I

EPA Phase II Aggregate Site Report

Cost-Effective Directed Inspection and Maintenance Control

Opportunities at'Five Gas Processing Plants and Upstream

Gatllering C0111pressor Stations and Well Sites

PREPARED FOR:

Project Manager: Roger Fernandez

U.S. Environmental ProteCtion Agency Natural Gas STAR Program

U.S. EPA Grant No: XA-83046001-1

PREPARED BY:

National Gas Machinery Laboratory,

An Institute of Kansas 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

,................... '...........•...... == . 'J..'

;-.;: ,.. ... /..... ,,: ...... §' ................ •'~

.~ '~

March 2006

Rev]
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 of plant 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 of nonmethane hydrocarbons (NMHC) and contaminants, such as hydrogen sulfide (H2S),

nitrogen (N2), carbon dioxide (C02) and water vapor (H20). 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 (C02E) 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 of equipnient components in hy~rocarbon

gas service, lneasurement and characterization offlows into all key vent arid flare

systelns, and liJnited perfonnance testing of natural gas-fueled cOlnbustion equipment at

three ofthe five surveyed sites. Elnissions from selected pressure relief valves 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

that were noticeably leaking were tagged and brought to 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 of 74,438 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

measurement results. Additionally, specific emission-control opportunities were

identified, and a preliminary cost-benefit analysis 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 identifying site-specific constraints and to help ensure that cost data were

satisfactorily considered.

EMISSIONS INVENTORY OVERVIEW

Total atmospherk methane elnissions from all sources at the combined sites are estimated

at 8,071 tonnes per year. Corresponding GHG and NMHC emissions are estimated at

598,184tonnesper year C02E and 3,625 tonnes per year, respectively. The majority of

total methane emissions resulted from fugitive equipInent leaks (55%). Incomplete

combustion by natural gas-fuelled equipment and process venting are also 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 of all 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 per year (an average of $1.7 Inillion per year per.plant). The

fugitive emission opp0l1unities totalled $2.9 Inillion dollar or $580,000 per facility per

year. The cost to survey and repair these 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 of conlponents in gas service, were approxiInately $1.5 per

cOlnponent, which is Inore than the cost of conventional VOC LDAR programs. This per

cOlnponent cost Inay be reduced if a routine survey were to be implemented 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 of vents, combustion' sources and

control opportunities identified. The current study identified more than $3,200 in annual

ii
gross savings~ or $3,000 in net savings (including after repair or control costs), per

componentfor control opportunities having a less than a I-year payback based on a gas

value of $7.15/Mscf($6.78/GJ). Considering opportunity ide'ntificationcosts reduces the

net savings by only about 4%. If a value is assigned to the resulting GHG credits, work is

done as a routine commercial service rather than as a study, and efforts are focused on the

plant areas most likely to offer meaningful 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 of natural

gas increases, the number of components that are cost effective to repair will not increase

significantly however, the saving realized will scale commensurate with the price

increase. These reductions would result in.emission reductions of 61 % for methane, 17%

for GHG C02E, and 67% for NMHC 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 at the sites are:

• Fugitive Equipment Leaks:

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) at the 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 leak prone. The majority

ofthe identified natural gas losses from fugitive equipment leaks were attributed

to a relatively slnall number of leaking cOlnponents. Open-ended'lines emissi'ons

were the greatest contributor to this source category, accounting for 320/0 ofthe

total, followed by connectors (300/0), COlnpressor seals (20%), and block valves

(15%). The relnaining 3% were from pressure relief valves, 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/Mscf or $6.78/GJ). This

equates to an average gross annual savings of approxiJnately $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 newer plants. Conversely,

higher losses and more loss-reduction opportunities would likely be found at older

and/or poorly lnaintained plants.

Repairs to the 1

°largest elnitting cost-effective-to-repair cOlnponents at -each site

(refer to Appendix I for a CQlnponents list ranked 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 relief events) totalled 496 Mscfd. In several cases, the

system flows were sufficient to potentially justify installing a v.ent- or flare-gas

recovery unit. Alternatively, the residual gas flow source or sources (e.g., excess

purge gas consumption and leaking pressure-relief devices, drains, and blowdown

.valves connected to the flare header) could be repaired. However; these sources

are often difficult to isolate, usually require a Inajor plant 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 a year to pay 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-fuel ratios 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'at umnanned field facilities. Total avoidable fuel consumption

from servicing all econOlnic-to-tune engines and heaters at the five sites is

estiJnated to be 446 Mscfd, which equals GHG emission reductions of 13,100

tonnes C02E per year.

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 oftheir performance curve). Notwithstanding this, situations

Inay arise where engines are operated outside their performance curve optimum

area (e.g., due to changes in original load requirements caused by production

changes or initial equipment misInatching with process applications) causing

significant excessive operating costs.

KEY FINDINGS

• The value of natural 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 per year (an average of$1.7Inillion per year per plant). The findings

from these additional 5 plant surveys solidify the econOlnic benefits of voluntarily

, 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 have higher methane

elnissions per volume gas throughout and leak frequencies than facilities

processing sweet gas streaJns. Statistical comparisons for surveyed sites on the

. effects of gas plant service years and process stream type were not attempted due

to the limited number ofsites surveyed. It is recommended that additional

analyses, including results frOln the Phase I and other surveys, be conducted to

develop statistically significant correlations offugitiveequiplnent leak rates with

service years and process gas type..

• A targeted DI&M program aiJned at pro.ven opportunities can significantly reduce

the tilne and resources required to identify and repair those leaks that represent

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 prior to the Phase nsurvey. While fugitive emissions frOln the new

process units cOlnponents tested in Phase n were 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

v
indicates higher Phase II fugitive elnission leaks from 700/0 of components that

were not replaced between Phases, and suggests that the facility DI&M program

has not been effective at controlling fugitive equipment leaks at this site. In

addition, a comparison ofthe average Phase I and Phase II emission factors.by

component type 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 Leak Detection 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 Equipment Analysis 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-Benefit Analyses 21

3.2.1 Equiplnent Repair Cost Estimating 21

3.2.2 Natural Gas Value 22

3.2.3 Repair Life 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 .Leak Frequencies 38

4.4 Tank Emissions._ _. __ .. .__ . ._. __ .__ .__ .. _. __ ._.._._ 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 Cost Curve for Reduction of GHG Emissions 43

4.6.2 Control Opportunities With a Payback of 1 Year or Less : 46

CONCLUSIONS AND RECOMMENDATIONS 47

5.1 Conclusions 47

vii·
5.2 Recoirllnendations for Further Work. 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 Payout Period 94

Appendix III COlnbustion Analysis·and Efficiency Testing Results .134

Appendix IV .Average Equipment COlnponent Schedules for Natural Gas Processing

Plants .....................•............................•...............................367

Appendix V Financial Considerations and Assumptions 368

AppendixVI Basic COlnponent Repair Costs and Mean Repair Life 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 Compressqr Engines 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 For Block 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 Throughput For Plants With Different

Service Duration 36

ix
Figure 22 Figure F Methane Emissions Per Unit Gas Throughput For Plants 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 26 Total THC Emissions Between Phases ; 42

Figure 27 COlnponent Emission 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 of Plants Surveyed in Phase II v

Table 1 Summary of Surveyed Plants 5

. Table 2 Sumlnary of Fugitive Losses from the Top Ten Leakers 28

Table 3 Summary of Fugitive Leaks for Gas Plants, Gathering Compressor Stations, and

Well ·Sites 28

Table 4 Comparison of Average THC Emission Factors Derived from Data Collected at

the Test Sites to Other Published 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 of Top Ten Sources ofNatural Gas Losses Identified 46

Xl
Blow-By

Carbon Dioxide Equivalent

(C02E) -

Centrifugal COlnpressor

Seal SystelnsCombustion Efficiency -

GLOSSARY

Gas from a piston cylinder that leaks past the piston rings

into the crankcase.

Carbon dioxide equivalent is an expression ofthe 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 most relevant 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 of various greenhouse gases emissions

relative to carbon ·dioxide emissions. The current practice

(IPCC, 1996) is to use a 1OO-year tilne horizon for global

warming potentials. Therefore, the GWPs used in this

document are: C02 = 1.0, CH4 = 21.0 and N20 = 310.

Greenhouse gases emissions are converted to carbon

dioxide equivalent (C02E) elnissions by multiplying the

mass elnissions of each gas by the appropriate global

warming potential and sUlnmingthe C02E emissions.

C02E 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 wear between the seal and compressor

shaft, operating pressure, and shaft rotational speed.

The extent to which all input combustible Inaterial has been

cOlnpletely oxidized (i.e., to produce H20, CO2 and 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 heat ti"ansfer limitations. In fuel rich systems,

oxygen deficiency is also a factor.

xii
Connectors -

Crank CaseDestruction Efficiency -

Flare and vent systems -

Fugitive EmissionsGas PlantA connector is any flanged or threaded connection, or

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

connector can provide essentially leak-free service for

extended 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,

improper tightening, 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 crank case 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 extent to which a target substance present in the input

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

intermediate, partially-oxidized, and fully-oxidized

products of combustion). 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 or toxic 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 leaks frOID equipment components including,

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

pumps and compressors, pressure relief devices, process

drains, open-ended valves, pump and compressor seals,

system degassing vents, accumulator vessel vents, agitator

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

continuous emitters and have low to moderate emission

rates.

A gas processing plant is a facility for extracting

condensable hydrocarbons from natural gas and for

upgrading the gas quality to market specifications (i.e.,

r~moving contaminants such as H20, H2S and CO2 and

possibly adjusting the heating value).

xiii
Heat RateIntegral Compressor

Methane Leak

Molecular Sieve

Long-Term Natural Gas

Contract Price - '

Open-ended Valves

and LinesThe heat energy (based on the fuel net or lower heating

value) which Inust be inputto a combustion device to

produce the rated power output. H'eat rate is usually

expressed in terms of net J/kW·h.

A reciprocating cOlnpressor that shares a common·

crankshaft and crankcase with the engine.

Greater than 10,000 parts per million as measured by a

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

Absorbers composed of zeolites (aluminosilicate crystalline

polymers) used to relnove water vapor from natural gas.

Zeolites are r~generated periodically by heating.

Historically, long-term contracts have been used by buyers

to secure a natural gas supply and by sellers to reduce large

reserve development risk. During the 1960s and 70s, these

contracts wert: established for terms ofup to 20 to 25 years

and the 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

Inarket rates. Today, a typical long-term contract with a

cogeneration plant is about 15 years. Given the sellers and

buyers interest in risk management, there is also a trend

towards great~r standardization of long-tenn contracts to

facilitate hedging activity in the financial or the over-thecounter markets.

An open-ended valve is any valve that releases 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 or Worn

seat An open-ended line is a pipe or tube 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 over time.

Sonle common examples of open ended valves and lines

are:

XIV
Power Output -

Pressure-Relief or 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 instrument block valves where the instrument has been

removed for repair or other reasons; and

Ii purge or sampling points.

The -net shaft power available from an engine after all

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

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

lubricating oil, and liquid coolant) have been subtracted.

For heaters and boilers, it is the net heat transferred t.o, a

target process fluid orsystem.

Pressure relief or safety valves are used to protect process

piping and vessels from being accidentally over-pressured.

They are spring loaded so that they are fully closed when

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

when the set point is exceeded. Relief valves open in

proportion to the overpressure to provide modulated

venting. Safety valves pop to a full-open position on

activation.

When relief or safety valves reseat after activation, they

often leak because the origiTlal tight seat iSI

not regained

either due to seating surface damage or foreign material

build-up on the seat plug. As a result, they are often

responsible for fugitive emissions. Another problem

develops ifthe operating pressure is too close to the set

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

pressure.

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

at the 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, H20, S02, HCI -

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

combusted gases. These cOlnpounds may result from

thermodynamic, kinetic or transport 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

xv
Blow-By

Carbon Dioxide Equivalent

(C02E) -

Centrifugal COlnpressor '

Seal Systems -

COlnbustion Efficiency -

GLOSSARY

Gas from a piston cylinder th3;t leaks past the piston rings

into the crankcase.

Carbon dioxide equivalent is an expression ofthe 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 most relevant GHGs for

natural gas systelns are carbon dioxide (C02), methane

(CH4) and nitrous oxide (N20). Global warming potentials

(GWPs) were developed as a simple measure ofthe global

warming effects of various greenhouse gases emissions

relative to carbon dioxide emissions. The current practice

(IPCC, 1996) is to use a 100-year time horizon for global

warming potentials. Therefore, the GWPs used in this

docUlnent are: C02 = 1.0, CH4 = 21.0 and N20 ='310.

Greenhouse gases emissions are converted to carbon

dioxide equivalent (C02E) emissions by multiplying the

mass elnission~ of each gas by the appropriate global

warming potential and summing the C02E emissions.

C02E 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-ring shaft

seals, or dry-gas shaft seals are used. Seal leakage will tend

to increase with wear between the.seal and COInpressor

shaft, operating pressure, ,and shaft rotational speed.

The extent to 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 that contribute to

incOInplete combustion are thennodynamic, kinetic, lnass

transfer and heat transfer limitations. In fuel rich systelns,

o~ygen deficiency is also a factor.

xii
Connectors -

CrankCase -

Destruction Efficiency -

Flare and vent systelns -

Fugitive ElnissionsGas PlantA connector is any flanged or threaded connection, or

Inechanical coupling, but excludes all welded or b.ackwelded connections. If properly installed and maintained,a

connector can provide essentially leak-free service for

extended time periods. However, there are many factors

that can cause leakage problems. Common leak causes

include vibration, thermal stress and cycles, dirty or

dmnaged contact surfaces, incorrect sealing material,

ilnproper tightening, 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 extent to which a target substance present in the input

combustibles has been dest~oyed (i.e., converted to

intennediate, pmiially-oxidized, and fully-oxidized

products of cOlnbustion). 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

where the waste gas contains odorous or toxic 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 leaks frOln equipment components including,

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

pumps and cOlnpressors, pressure relief devices, process

drains, open-ended valves, pUlnp and compressor seals,

systeln degassing vents, accumulator vessel vents, agitator

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

continuous emitters and have low to moderate emission

rates.

A gas processing plant is a facility for extracting

condensable hydrocarbons from natural gas and for

upgrading the gas quality to market specifications (i.e.,

renioving contan1inants such as H20,H2S and CO2 and

possibly adjusting the heating value)..

xiii
Heat RateIntegral COlnpressor

Methane Leak

Molecular Sieve

Long-Term Natural Gas

Contract Price ,;.

Open-ended Valves

and LinesThe heat energy (based on the fuel net or lower heating

value) which mList be input to a: combustiondevic'e to

produce the rated power output. Heat rate is usually

expressed in terms of net J/kW·h.

A reciprocating compressor that shares a common

crankshaft and crankcase with the engine.

Greater than 10,000 parts per million as measured by a

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

Absorbers composed of zeolites (alUlninosilicate crystalline

polylners) used to remove water vapor from natural gas.

Zeolites are regenerated 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 development risk. During the 1960s and 70s, these

conti"acts were established for terms ofup to 20 to 25 years

andthe gas price was determined by periodic negotiations.

The recent trend is towards shorter contract durations, and

Inost new long-:tenn contracts index the gas price to spot

market rates. Today, a typical long-term contract with a

cogeneration plant is about 15 years. Given the sellers and

buyers interest in risk Inanagement, there is also a trend

towards greater standardization oflong-term contracts to

facilitate hedging activity in the financial or the over-thecounter markets.

An open-ended valve is any valve that releases 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 or worn

seat. An open-ended line is a pipe or tube segment attached

to a leaking valve and that opens to the atmosphere.

Few open-ended valves and lines are designed into process

systems. However, actual numbers can be quite significant

at some sites due to poor operating practices and various

process·modifications that may occur over time.

Some common examples of open ended valves ~nd lines

are:

xiv
Power Output -

Pressure-Relief or 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);

-. instrUlnent block valves where the instrument has been

removed for repair or other reasons; and

• purge or sampling points.

The net shaft power available from an engine after all

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

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

lubricating oil, and liquid coolant) have been subtracted.

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

target process fluid orsystem.

Pressure relief or safety valves are used to protect process

piping and vessels frOln being accidentally over-pressured.

They are spring loaded so that they are fully closed when

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

when the setpoint is exceeded. Relief valves open in

proportion to the overpressure to provide modulated

venting. Safety valves pop to a full-open position on

activation.

When relief or safety valves reseat after activation, they

often leak because the original tight seat is; not regained

either due to seating surface damage or foreign material

build-up on the seat plug. As a result, they are often

responsible for fugitive elnissions. Another problem

develops ifthe operating pressure is t60close to the set

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

pressure.

Gas that leaks from a pressure-reliefvalve may be detected

at the vent pipe (or horn) end. Add~tionally, there normally

is a lnonitoring port located on the bottOln ofthe horn near

the valve.

These are any cOlnpounds, excluding CO2, H20, S02, HCl

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

cOlnbusted gases. These,cOlnpoun'ds Inay result from

thennodynamic, kinetic or transport 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

xv
Pump SealsReciprocating Compressor

Packing Systems -

Standard Reference

Conditions -

Thermal Efficiency -

formed).

PositIve displacement pumps are normally used for

pUlnping hydrocarbon liquids at oil and gas facilities.

Positive displacement pumps have a reciprocating piston,

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

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

controlling leakage around the pUlnp shaft. It may 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 tightening and periodic packing

replacelnent.

Particulate contmnination, overheating, seal wear, sliding

seal leakage, and vibration will contribute to increased

leakage rates over tiIne.

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 under the best of conditions.

According to one Inanufacturer, leakage from within the

cylinder or through 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 equipment manufacturers reference flow,

concentration, and equipInent performance data to ISO

standard conditions of 15°C, 101.325 kPa, sea level an'd 0.0

% relative hUlnidity.

The percentage or pOliion ofinput energy converted to

useful work or heat output. For combustion equipment,

typical convention is to express the input energy in terms of

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

following relation for thermal efficiency:

Th I E~(fi' . Useful Work/Heat Output 100% 7J = 1 ,erma . :JJ lClency = x 0

Net Heat/Energy Input

Alternatively, thermal efficiency may be expressed in terms

xvi
Total Hydrocarbons -

Total Organic

COlnpounds (TOC) -

Valves -

of energy losses as follows:

.r;= (1- ""LEnergy Losses 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 heat rejected to cooling jacket water and lubrication oil;

It "radiation from equipment hot 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 least one 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 ofper fluorocarbons).

There are three main locations on a typical valve where

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

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

valve seat. Leaks ofthe first type are referred to as valve

leaks. Elnissions frOln the end connections are classified as

connector leaks. Leakage past the 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 leak points on the different valve 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 part to leak is the valve-stem

packing.

"The different valve types include gate, globe, butterfly,

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

xvii
Vented Emissions -

Volatile Organic

Compounds (VOC) -

and the rest are quarter-turn valves. Valvesmay either be

equipped with ahand-wheel or'lever for 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

start lnotors, chemical injection and odorization pumps,

instrument control loops, valve actuators, and some types

of glycol circulation pUlnps), equiplnent blowdowns and

purging activities, and glycol dehydrators still-column offgas venting.

Any compound of carbon, 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 of per fluorocarbons.

xviii
ACKNOWLEDGEMENTS

The funding provided by US Environmental Protection Agency (Grant Number XA8304-6001-1)" in support ofthis project is gratefully acknowledged~ Special thanks are

given to the personnel at each ofthe host facilities for their help, 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 measurelnent program was conducted

during the first quarter 2004 and second quarter 2005 at five gas processing facilities in

the USA. The selected facilities were of various ages, types, and throughputs and were

evaluated with a strong emphasis on identifying and quantifying natural gas losses from

leaking equipInent cOlnponents in heat-cycle and vibration services. The facilities

included sweet and sour gas processing, and a variety of processes including

cOlnpression, separation, storage, and flare systelns.

The study's primary objective was to demonstrate the cost-effectiveness of conducting 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 of elnissions 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 test results,

the greatest opp0l1unities for cost-effective reduction of natural gas losses are from the

control of leaking 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 Ineasurement prograJn results are presented in Section 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 of all the identified equipment leaks are provided in Appendices I and II, --

ranked by emission rate and payout period, respectively. The following information 'is

prov'ided for each component: Site No., Tag No., Process Unit, Component Description,

Elnission Rate (l03 In3

/yr), Estimated Repair Costs ($), Net Present Value ofRepair ($),

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 unit type

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

Under the settlement terms of a recent Consent Decree, deadlines are estaplished for EPA

to review and, if appropriate, revise the NSPS standards for Subparts J, VV and GGG, 40

CFR 60.100-109, 60.480-498, 60.590-593. The New Source Performance' Standards in

40 CFR Part 60 KKK (back reference 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 leak potentials and the cost-effectiveness

ofimplelnenting LDAR prograIns at natural gas processing facilities.

Most natural gas industry LDAR prograIns rely onU.S. EPA Method 21. Depending

upon the leak screening instrument detector, the concentration of either total

hydrocarbons (THe) or VOCs in the air from a leaking cOlnponent is measured, and then

the leak rate 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 a prescribed frequency (e.g.

quarterly, bi-annually or annually). All components that screen above a given threshold

(typically'] 0,000 parts per million) 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 100,000 parts

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 leak rates;

however, is very tiIne intensive and expensive and 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 per Inillion per Method 21, resources are wasted by

repairing components - 35% ofthe total b&sed on the Phase I results - whose repair costs

exceed the value of gas saved. Another shortcoming ofthe conventional Method 2]

approach is that it does not accurately Ineasure either the facility baseline emissions or

the elnissions reduction (erroris ± 300%). Because the elnissions reduction cannot be

accurately detennined, the benefits ofiInplementing an LDAR program cannot be

evaluated.

2
The HiFlowTM Sampler, describedin Section 3.1.2, quickly and accurately quantifies

fugitive emissions leak rates"Rnd has signtfic"antly reduce"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 not performed

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 SaJ11pler LDAR program accurately measures the facility" baseline emissions I

and the emissions reduction can be accurately deten11ined.Therefore, the LDAR program

implementation benefits can be evaluated.

Figure 1 Leak Rate versus Concentration

-

0 1.0E+01

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

at natural gas processing arid production facilities,. and delineate and quantify the extent

of cost-effective opportunities for reducing these e111issions. A secondary objective is to

evaluate the potential for cost-effective reduction of other GHG e111issions (primarily

CO2) through process efficiency gains, and to establish a Best Manage111ent Practice for

conducting DI&M programs.

Primary sources of 111ethane 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

3
serves as the basis for developing an industry specific best management praCtices

guidance ,document.

Phase II provided the following:

II An increased number and type of gas processing facilities and components within

the current database giving an improved statistical basis for extrapolation ofthe

results systeln--wide.

II An indication ofthe effectiveness ofrepairs to the major leakers at a Phase I

facility and the increases in leakage over tiIne at gas plants.

II An initial indication of CH4 and GHG emission reduction opportunities atgas

production facilities upstream ofthe gas processing plant (e.g., gas-gathering

systelns including compression and well-site facilities).

Although the primary goal of Phase II was to expand the results ofthe prior Phase 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 of work and project approach for the second Phase was consistent

with the Phase 1 study and allows for direct comparison 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 lneasurement techniques 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 offer the greatest opportunities for cost-effective reduction of natural gas

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

seJected. These plants ranged from 6 to 57 years in age, for an average age of 31, and all

ofthem have compression facilities and mole sieve dehydration units. In comparison, the

average age of gas 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 in Table 1 above include cOlnponents less than 0.5"

nonlinal pipe size. Overall, 14.5% ofthese cOlnponent counts are cOlnponents less than

0.5" nOlninal pipe size.

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;

• performance testing naturalgas-fueled combustion equipment;

CD performance testing of cOlnptessors (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 most process-, fuel- and waste~gas systems were

screened for leaks. Components types surveyed included flanged and threaded

connections (i.e., connectors), valves, pressure-relief devices, 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 Detector to 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 leak rates (U.S. "EPA, 1995) and relative nUlnbers. Leak

detection (or screening) was conducted using bubble tests with soap 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 of cOlnponents .

(including pipe threads, tubing connections, and valves) because it is usually the

fastest screening technique. ~Olnponents that could not be 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 per lnillion or greater defined con1ponents as leaking or "leakers."

6
Under normal operation, waste gas volumes from blowdown or depressurization

events are sent to the flare system. Ifthe valves do not properly reseat after one of

these events, gas will continuously leak through 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~ Physical Acoustics 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 instrument uses

an acoustically coupled sensor that is held against the pipe upstream and

downstream ofthe pressure relief valve and the relief valve body. At each

location the sound level in 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. Allleaker tags were left in place after the leak rate measurelnent to allow

follow-up action by facility persOl'inel. A total of 74,438 individual equipment

conlponents and numerous process vents, natural gas-fueled compressor and

generator engines, process heaters, and flare/vent systems were surveyed.

Sufficient process infonnation was collected to deternline total annual emissions

from the cOlnpiled lneasurement results.

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 that cost data

were satisfactorily considered.

3.1.2 Leak Detection 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

7
thorough; 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 well during numerous field trials, there are not yet sufficient data to

demonstrate that the technology should be adopte<i in lieu oftraditional screening

techniques.

Although separated and excluded frOlu the EPA portionofthe scope ofwork, al'1

five facilities integrated a passive luidwave infrared camera in the leak surveys.

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 data to 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 that EPA will consider addressing reluote leak detection

luethods within future revisions to the New Source Perfonuance Standard (Under

the settlement tenus of a recent Consent Decree, deadlines are established for

EPA to review and, if appropriate, 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 IR camera is capable ofscreening leaks approximately 3 tiJues faster than

conventional methods (for two people: typically 2,400 cOluponents/day for

conventional versus 6,400 cOluponents/day for the optical);

• The IR cmuera is not currently capable of quantifying a leak and can only be used

to identify leak sources. The camera is capable of identifying leaks (using a

variety oflenses) that are inaccessible to conventional techniques that principally

rely on direct access.

• The camera offers visual confinuation ofleaking eluissions sources and allows

rapid source identification; however, mubient hydrocarbon 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;

• Water vapor overlays the hydrocarbon absorption spectra and therefore steam

plumes are visually comparable to hydrocarbon leaks and very difficult to

differentiate;

• Rain and fog limit the IR camera utilization; 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.

8
Leaks can occur through valves and pressure relief valves that have not seated properly

after activation. This leak is not out ofthe process equiplTIent and so cannot be seen with

optical methods or by organic vapor analyzers. Instead an acoustic method has been

developed that measures the noise generated by gas flowing through a slTIall gap. The

acoustic detector yompares the sound before the valve; at the valve and downstream frOlTI

the valve and compares the sound to a database of previously measured leaks. This

instrument was used to measure leaks at pressure reliefvalves.

Due to the high volume offlared hydrocarbons at several sites and the large number of

possible sources tied into the flare systelTI (e.g., leaking pressure-relief devices, drains,

and blowdown valves corme'cted to the header), connecting the flare to a vapor recovery

unit should be considered as a cost effective option for capturing the residual gas flow.

Another option isto targetthe individual residual gas flow sources; however, these.

sources are often difficult to isolate, usually require a major plant shutdown to fix (i.e.,

resulting in significant indirect costs), and are likely to reoccur.

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

Figure 6. Tagged Leaking Components

10
Figure 7. Cut-Away View Of A Natural Gas Co.mpressor Showing The Potential

-:Lea-k-Pointslncluding-The-Compressor"Seals And-Crankcase Vent.

CRANKCASE

VENT

Vent

•

Vent

RECIPROCATING COMPRESSOR

PACKING & VENT SYSTEM

Oil

EXPANDED VIEW OF THE

COMPRESSOR HEAD

11

PACKING

CASE

,

Leakage

Leakage

Leakage
The 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 Sampler was the priInary emission rates ~easurement Inethod for

leaking equipment components. The HiFlowTM Sampler was not used for

cOlnponents leaking at rates above the equiplnent upper limit (i.e., about 14 m

3

/h

for the current HiFlowTM 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 Phase II for consistency. The' following provides a brief description 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. Bagging all leakers to differentiate

between econOlnic-to-repair and uneconOlnic-to-repair cOlnponents is expensive

and, therefore, is not nonnally done (typica1l1M ]Oto 30 leak-rate aneasurements

per hour 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 leak rates does not provide sufficient

accuracy for econOlnic analysis. The correlation leak rate 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 a practicable means of making

objective repair decisions. The reliability and use ofthe HiFlowTM Sampler has

been delnonstrated in a nUlnber ofstudies (Howard et a/., 1994; Lott et al., 1995).

The HiFlowTM Sampler operating principle is siInple - a variable-rate inducedflow samplingsysteln provides total or near total leaking cOlnponent emissions

capture. Specially-designed attachnlents are used to encapsulate the leaking

conlponent and allow ambient air to flow over the cOlnponent; the air-leaking gas

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

corrected for-' 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 Sampler is intrinsically safe and is equipped with a grounding wire to

dissipate st,atic charge formed as air passes through the saJnplecollectiori line and

instrument..

Th~ HiFlowTM Sampler battery-operated fan can generate am'aximum sampling

velocity of approximately 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 either fall below the sample detector range or to decrease to

backgrouncilevels resulting in a zero reading. The sampling rate is'adjusted

manually using abackpressure valve mounted on the fan outlet. For large 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 and background hydrocarbon detectors were

calibrated with] 000/0 methane and 2.50/0 methane-in-airto cover both ranges of

the dual-element detector system. The detectors were zeroed using ambient air

upwind ofthe facilities. The ca,librations \vere done prior to HiFlowTM Sampler

use at each site, and then periodically thereafter-tb;ensure that n6 isignificant drift

occurred. The HiFlowTM Sampler was also periodically calibrated by releasing

known methane flows, determined using a bubblometer 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.

13
Figure 8. Pro1otype GRI HiFlowTI\~ Sampler

3.1.4 Ven1s a nd Open-ended J..Iines Emissions J\1easu rements

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

appropriat~ flo\v-through measurement device (i.e., a precision rotary meter, .

.diaphragm flo\\! meter, or rotameter, depending on the flow rate) iftotal 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 or tube

\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 of neoprene or plastic 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 or thermal dispersion

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 needed for

reasonable flow rate estimation. Low flo\\' veloc.ities in large diameter pipes

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 a portable 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 et aZ. (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 of conserving the gas

losses can thenbe determined.

P-rimary sources offlaring aild vented emissions include disposal of waste

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-] 00/0of valves 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-fue led 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 or to redl!ce energy

requirements through process modifications \:vas beyc;md 'the projectscope.

The testing on each unit involved analyzing the flue gas,meas'urlng the flU'e gas,

temperature~ obtaining a fuel 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~ or to determine overall unit performance.

Consequently: a simplified approach was used where the following parameters

were evaluated and their deviationsfro111 proper operating cOllditions were'

indicators of improvement opportunities:

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

• excess air setting; and , ,

• flue ,gas concentrations of carbon 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.: compressor units

\vhere the engine and compressor share a conlmon crankshaft and crankcase),"

crankcase ventemissions potentially include engine cylinders blow-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 a building or work area.

This poses a potential health and safety risk. Figure 7 depicts various venting

configurations l~ecommended by the engine manufacturers.

Key sources of combustion emissions ijlclude~ oversized engines, heaters and

boilers~ poor lUning (e.g., air/fuel ratio), leakage past pistons in engines: lack of

waste heat utiljzation~and fouled burner tubes.

]6
Figure 9. Typical S1a1ionaD7 Compressor Engines CnmkC3&e Vent Configurations

Recommendedb)1 lVhmufacturers.

Building ROOf---, ......±.__...:.-_'-----:- ...:.--I-==:::::;-Crankcase Breather Line

.----.,t--Clean-out Port

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

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

:" I

"-

('- ~) 4-LU~e_OiIDrain 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 of normal 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 detailed results 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 of compression varies with the changein enthalpy according to the

following equation: I

I

(D.I)

Where:

fiJI is the compressor ,vork

·is the mass flow rate of gas

. is the suction enthalpy

. is~he dischar,ge enthalpy

The following property data was collected for each stage of compression:.

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 of interest such as enthalpy and

entropy follow from the temperature and pressure measurements and the actual

work of compression 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 entropy and measured

discharge pressure. For an isentropic. process entropy is conserved and the

discharge entropy is determined from the suction state. The suction enthalpy

follows from the state definition and the ideal compression work can be calculated

using EquationD.l. This ideal compressor work is corrected to account for valve

pressure drop based on the method presented in Figure 13-14 of Gas Processors

Suppliers Association Engineering Data Book Volume'l. The corrected ideal state

is then defined by the enthalpy calculated using equation D.l and the measured

discharge pressure. The corrected 'ideal discharge 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. For the purpose ofthis analysis an acceptable energy loss is taken as 5%

ofthe corrected ideal energy require,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 greater then the acceptable

compressor work a potential savings is estimated. This estimate takes into account

the efficiency ofthe compressor driver and the price of natural gas. I i

I I

Key sources of compressor inefficiencies include, internal valve and cylinder

leakage in reciprocatingconlpressors, pulsation losses, excessive gas

recirculation, non-optimal loading.

3.].8 S10rage Tanks Excess Emissions Evaluations

Storage tanks are a potentially significailt emission sources due to evaporation

losses, paI1icularly where intentional product boiling or flashing occurs. Primary

sources ofstorage tank emissions include:

• Flashing losses at production 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 -vapor recovery systems;

It Faulty blanket gas regulators or pressure controllers; and

• Fouled vapor collection lines.

19
However, other less recognized, and often unnoticed; contributions,to

atmospheric emissions or vapor losses from storage t~nks include the following:

• Process gas or volatile product leakage past drain or 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 of high ,vapor pressure

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 in direct atnl0spheric emissions of product

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

of eac.'h process unit. The following component information ",'-as collected:

• type (e.g., connector, valve, control valve,pressure relief valve, 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).

20
3.1.1 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 of components:. Total

emissions are the sum of emissions 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 Emission Estimates (U.S. EPA,

1995). '

'3.1.11 Emission Control Guidelines

There are currently no regulations or codes of pi"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% for compressor

seals, 0.50/0 for connectors, and 20/0 for other component types

3.2 Eq uipmen1 Repair Cost·Benefit AnaJvses

Practicable oppo11unities for reducing fugitive equipment leak and process venting

emissions were assessed on a source·by·source basis. The net cost/benefitsof identified

control options were determined in dollars per tonne of C02-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 to repair 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 of gas 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 after the leak

detection and evaluation.

3.2.2 Natura) Gas Value

Tne value of natural 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/GJ and condensate $9.63/GJ. The actual value of avoided natural gas

losses is very site-specific and can depend on many factors including:

• Local market pricing;

• ]mpact of emission reductions on specific energy consumption, equipm,ent

life, ,vorkplace safety, and system operability, reliability and deliverability;

• Contract terms; ,

• Facility remoteness; .

• Gas concentrations of contamiilants and NMHCs;

• Applicahle taxes and tax shields.

3.2.3 Repair Life

It ,vas assumed that a leak, once repaired, will remain fixed for some finite time

period, and then will reoccur. The mean time 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 of associated equipment

units. ]n a formal 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 (for these analyses, the'shonest repair lifetime is assumed to

22
be one yea'r). Control measures \vith lifetimes greater than one year will 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 at these facilities.

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

presented in 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' of methane, 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 per year, respectively. The relative distributions o(these emissions by source

category are presented in Figures 8 to ]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 C020n1y 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 ofnitrous 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 of methane 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 by combustion equipment

and wells.

The C02E 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..

23
Figure 10 Distrihution of Methane hy Source Category for All Sources.

<?as Q:Jeration

[)::Nice

O°fc,

Storage Tankt;

1%

Corrbustion

Equiprrent

17%

Recess Venting

16%

Rares

2°fc, V\ells

4%

Leaking

Corrponents

60%

Methane Emissions = 8,072 tonne/yr

24
Figure!1 Distribution, Of Non-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

25
Figure 12 Distribution OfTotal GHG Emissions By Source Category.

Recess Venting

5°16

Storage Tanks

0°16

Corrbustion .

Equiprrent~~ 74°k

Rares

3°16

V\efls

1°k

Leaking

Cbrrponents

17016

GHG Emissions = 598,184 C02E tonne/yr

26
4.2 Natura) Gas Losses

The value of natural 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 direct leakage 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 re lative distribution of natural gas losses by source category is shown in Figure] 1.

Leaking equipment components are the greatest source of natural 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 half ofthe total natural gas losses

from fugitive equipment leaks (refer to Table 2).

4.3 Fugitive Equipment Leaks

The following subsections characterize the 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 of equiplnent 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 greater than those.

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

for natural gas facilities.

The average emission factors are simply the total emissions fJ~om all tested

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

Quantification of emissions 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).

27
Plant 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 of Total

Leakers

2

3

4

.5

) Excluding leakage into flare systems.

0.04

0.08

0.05

0.06

0.2]

]31 97 2,044 $49,018

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

5 ] 2~243

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

28
Figure 13 Distributions of Natural Gas Losses By Source Category

Storage Tanks

0%)

~tion

Equiprrent

4°J'o .

Leaking

Cbrrp:)nents ...

55°J'o

R-ocess Verting

9oJ'o Rares

24°J'o

~W:JIS8°J'o

Total Natural Gas Emissions = 14,457 tonne/yr

29
Figure 14 Distribution Of Natural Gas Losses From Equipment Leaks By Type Of Component

BlockValves

15%

nectors

30%

l Q-ankCase Vent

0°1<,

Regulators

0%

R-essure Felief

Valves

1°1<,

Qifice Neter

0°1<,

Control VaJves

2°1<, .

OJrrpressor Seals]

20%

Q::en-ended Unes

32°1<,

30
·••>r~b!e .. 4.(2oJnp~.rison •.Of Aeverage.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 have been 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 of process stream (e.g., fuel gas, residue gas, acid

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

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

average en1ission factors (D.S. EPA, 1995). The lnain findings are as follows:

• Average hydrocarbon fugitive emission rates 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

31
gas fugitive elnissions. COlnponents in fuel gas and process gas servic~s, even

though not registered to have the highest ~verage elnission rates, have

consistently to be on the highest four averaged emission rates among these

three con1ponent types. In Figure 14, open-ended lines in propane and C4

stremns have significantly higher average elnissi6ns rates. This resulted from

a cOlnbination of low component counts and was dominated by a large leak

identified in the categories. Each point on figures 13-15 denotes the average

elnission factor for the corresponding stremns the cOlnponent is serving on the

,horizontal axis. The iIiteger shown adjacent to each emission factor value is

the number of data 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 of data 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 to the large

95% confidence interval. However, general trends were implicateq.

• Average hydrocarbon fugitive emission r-ates for connectors, open-ended lines

and block valves are shown by process unit as shown in Figures 16, 17, and

] 8, respectively. For all three cOlnponent types shown, their average emission

rates in compressors and lnole sieve units are mnong the top three process unit

types. \Vhile connectors, and block valves in sales units have relatively low

average elnission rates, open-ended line in sales unit registered the highest

average elnission ratemnong all process units. This resulted from the

combination of low overall cOlnponent counts of open-ended lines in sale unit

and one single big leaker identified in this category.

• COlnponents tend to have greater average emissions where subjected to ,

frequent thermal cycling, vibrations, or cryogenic service (see figures 16-18).

• All other parameters had little or no 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. '

32
Figure 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 NGL
Figure 17Average THe Emissions For Block Valves 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

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

0.9

0.8 4-

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 Block Valves By Process Unit

n07

0.06

0.05

'-'

§ 0.04 I .~

0.03 CV'

0.02 " t r\9

0.01

Process Thit

35
Additional trends on the age of afacility, sweet/sour raw gas stream, and the

potential ofilnplementing a process-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 against years ofservice for the surveyed

facilities. Facilities with longer than 30 years of service have higher methane

fugitive elnission per pnit throughput 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 longer than 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 sour raw gas

have significantly higher methane elnission per unit gas throughput and higher

leak frequency as '\lell when cOlnpared with facilities with sweet raw gas input.

As mentioned earlier, due to the limited number of surveyed facilities (3 with

sweet and 2 with sour raw gas), the significance ofsour versus sweet process

plants can not be concluded with statistical significance.

36
Figure 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 gas type

In Figure 21, fugitive Inethane elnissions are shown againstthe process units.

Compressor related 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 of methane emissions contributed by .

these two processes and related components warrants instituting a targeted DI&M

program.

37
Figure 23 Methane Emissions Percentage by Process Units

Inlet Sei:>aration· Sales

1% 1%

Mole Sie\e . \ . 5% -------.:-.

4.3.3 Leak Frequencies

D3methanizer

0%

Compressor

92%

Others

1%

Fugit~ve equipment leaks are generally considered to be well controlled when the

leak frequency for each cQInponent type .(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 leak prone cOlnponents.

Conlpressor seals, orifice nleters, control valves, and open ended lines constitute

greater than 70% ofthe leak frequency. Figu~e 23 further illustrates the

contribution of each component type to total THC emissions.

38
Table 5 Number ofComponents And LeakFrequency At Each>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

Leak Frequency % 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 7,692 i I> 495 1 124 I 320 57

NUIllberofLeakerl916 I 406<1 51 10 I 1

39
4.4 Tank Emissions

Ofthe five sites surveyed, three contains leaky tanks that were measured during the site

surveys. Thief hatches were found to be leaking and' subsequently the volume flow was

measured. The average value of gas loss is $906,296 per year per site (see Table 6).

Gas Plant 1 37,801 2,670;645

Gas Plant 2 183 3,429

Gas Plant 3 1,320 44,813

Gas Plant 4 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 ofthe 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 and the changes in fugitive emissions

between the Phase I and Phase II plant surveys.

4.5.1. Overall Plant

Figure 22 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 source following changes at the site were very different.

The changes in the average THC elnission rate for each cOlnponent type are

contrasted in Figure 23.

40
Figure 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 process units in Phase 1. In Figure 24, the total THe emissions

for these two sets of process units were compared. The THe emissions reduced

by an estilnate of 80% from Phase I (decomll1issioned units) to Phase II (new

units). The average elnission rates per component between Phase I and II are

cOlnpared and are shown 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

~--:'-~~~---l0 Open-ended Une

~"-'--~~~":';"""';'=.,-j0 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 Block Val'S

line

Component type

The results ofthis cOll1parison tend to suggest that the 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

42
DI&M progrmn may be attributed to a nUlnber offactors including: excessive

durationbetweensurveys, -inadequate-fellow -up to--maintenance recommendations

and insufficient docunlentation ofInaiJitenance activities. The 5 year time frame

between these two surveys exceeds the estimated mean repair life for most

cornponents. This.makes it difficult to assess the effectiveness of any repairs

nlade in response to the Phase I"survey because the leaks are likely to have

reoccurred; Increasing the frequency of leak surveys to annually or bi-annually

would allow fora better assessment ofthe effectiveness of maintenance 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 either repairing the leak or reevaluating the economics to justify no action.

Any maintenance performed in response to the survey should be adequately

documented so the success ofthe repair can be addressed during subsequent site

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 if all control opportunities with positive net

cost ora positive payback are iJnplemented (see Figure 26). This would result in

corresponding reductions of 97% in fugitive methane en1issions, 97% in fugitive GHG

emissions, mid 980/0 in fugitive NMHC elnissions in the first year alone. Moreover, Inany

ofthe control options have n1ulti-year life expectancies resulting in significant elnission

reductions in subsequent years as well.

4.6.1 Cost Curve for Reduction of GHG Emissions

To further evaluate the control of natural gas losses as a means ofreducing GHG

elnissions, it is usefulto express the results in terms of a cost curve. Figure 27

presents the net annualized cost curve for implementation ofthe various

opportunities identified at the five gas plants. The net cost of each target control

oppOliunity is calculated as the equalized annual implementation cost over the life

ofthe project (i.e., the net present cost ofthe opportunity expressed as an

equivalent series of equal annual payments over the life ofthe project) divided by

the resulting average annual CO2-equivalent emission reduction.

Figure 27 shows that the incremental costper tonne 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 over the abscissa axis (i.e., the axis. of

43
cUlnulativeC02E GHG elnission reduction) is the amount ofC02E emission

reduction that could be achieved if only opportunities with a zero cost or a

positive payback are iInplenlented (i.e.; 103,363 tonnesC02E reduction per year).

This reduction amounts to 17% oftotal estimated GHG emissions frotn the five

gas plants.

If a value is assigned to GHG elnission reduction credits, then companies may

choose to pursue opportunities even fUliher out on the cost curve. The shape of

the cost curve shows that there are a few very attractive control opportunities, a \

large number of moderate control opportunities, and eventually a point of

diminishing returns.

44
Figure 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 of 1 Year or Less

On a purely financial basis, opportunities to reduce natural gas losses must

cOlnpete against other investlnent opportunities to receive funding. A common

paraJneter used to evaluate opportunities is either the effective rate ofreturn on

the investlnent or the payback period. To justify equipment upgrades or process

enhancelnents, companies often look for a payback period of 1 year or less.

Accordingly, it is useful to consider only opportunities to reduce natural gas

losses that have a payback period of 1 year or less.

If only these control opportunities are 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

aJnount to 97% as well.

The 10 greatest.individual control opportunities in the I-year payback category

are listed in Table 7. Collectively, they account for 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 four plants surveyed

in the first Phase. The plants chosen for this study varied 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 that the data collected represents an average for the natural gas processing

industry. A comparison was conducted between the traditional leak detection methods

and an optical passive infrared can1era was conducted at all sites.

The sources with the greatest natural 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 associated identification and control costs. In addition, actual economic

opportunities depend on the natural gas value, and will therefore vary with fluctuations in

the natural gas lnarket price. Nonetheless, it is clear frOln the available data that

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 leak rates based on cOlnbined data froln the five test sites suggest that

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 relief valves,

• regulators,

• flange connections,

• crankcase vents,

• compressor seals, and

• con1pressor valve steIns and valve caps.

Additionally, cOlnponents operating in thermal 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

suggestthat process-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 of a full facility DJ&M program cost.

47
5.2 Recommendations for Further Work

Specific recommendations are:

• The amount and composition of emissions 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, should be evaluated.

• There are a wide varietY'of available technologies, as well as design and operating

practices that would help co~panies ,cost-effectively reduce natural gas losses;

however, these technologies and practices are under-utilized. One such example is

the application offlow sensors, which can be installed on compressor seal vents at

a relatively low cost. Flow sensors provide real-time excessive leakage detection.

They may also be applied to crankcase and other vents. Only one ofthe five sites

had installed seal vent flow sensors, and the operators did not monitor the sensors

"readings. Additionally, emergency flare systems are not normally equipped with

flow meters, so in-leakage and excessive purge gas consumption often go '

unnoticed until natural gas losses produce a noticeably larger flame. Historically,

meters were not installed because conventional obstruction meters do not provide

reliable readings over the 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 past valve seats into flare and vent

systems.

• It is recOlnmended that a best practices document be developed to disseminate and

encourage the cOlnpilation and use of cost-effective emissions reduction practices.

The document should' also provide infonnation required by companies to develop

site-specific programs for reducing their Inethane 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 cost data for

evaluating control options, recommended monitoring frequencies, and typical

repairs life expectance by source type and service category).

• Analysis ofthe Phase I and Phase II results to detennine the relative costeffectiveness of a facility wideDI&Mprogram and a process-unit-targeted DI&M

program focused on components in vibration (i.e. compressor) or heat-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, at a 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 include an age-based arid/or

gas-type-based DI&M program that would also reduce the cost ofDI&M program.

48
-Use oftheconibustion equipment and ·c6mpressor performance tests (new tests

implemen·ted in Phase·2) in future surveys. These tests, when implementeq in the

surveyed faCilities, contributed significantly to thelTIethane and overall GHG

emissions inventories.

- It A follow up progrmTI to evaluate the impact of monitoring frequency on gas

processing facilities DI&M programs·cost effectiveness.

49
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System for Measuring Emissions from Leaking ProcesS Components. Presented at the

1994 International Workshop on Environmental Impacts ofNatural Gas Losses, Prague,

Czech Republic. .

Gas Processors Suppliers Association Engineering Data Book Volume 1, FigureI3~14.1

11th edition, 1998.

Hanlon, P.C., Compressor Handbook, McGraw-Hill, New York, 2001.

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IPCC. 1996. Climate Change 1995: The Science of Climate Change. Cambridge

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Loti, B., T. Howard and M. Webb. 1995. New Techniques Developed for Measuring

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Picard, D.J., Smith M., Ross, B. 2002. Identification and Evaluation of Opportunities to

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Air and Waste Management Association, v42 n6.pp. 333-340.

I I

U.S. EPA (Environmental Protection Agency). 1995. Protocol for Equipment Leak

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Springfield VA. Publication No. EPA-600/R-96-080h.

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(www.epa.gov/ttn/emc/promgate.html)

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