations~** and**$3~]** 83 from well sites per year., 4.3.1 Average Emission Factors Average emission factors viere determined for each type ofequiplnent component in natural gas service at the surveyed sites. The results are presented,in Table 4 and are compared to corresponding factors published by U.S. EPA (1995) for oil a'nd gas production operations and b)i U.S. EPA and GR] (1996) for natural gas facilities.**Overa]]~** the developed average emission factors are greaterthan 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**fJ~om** all tested components divided by the total number ofcomponents ofthat type surveyed. Quantification ofemissions from non-leaking components (i.e., components with sc:reening values bel\\ieen zero and ]**O~OOO** parts per million) \vas nol attempted.**Instead~** emissions from these components were assumed to be represented by the average no-leak emission rates presented in the Protocol for Equip1nent Leak Emission Estimates

### CU.S. EPA, ]995).

27Plant No. Gas Losses from Top 10 Leakers (1Vlscfd) Gas Losses from l\1easurable Fugitive Leaks' (l\1scfd) 0/0 Contribution by Top]O

Leakers 0/0 ofTotal Leakers
2 3 4 .5 

### ) Excluding leakage into flare systems. 0.04 0.08 0.05 0.06 0.2]

$49,018 2,044 97 ]31 1.348 882 '" "':"":"'::':-'i>:'"



# .**~~~·;i'1k~·:;·:** 

# .: ....".:./,.y:
...

### 'FI;~inle:ak'iri~: "

### ':~1;rh~'~**~:'::'/:**

### ..:. COr1)JOri·eIlts:'· : .EmHsions'

.

### (f9ti.~:~·}.;r;:."

## ..:.:"·'(T()**nri~::·:.:·:·::** 

## .,. fYr/F3cHity):" jYrJ.Fncmb,) 232

### :,:N'Grrib'~f: 'ofLeaks:**:l~el)lj~~d** 

### :.(Je:tks.//." ·'/fadlityf .,.; ":',; ';';:**~.;~,:. >~** ..>'

..

2,423 87 ]**2~243** 5 7**':N~fube)"6f'** 

## .

.Co:riip6nellts



## ..**}fJ"~~~(f.~':.·:"··.··** ",,,"·,io,,,,,1"1 '.

### (Compon('llts**)facnif,~)t>,/-** 

### .**$urnJh~ryQt"F'1.Jgi1hie** 

### ..**L€3k~F6rG3~.P)a.as;·Gall)erbig<~oml?r¢SS'or:** XVe))**Site·s·:::;~;'·':;.** .,",:'

.. :,:::..

## >. ",,'**·'·>~'i'::::i** .. ::,;..:.:..::::::'.:

..**::/<'}U'·:::.~):::)v;!~:~·** ·:r.

Gas Plant Gathering Compressor Station 'Veil Site ]2 238 ]] 8 117

28Figure 13 Distributions ofNatural Gas Losses 

### By Source Category

StorageTanks 0%)**~tion** Equiprrent 4°J'o

.

Leaking Cbrrp:)nents

... 55°J'o R-ocess Verting 9oJ'o Rares 24°J'o

## ~W:JIS 8°J'o

Total Natural Gas Emissions 

### = 14,457 tonne/yr

29

### Figure 14 Distribution OfNatural Gas Losses From EquipmentLeaks By Type OfComponent

BlockValves 15%

nectors 30% 

# l Q-ankCaseVent 0°1<, Regulators 0% R-essure Felief Valves 1°1<, Qifice Neter 0°1<,



### ControlVaJves 2°1<,

. OJrrpressor

### Seals] 20% 

### Q::en-ended Unes 32°1<,

30· ••

### >r~b!e ..

## 4.(2oJn**p~.rison** •.OfAeverage.THfi••••

### ~missioJ1f~~t?-rs.l)eri~7~~;.Fronl.··;

... ... .DataCoHected In Both Phases To Otber**PublislledVahje~~·;<** ..

Connectors 2.22E-03 3.30E-03 2.00E-04.**3.05~-04** Block Valves 1.10E-02 1.47E-02 4.50E-04 3.40E-03 Control Valves 4.85E-02 3.73E-02 4.50E-04 N/A Pressure Relief Valves 6.73E-02 4.70E-04 8.8 E-03 2.24E-03 Pressure Regulators 1.74E-02 6.31E-03 8.8 E-03 N/A Orifice Meters 3.58E-03 2.70E-03**8~8** E-03 N/A Crank Case Vents 8.83E-Ol 1.20E-Ol N/A N/A Open-Ended Lines 5.18E-02 2.39E-Ol 2.00E-03 9.02E-02 Compressor SealsD 8.52E-Ol 5.20E-Ol 8.8 E-03 1. 17E+00 N/A

A

B
c

D



### 4.3.2 Emission factor for this source type is not available.**Source~** U.S. EPA. 1995. Protocol fot Equipment Leak Emission Estimates. Research Triangle Park, NC 27711. Source: U.S. EPA and GRl. 1996. Methane Emissions froin the Natural Gas Industry. Volume 8: Equipment Leaks. Research Triangle Park, NC 27711. The factors presented in the column are for methane emissionsl 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**~olumns** are for THC emissions. 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 havebeen divided evenly among the seals on units with detected leakage. 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 ofprocess 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 en1ission factors (D.S. EPA, 1995). The lnain findings are as follows:

• Average hydrocarbon fugitive emissionrates for connectors, open-ended lines and block valves are shown by stream types as shown in Figure 13, 14, and 15, respectively. These three cOlnponents account for 77% ofthe total natural

31gas fugitive elnissions. COlnponents in fuel gas and process gas**servic~s,** even though notregistered to have the highest**~verage** elnission rates, have consistently to be on the highest four averaged emission rates among these three con1ponenttypes. In Figure 14, open-ended lines in propane and C4 stremns have significantly higher average elnissi6ns rates. This resulted from a cOlnbination oflow componentcounts and was dominated by a large leak identified in the categories. Each point on figures 

### 13-15 denotes the average elnission factor for the correspondingstremns the cOlnponent is serving on the ,horizontal axis. The iIiteger shown adjacent to each emission factor value is the number ofdata used to develop the factor. The vertical line through each average elnission factor denotes the 95% confidence liInits based on the variance in the compiled data and nUlnber ofdata points assuming a normal distribution. Under each ofthe component categories shown, one can not conclude an average einission rate is a function ofstremn type due tothe large 95% confidence interval. However, general trends were implicateq.

• Average hydrocarbon fugitive emission r-ates for connectors, open-ended lines and blockvalves are shown by

### process unit as shown in Figures 16, 17, and ]8, respectively. For all three cOlnponenttypes shown, their average emission rates in compressors and lnole sieve units are mnong the top three process unit types. \Vhile connectors, and blockvalves in sales units have relatively low average elnission rates, open-endedline in sales unitregistered the highest average elnission ratemnong all process units. This resulted from the combination oflow overall cOlnponent counts ofopen-ended lines in sale unit and one single big leaker identified in this category.

• COlnponentstend to have greater average emissions where subjected to , frequentthermal cycling, vibrations, or cryogenic service (see figures 16-18).

• All otherparameters had little orno iInpact on average emissions. In the Figures below, C2 = ethane,R = residue gas, FG = fuel gas, PG = process gas, P= propane refrigerant, C4= butane, NGL = natural gas liquids, C3= propane, LPG = liquefied petrol,eum gas. '

32Figure 15 Average THC Emissions For Connectors By Gas Streams0.04 

# ! 0.035 0.03 

# I 330 

## 8 0.025**.~** 0.02 

### I I 0.015 

## I ,004 

# f 0.01 0.005 5,634 1,081 1,845 435 93 0 C2 R FG PG P CA NGL C3 LPG Streatn Figure 16 Average THC Emissions For Open-Ended Lines By Gas Stream

5 4.5

4 3.5

3 til § 2.5**.~** 2 1.5

1 0.5

0 4

9

626 

### +28 131 21 60

.. 15

.... P CA PG FG Stream

33 C2 R C3 NGLFigure 17Average THe Emissions For BlockValves By Gas Stream**~.** 73**_.~** 

## -_..

# __•...._._ 

### _ __ .....................................•.



### _ .............•...•.



### _ _ : :..


## __._--_..•.....•..•............

### _-_._-----_.. 0.1 0.09 0.08 0.07 § 0.06
• til 0.05 0.04 

# t 0.03 0.02 <I: 0.01 0 p FG 147

C2 3,671 g)()**~183** 434 fr7 20 <b ;':\ PG R CA I\K?L C3 LPG Stream Figure 18 Average THC Emissions For Connectors By Process Unit

0.16 0.14 0.12

0.1 0.08 

# s- .t:;;f 0.06 0.04

Process Unit

34Figure 19**Aver.~g_eT~<; Ern.i~~io~s**  for 9pen-Ended**~ine :o.YJ>roces~**  Unit

0.9 4- 0.8 0.7 § 0.6**.~** n5 0.4 0.3 

# t 0.2 0.1

0 

## c#f/} 680

66 g 20 tIo 86 39 14 5 5 8 9

Figure 20-Average THe Emissions for BlockValves By Process Unit

n07 0.06 0.05

'-' § 0.04 

# I**.~** 0.03 CV' 0.02 

## " 

# t r\9 0.01

Process Thit

35Additional trends on the age of

### afacility, sweet/sourraw gas stream, and the potential ofilnplementing aprocess-unit-targeted DI&M program are illustrated in the figures thatfollow. In Figure 19, the methane fugitive emission per unit gas throughput (kg! MMcf) and the leak frequency 

### (%) are shown againstyears ofservice for the surveyed facilities. Facilities with longerthan 30 years ofservice have higher methane fugitive elnission perpnitthroughput and higher leak frequencies than those with less than 30 years ofservice. However, due to the limited nUlnber ofsurveyed facilities (3 with less than 30 years ofservice and2 with longerthan 30 years of seI'vice), it can not be concluded with statistical significance. Figure 21 Methane Emissions Per Unit Gas Throughput For Plants With Different Service Duration

.

Methane Emission (KglMMcf) 45 40 35 30 25 20 15 10 5 

### o <30 Years in seRVice >30

In Figure 20, the n1ethane fugitive emission per unit gas throughput (kg / MMct)

. and leak frequency are shown against raw gas type. Facilities with sourraw gas have significantly higher methane elnission per unit gas throughput and higher leak frequency as '\lell when cOlnpared with facilities with sweetraw gas input. As mentioned earlier, due to the limited number ofsurveyed facilities (3 with sweet and 2 with sourraw gas), the significance ofsour versus sweetprocess plants can not be concluded with statistical significance.

36Figure 22 Figure F Methane Emissions Per Unit Gas Throughput For Plants With Different Raw,Gas Type

50 45 40 35 Methane 30 ':/."':.'./'; Emission. 25 (KgfMMcf) 20 15 10

5 

## o Sour Raw gastype

In Figure 

### 21, fugitive Inethane elnissions are shown againstthe process units. Compressorrelated cOlnponents contributed the Inajority ofInethane fugitive en1issions at 92% with the Inole sieve being a distant second in Inethane emission contribution.at 50/0. These results validated the components under vibration (compressor units) and heat-cycle (Inole sieve units) services are a lot more prone to leaks. The overwhehning percentage ofmethane emissions contributed by

. these two processes and related components warrants instituting atargeted DI&M program.

37Figure 23 Methane Emissions Percentage by Process Units

Inlet Sei:>aration· Sales 1% 1% Mole Sie\e

. \

. 5% -------.:-.



### 4.3.3 LeakFrequencies D3methanizer 0%

Compressor 92% Others 1%**Fugit~ve** equipmentleaks are generally consideredto be well controlled when the leak frequency for each cQInponenttype
.(except connectors, COlnpressor and pump seals) is 2% or less. For connectors, the allowable percentage ofleaking cOlnpohents is 0.5%, and for COlnpressor and pump seals the allowable percentage is ]0%. Based on these guidelines, none ofthe categories for the combined plants would be considered adequately controlled (see Table 5). However, some categories at individual plants would have passed (i.e., connectors and block valves at Site 2). Table 5 below summarizes the Inost leakprone cOlnponents. Conlpressor seals, orifice nleters, control valves, and open ended lines constitute greaterthan 70% ofthe leak frequency.**Figu~e** 23 further illustrates the contribution ofeach componenttype to total THC emissions.

38

### Table 5 Number of Components And LeakFrequency AtEach>OfTheFiveGasPlants. Pressure ...•.•.·····</·1 I Crank tllock Control Relief<> Orifice Case Iconnectorsl Valves Valves Valves Regulators Meters Vents Open-Ended· Lines

I Site 1

Site 2

Site 3

Site 4

Site 5 Total Count I 20,045 

### I 1,581 191 1 43 

### I 63 

### I' 8 

### I - I 332 

### I 127 

### I 22,290 NUlllberofLeaker 1 273 1 84 1 6 I 0 1 2 1 1 1 - 1 31 1 71 I 468 Leak Frequency % 1 1.36 1 5.31 1 6.59 1 0.00 1 3.17 1 12.50 1 - I 9.34 1 55.91 1 2.10 Total Count 1 10,705 

### I 1,392 

### I 82 

### I - I 69 

### I 25 

### I - I 57 

### I - I 12,330 NUlllberofLeaker 1 48 ·1 22 1 7 1 - 1 4 I 1 1 - 1 9 1 - 1 91 LeakFrequency % 

### I ·0.45 

### I 1.58 

## r 8.54 

### I - I 5.80 I 4.00 I - I 15.79 1 - 1 0.74 Total Count I 15,552 

### I 2,225 

### I 108 

### I 59 

### I 46 

### I 10 

### I 3 

### I 291. 

### I 59 

### I 18,353 NUlllberofLeaker I 193 I 133 I 14 I 0 I 3 I 4 I 0 I 25 I 30 I 402 Leak Frequency % I 1.24 I 5.98 I 12.96 I 0.00 1 6.52 I 40.001 0.00 I 8.59 1 50.85 I**2~** 19 Total Count 1 14,509 

### I 1,657 

### I 158 

### I 21 

### I 131 

### I 11 

### I 23 

### I 160 

### I 17 

### I 16,687 Number ofLeaker 1 120 1 36 I 19 I 0 I 9 1 0 1 1 1 28 I 10 I 223 Leak Frequency % I 0.83 1 2.17 I 12.03 1 0.00 1 6.87 1 0.00 I 4.35 I 17.50 1 58.82 I 1.34 TotalCount· I 3,558 

### I 837 

### I 56 

### I 1 

### I 11 

### I 3 

### I I 

### I 215 

### I 96 

### I 4,778 Number ofLeaker 1 282 

### I 131 I 5 I 0 I 1 1 0 I 1 I 14 I 11 1 445 Leak Frequency % I 7.93 I 15.65 I 8.93 I 0.00 I 9.09 I 0.00 I 100.00 I 6.5 I I 11.46 I 9.3 I Total Count 164,369 

## F 7,692i

# I> 495 1 124 

# I 320 57 NUIllberofLeakerl916 

# I 406<1 51 10 

# I 1

39

### 4.4 TankEmissions
Ofthe five sites surveyed, three contains leaky tanks that were measured during the site surveys. Thiefhatches were found to be leaking and' subsequently the volume flow was measured. The average value ofgas loss is $906,296 peryearper site (see Table 6).

Gas Plant 1 37,801 2,670;645 Gas Plant2 183 3,429 Gas Plant 3 1,320 44,813 Gas Plant4 

### NA NA Gas Plant 5 

### NA NA

·4.5 Results for Retested Site One ofthe four surveyed sites frOlTI Phase I was retested in Phase II to investigate changes in its fugitive leak characteristics. SOlne of the process upits from Phase I were decOlnmissioned and repl!lced with new process units. COlnponent count frOln the decommissioned process units (5,590 components) is about 30% ofthe total plant count from Phase I (18,390 cOlnponents). The following sections discuss the process units that'were replaced andthe changes in fugitive emissions between the Phase I and Phase II plant surveys. 

### 4.5.1. Overall Plant Figure22 shows the overall THC elnissions between Phase I and II for the retest site. Component level emissions for each Phase were also demonstrated. The THC elnissions increased about 50% frOln Phase I to Phase II. While the Inajor THC contributors are the SaIne between Phase I and II programs, the percentage· contributions from each sourcefollowing changes atthe site were very different. The changes in the average THC elnission rate for each cOlnponenttype are contrastedin Figure 23.

40Figure 24 Total THC Emissions Between Phases

Total TH::: Bnissions (Kglh) 

### 140 120 100

80 60 40 20



## o E'lOllers [J BockValve IJ R.lrrp Seal 

### o QJen-encIed Une o O:Jntrol Valve El Corrpressor Seal o Connector Phase 1 Phase 2

Figure 25 Component Emission Rate Between Phases·

### r-:ST?1YF·CT77:T7"'S7'T7"'-7":'7'~·'·"-'-""C'··"""""""'-"'"_1.6 1.4 1.2 1 0.8 0.6 0.4

I IN =ai

.(1) ID 

## 6 Phase

4.5.2 Replaced Process Units THe Emission Rate (KglhI component)

About 300/0 ofthe original component count from Phase] was not active during the Phase]] survey due to decommissioning and replacing equipment. These decomnlissioned process units were replaced with new process units and their 4]associated fugitive equiplnent emissions were cOlnpared with those from the deconl111issiolled processunits in Phase 

### 1. In Figure 24, the total THe emissions for these two sets ofprocess units were compared. The THe emissions reduced by an estilnate of80% from Phase I (decomll1issioned units) to Phase II (new units). The average elnission rates per component between Phase I and II are cOlnpared and areshown in Figure 25. With open-ended lines being the exception, all other cOlnponents have significantly lower average emission rates in the newly added process units. Figure 26 Total THe Emissions Between Phases

450 400 350 300

f\eMy added, process units- Phase II**:7:"7:--'7------::t;-:f:j5~§____j** III Block'Val\e**~--:'-~~~---l** 0 Open-ended Une**~"-'--~~~":';"""';'=.,-j** 0 Control Val\e tim Compressor Seal o Connector

D3commissionedUlits.,. Phase I THe Emissions 250

(kg/h) 200 150 100 50



## o

Figure 27 Component Emission Rate Between Phases
2.5

2 THe Emisison 1.5 Rate (Kgfhlcomponent) 1 0.5

### o~~.~.~ Connectors 

## c.orrvessor Control Seal Val'S Open-ended BlockVal'S line Componenttype

The results ofthis cOll1parison tend to suggestthatthe 

### DI&M program conducted at this facility has been ineffective at controlling elnissions from fugitive equipment leaks. This apparent inability to control fugitive emissions using a

42DI&M progrmn may be attributed to a nUlnber offactors including: excessive durationbetweensurveys,-inadequate-fellow-upto--maintenance recommendations and insufficient docunlentation ofInaiJitenance activities. The 5 yeartime frame between these two surveys exceeds the estimated meanrepair life for most cornponents. This.makes it difficultto assess the effectiveness ofany repairs nlade in response to the Phase I"survey because the leaks are likely to have reoccurred; Increasing the frequency ofleak surveys to annually orbi-annually would allow fora better assessment ofthe effectiveness ofmaintenance activities and enable new leaks to be identified and repaired sooner. It is unclear what Inaintenance activities were undertaken in response to the Phase I survey. For example, a substantial leak frOlna weld failure identified during the Phase I survey was also found to be leaking during the phase II survey. In order for the program to be effective, all cost-effective control opportunities should be acted on by eitherrepairing the leak orreevaluating the economics tojustify no action. Any maintenance performed in response to the survey should be adequately documented so the success ofthe repair can be addressed during subsequentsite surveys. Accurate maintenance records will facilitate in tracking the true economics ofthe repair, arid ultinlately assist in establishing future control opportunities. 

### 4.6 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 96.6% 9ftotal_ fugitive liatural gas losses could be avoided ifall control opportunities with positive net cost orapositive payback are iJnplemented (see Figure 26). This wouldresult in corresponding reductions of97% in fugitive methane en1issions, 97% in fugitive GHG emissions, mid 

### 980/0in fugitive NMHC elnissions in the first year alone. Moreover, Inany ofthe control options have n1ulti-year life expectancies resulting in significant elnission reductions in subsequentyears as well. 

### 4.6.1 Cost Curve for Reduction ofGHG Emissions To further evaluate the control ofnatural gas losses as a means ofreducing GHG elnissions, it is usefulto express the results in terms ofa cost curve. Figure 27 presents the net annualized cost curve for implementation ofthe various opportunities identified atthe five gas plants. The net cost ofeach target control oppOliunity is calculated as the equalized annual implementation cost overthe life ofthe project (i.e., the net present cost ofthe opportunity expressed as an equivalent series ofequal annual payments overthe life ofthe project) divided by the resulting average annual CO2 -equivalent emission reduction. Figure 

### 27 shows that the incremental costpertonne ofC02E GHG emission reduction resulting frOln implementation ofthe available control oppOliunities in ranked order fron1 most to least costeffective (i.e., see Table II-] in AppendiX II). The point at which the curve crosses overthe abscissa axis (i.e., the axis. of

43cUlnulativeC02E GHG elnission reduction) is the amount ofC02E emission reduction that could be achieved ifonly opportunities witha zero cost or a positive payback are iInplenlented (i.e.; 103,363 tonnesC02E reduction peryear). This reduction amounts to 17% oftotal estimated GHG emissions frotn the five gas plants. Ifa value is assigned to GHG elnission reduction credits, then companies may choose topursue opportunities even fUliher out on the cost curve. The shape of the costcurve shows that there are a few very attractive control opportunities, a \ large number ofmoderate control opportunities, and eventually apoint of diminishing returns.

44Figure 1 Emissions From Economically Repa,irable Sources



### o Leaks

unecononicaJ to repair (mscfd) mil Leak ECononicaJ

To Repair (mscfd)

Figure 2 Incremental Net Cost Curve For Cumulative C02E Emission Reductions At Surveyed Gas Plants

$500.00 -,--------------.-------... -'--". $400.00 $300.00 Incremental Net Cost ($ItonnesOO2E $200.00

Reduction) $100.00 $0.00 +-----,--'---,-----,------,----:-:::.....,..----i } 20 , ,000**80~** 100,000 120000 $10000 '-- --'

### -~--- ..._.....--..................-,--'-,-.......

### -~-----------.~ ...."""'., .- . CUJTl.Jlitive GHG Errission (tonnes C02E)

45 Economical

### 4.6.2 Control Opportunities With a Payback of1 Year orLess On apurely financial basis, opportunities to reduce natural gas losses must cOlnpete against other investlnentopportunities to receive funding. A common paraJneter used to evaluate opportunities is eitherthe effective rate ofreturn on the investlnent orthe paybackperiod. Tojustify equipmentupgrades orprocess enhancelnents, companies often look for apaybackperiod of 1 year or less. Accordingly, it is useful to consider only opportunities to reduce naturalgas losses that have apaybackperiod of 1 yearorless. Ifonly these control opportunities are**iInpl~mented,** it is estiInated that total natural gas losses, including unnecessary fuel consumption, would be reduced by 97%. Corresponding reductions in NMHC and GHG elnissions would both aJnountto 97% as well. The 10 greatest.individual control opportunities in the I-yearpayback category are listed in Table 7. Collectively, they accountfor 42% oftotal natural gas losses in this category.

Compressor

- 2" waterjacket connection" 194.25 $621,168 LP FO Scrubbercorrosion hole in bottle below HLL alarm Corrosion Hole 46.90 $102,893 Flare" fuel gas line

- Corrosion Hole 42.92 $111,631 Variable Volume Pocket 30.45 $97,380 Com ressor Com ressor Seal 16.27 $52,044 Compressor- distance piece vent (leak overwhelmed hiflow) Com ressor Seal 11.27 $33,573 Residue compressor (north caterpillar)

- common packing case drain Com ressor Seal 9.75 $25,863 Residue compressor (#2 ingersoll-rand)

- Valve Ca 9.34 $24,787 AmineTank PRV 9.34 $24,559 Compressor -reptured diaphram on 4 NPS control valve Control Valve

- ,4" 8.25 Total 378.75>

46

### 5 CONCLUSIONS AND RECOMMENDATIONS .5.1 Conclusions The second Phase added five additional gas processing plants to the fourplants surveyed in the first Phase. The plants chosen for this studyvaried in plant age, throughput, size, location and sweet and sour gas. The second Phase also included well sites and gathering compressor stations located upstremn frOln the gas processing plants. The variation \ ensures thatthe data collected represents an average for the natural gas processing industry. A comparisonwas conducted between the traditional leak detection methods and an optical passive infrared can1era was conducted at all sites. The sources with the greatestnatural gas losses were notnecessarily the most economical to control. Actual cost-effective emissions reduction opportunities may vary greatly between sites and not all gas plants will necessarily offer sufficient opportunities to justify the associatedidentification and control costs. In addition, actual economic opportunities depend on the natural gas value, and will therefore vary with fluctuations in the natural gas lnarketprice. Nonetheless, it is clear frOln the available datathat significant cost-effective emissions reduction opportunities do exist atall surveyed facilities and a rational approach to finding these opportunities at all gas plants may be economically attractive to industry. While any econOlnical-to-repair leaking**con1ponent~** detected by such efforts should be repaired,average leakrates based on cOlnbined data froln the five test sites suggestthat the lnost cost-effective approach would be to generally focus on the following types of components: I I

• block and control valves,

• orifice lneters,

• open ended lines,

• pressure reliefvalves,

• regulators,

• flange connections,

• crankcase vents,
• compressor seals, and

• con1pressorvalve steIns and valve caps. Additionally, cOlnponents operating inthermal cycling (lnole sieve) and vibration (con1pressor) applications have higher leak rates than other cOlnponents. The results show that cOlnponents in these two applications contributed 97% ofthe fugitive leaks and suggestthatprocess-unit-targeted DJ&M progrmns would have tremendous cost-effective emissions reduction potential. A DI&M program focusing on equiplnent in vibration and/or thennal cycling operation would likely identify and repair nearly all the large leaks at a £I-action ofa full facility DJ&M program cost.

47

### 5.2 Recommendations for FurtherWork Specific recommendations are:

• The amount and composition ofemissions from engine and compressor crankcase vents, and field practices for the vent systems design should be examined more closely. In particular, the potential for air-toxic emissIons from crankcase vents, especially those on engines, should**b~** 

### determined. Moreov'er, the practice of some companies to exhaust crankcase vents into buildings and work areas,.a practice manufacturers discourage, shouldbe evaluated.

• There are a wide varietY'ofavailable technologies, as well as design and operating practices thatwould help**co~panies** 

### ,cost-effectively reduce natural gas losses; however, these technologies andpractices areunder-utilized. One such example is the application offlow sensors, which canbe installed on compressor sealventsat arelatively low cost. Flow sensors provide real-time excessive leakage detection. They may also be applied to crankcase and othervents. Only one ofthe five sites had installed sealventflow sensors, and the operators did not monitorthe sensors "readings. Additionally, emergency flare systems are notnormallyequippedwith flow meters, so in-leakage and excessive purge gas consumption often go ' unnoticed until natural gas losses produce anoticeably larger flame. Historically, meters were not installedbecause conventional obstruction meters do notprovide reliable readings overthe wide flow ranges and cause excessive system backpressure; however, non-intrusive ultrasonic flow meters, which overcome these problems, are now available. Moreover, ultrasonic techniques are available for identifying and quantifying leakage pastvalve seats into flare and vent systems.

• It 

### is recOlnmended that abestpractices documentbe developed to disseminate and encourage the cOlnpilationand use ofcost-effective emissions reduction practices. The document should'also provide infonnation required by companies to develop site-specificprograms for reducing theirInethane and non-methane hydrocarbon losses, and greenhouse gas emissions (e.g., delineate source categories and/or facility areas to focus efforts on for maximum benefit, generic costdata for evaluating control options, recommended monitoring frequencies, andtypical repairs life expectance by source type and service category).

• Analysis ofthe Phase I and Phase II results to detennine the relative costeffectiveness ofa facility wideDI&Mprogram and aprocess-unit-targetedDI&M program focused on components in vibration (i.e. compressor) orheat-cycle (i.e. mole sieve) services
Further analysis combining the data from Phase I and Phase II to improve the results statistical significance. Analyses should include, ata minimum, the plant level trends identified in the Phase 2 report (i.e. impacts offacility age and sweet or sour gas on methane emissions). Potential benefits includean age-based arid/or gas-type-based DI&M program that would also reduce the cost ofDI&M program.

48-Use oftheconibustion equipment and·c6mpressorperformance tests (new tests implemen·ted in Phase·2) in future surveys. These tests, when implementeq inthe surveyed faCilities, contributed significantly to thelTIethane and overall GHG emissions inventories.



### - It A follow up progrmTI to evaluate the impact ofmonitoring frequency on gas processing facilities DI&Mprograms·cost effectiveness.

49

### 6 REFERENCES CITED Howard, T., R. Siverson, A. Wenzlick andB; Lott. 1994. A High Flow Rate Sampling System for Measuring Emissions from Leaking ProcesS Components. Presented atthe 1994 International Workshop on Environmental Impacts ofNatural Gas Losses, Prague, Czech Republic.

. Gas Processors Suppliers Association Engineering DataBookVolume 1,**FigureI3~14.1** 

### 11th 

### edition, 1998. Hanlon, P.C., CompressorHandbook, McGraw-Hill, New York, 2001. ISBN 0-07-026005-2 IPCC. 1996. Climate Change 1995: The Science ofClimate Change. Cambridge University Press. New York, NY. pp.572. Loti, B., T. Howard and M. Webb. 1995. New Techniques Developed forMeasuring Fugitive Emissions. Pipe Line and Ga's Industry, v 75, nl0, October 1995. Picard, D.J., Smith M., Ross, B. 2002. Identification and Evaluation ofOpportunities to Reduce**M~thane** 

### Losses atFour Gas Processing Plants. GR! Report 02/0119. Stone, D.K., S.K. Lynch, R.F. Pandullo, L.B. Evans and W.M. Vatavuk. 1992. Flares. PartI: Flaring Technologies for Controlling VOC-Containing Waste Streams. Journal of Air and Waste ManagementAssociation, v42 n6.pp. 333-340.

I I 

### U.S. EPA (Environmental Protection Agency). 1995. Protocol for EquipmentLeak Emission Estitnates. Availablethrough NTIA. SpringfieldVA. PublicationNo. EPA453/R-95-017. Section 2. U.S. EPA (Environmenti::ll Protection Agency) and GR!. 1996. Methane Emissions from the Natural Gas Industry. Volume 8: EquipmentLeaks. Available throughNTIA. Springfield VA. PublicationNo. EPA-600/R-96-080h. U.S. EPA (Enviromnental Protection Agency). 1997. Method 21 -'Determination of Volatile Organic CompoundLeaks. Available onthe EPA website. (www.epa.gov/ttn/emc/promgate.html)

50