BEST PRACTICES TO AVOID LNG

FUELING STATION VENTING LOSSES

Charles A. Powars

June 25, 2010

Prepared for:

Brookhaven National Laboratory

P.O. Box 5000

Upton, NY 11973-5000

Contract No. 157688

Prepared by:

St. Croix Research

5535 Fern Dr.

San Jose, CA 95124-6311

S . Croix Research

TABLE OF CONTENTS

Section Page

1 Introduction 1

1.1 Objective 1

1.2 The Magnitude of the Venting Problem 3

1.3 Issues and Challenges 4

1.4 Information Sources, LNG Quantity Units, and Report Organization 6

1.4.1 Prior Work 6

1.4.2 Information Sources and Citations 6

1.4.3 Patents and Commercial Products 6

1.4.4 LNG Quantity Units 6

1.4.5 Report Organization 7

2 LNG Infrastructure Requirements Summary 9

2.1 Overview 9

2.2 LNG Saturation, Properties, and Weathering 9

2.3 LNG Tank Basic Characteristics 11

2.4 Natural Gas Engine Fuel Pressure Requirements 14

2.5 LNG Vehicle Fuel System Design Options 14

2.6 LNG Tank Trucks 18

2.7 Station Utilization 19

2.8 Temporary and Mobile LNG Fueling Facilities 20

2.9 Weights and Measures Certification 21

2.10 Applicable Codes and Standards 22

3 LNG and LCNG Fueling Station Design and Operation Effects on Venting 23

3.1 Overview 23

3.2 Tank-Truck-to-Station Transfer 23

3.2.1 Pressure Transfer Offloading 23

3.2.2 Offloading Using Dedicated Pump 25

3.2.3 Offloading Using Dispensing Pump 28

3.3 LNG and LCNG Station Design and Operation 28

3.3.1 Station Sizing 30

3.3.2 Dispensing Pump Options 31

3.3.3 LNG Fuel “Conditioning” Options 33

3.3.4 Fueling Stations Without LNG “Conditioning” Equipment 35
3.3.5 Stations Capable of Refueling All Types of LNG Vehicles 36

3.3.6 LNG Fuel Dispenser Cool-Down Options 38

3.3.7 Station LNG Storage Tank Pressure Management 38

3.3.8 LCNG Fueling stations 39

3.4 LNG Vehicle Operations 41

4 Options for Recovering Vapor Generated at LNG Fueling Stations 45

4.1 Overview 45

4.2 Reliquefaction of Boil-Off Vapor 46

4.3 Utilization of Boil-Off Vapor for On-the-Fly Conditioning 47

4.4 Flaring of Boil-Off Vapor 48

4.5 Sell Boil-Off Vapor to Local Natural Gas Utility 49

4.6 Utilize Boil-Off Vapor to Supply Facility Natural Gas Requirements 49

4.7 Use Boil-Off Vapor to Generate Electric Power to be Sold to Local

Electric Utility 50

4.8 Use Boil-Off Vapor to Generate Electric Power for On-Site Use 50

4.9 Compress Boil-Off Vapor for Use for CNG Vehicle Fueling 51

5 Emissions Implications of LNG Vapor Atmospheric Venting 53

5.1 Overview 53

5.2 Greenhouse Gas (GHG) Emissions 53

5.3 Criteria Pollutant Emissions 55

6 Conclusions and Recommendations 57

6.1 Conclusions 57

6.2 Best Practices Recommendations 57

6.3 Research and Development Recommendations 60

References 63

Appendix A – LNG Tank Pressure, Temperature, Ullage Fraction,

Heat Leak, Hold Time, and Venting Rate Relationships A-1

Appendix B – Methane Phase Diagram B-1
1

Section 1

INTRODUCTION

1.1 Objective

The objective of this document is to recommend liquefied natural gas (LNG) fueling

station design and operation best practices to avoid or minimize LNG vapor venting.

Atmospheric venting of natural gas vapor is undesirable because it negatively affects

economics, increases greenhouse gas (GHG) emissions, and creates a safety hazard in

some situations.

Figure 1 is a highly simplified illustration of some potential causes of vapor venting

associated with LNG fueling station operations. Tank truck delivery of LNG to a fueling

station can result in venting from the station and/or from the tank truck itself. In some

circumstances, LNG vehicle refueling involves processes that increase the likelihood

that vapor will need to be vented from the station or vehicle. Therefore, this document

considers potential LNG vapor generation and venting associated with three closely

related aspects of the overall LNG transportation fuel infrastructure:

 Tank truck delivery of LNG to a fueling station

 LNG fueling station operation

 LNG vehicle operation and refueling

Figure 2 shows examples of LNG vapor venting from each of these infrastructure

elements. The white plume usually associated with LNG vapor venting is actually

atmospheric water vapor, which is condensed as it is entrained and cooled by the much

colder LNG vapor. The extent of this plume depends strongly on the ambient humidity

and temperature, and so the magnitude of LNG vapor flow cannot be judged from the

plume size.

This document also addresses best practices to avoid venting from LCNG fueling

stations. LCNG stations receive and store LNG, which is pumped to a high pressure,

vaporized, and dispensed to refuel compressed natural gas (CNG) vehicles. Some

LCNG stations are equipped to refuel both LNG and CNG vehicles.

The LNG fueling station illustrated in Figure 1 is but one example configuration. There

are in fact many different LNG and LCNG station design options, the details of which

affect potential venting. There are also various types of LNG vehicle tanks and fuel

systems, which also affect venting. Finally, there are optional LNG tank truck offloading

connections and procedures. These options and their effects on vapor generation and

venting are discussed in this report.
2

Figure 1. Highly simplified illustration of potential LNG venting losses associated with LNG fueling station operation

including tank truck delivery and vehicle refueling.

Blowdown of truck following

pressure build to transfer LNG

to station (particularly if station

has no offloading pump)

Use of back pressure regulator to

maintain convenient saturation

pressure in storage tank

Storage tank PRD opens (e.g., due to

inadequate station utilization or too

much vapor injected into storage tank)

Blowdown of storage tank (e.g.,

to facilitate delivery truck-tostation LNG transfer)

Vehicle tank PRD opens

(e.g., due to infrequent truck

use, reduced hold time

associated with high Sat. P

refueling, tank soft vacuum)
3

Figure 2. LNG vapor venting from a fueling station (A), tank truck (B), and vehicle (C)

1.2 The Magnitude of the Venting Problem

The societal benefits of using natural gas as a transportation fuel are broadly

recognized and well documented. LNG is used primarily as a fuel for heavy-duty

vehicles, which would otherwise consume diesel fuel. This natural gas fuel application is

especially beneficial with respect to criteria pollutants such as NOx and particulate

matter, because it is more straightforward to minimize these emissions from natural gas

engines than from diesel engines. These LNG vehicles also produce less GHG

emissions, primarily because the carbon content of natural gas is much less than that of

diesel fuel.

The total emissions (especially total GHG emissions) associated with a particular

transportation fuel are often compared on a “well-to-wheels” basis. In this context, any

LNG fueling station vapor venting contributes to the well-to-wheels GHG emissions of

LNG-fueled vehicles, and this contribution is exacerbated by the fact that the CO2 GHG

equivalence of methane is approximately 25. The GHG emissions implications of LNG

fueling station vapor venting is discussed in more quantitative detail in Section 5.

While the GHG implications of LNG fueling station vapor venting are important to

consider as use of LNG as a transportation fuel increases, the fact is that this source of

GHG emissions is relatively insignificant at the present time. This is demonstrated by

the comparison summarized in Table 1, which was provided by Gladstein, Neandross

and Associates (Reference 1). This very approximate estimate indicates that the

A B C Image courtesy Jerry Wiens
4

methane currently vented from LNG fueling station and vehicle operations in California

are at least two orders-of-magnitude less than the methane released from dairy cows in

California.

Cows in California* 2,264,000 cows

Annual methane emissions per cow (pounds)* 350 Lb/cow

Annual metric tons of methane emitted by cows in CA 360,000 MT

Approximate daily LNG fuel demand in CA from the LNG vehicle fuel market 160,000 gal

Approximate annual LNG fuel demand in CA from the LNG vehicle fuel market 58,400,000 gal

Approximate annual LNG fuel demand in CA from the LNG vehicle fuel market 93,500 MT

Assumed LNG vehicle fuel market maximum venting loss percentage 1.0%

Rough estimate of venting losses associated with the LNG vehicle operations in CA 935 MT

Ratio of venting from CA LNG vehicle operations to methane emissions from cows 0.26%

* Data from Reference 2

Table 1. The current contribution of methane venting from LNG vehicle refueling and

operation is relatively small, as indicated by this very approximate comparison

provided by Gladstein, Neandross and Associates (Reference 1).

1.3 Issues and Challenges

Venting from LNG vehicles and fueling stations is due primarily to the simple fact that

LNG must be maintained at cryogenic temperatures (approximately -260°F to -170°F,

depending on pressure and composition) in order to stay in the liquid phase. For this

reason, LNG fueling stations utilize highly insulated storage tanks and plumbing

systems to minimize heat leaks that may eventually cause venting. However, even

when good cryogenic design practices are followed, certain situations tend to increase

the potential for vapor venting from LNG fueling stations.

The overarching issue is simply station utilization. If a substantial number of LNG

vehicles are refueled at the station and these vehicles have typical heavy-duty vehicle

fuel consumption rates, then LNG tank truck deliveries will be reasonably frequent.

Regular additions of substantial quantities of colder (i.e., lower saturation pressure1)

LNG ensures that the storage tank pressure remains well below the pressure relief

device (PRD) pressure, and venting does not occur. Moreover, if the LNG vehicles’ fuel

consumption is significant, vehicle fuel tank pressure increases are not large, and there

is seldom any need to transfer vapor from the vehicle to the station. On the other hand,

if the utilization is low or sporadic, and/or the supported LNG vehicles consume very

little fuel, the potential for vapor venting is much higher. For this reason, LNG is

sometimes referred to as a “use it or lose it” fuel.

1 Graphs showing the quantitative relations among LNG saturation pressure, temperature, density, and

other properties are contained in Appendix B. The analytical methods and assumptions employed to

generate these graphs are explained in Appendix A.
5

In addition to utilization, certain other issues and situations tend to exacerbate the

potential for venting from LNG fueling stations and vehicles. First and foremost among

these is the fact that most current heavy-duty natural gas vehicles have spark ignition

natural gas (SING) engines, which require fuel supply pressures near 100 psig and

have no on-board fuel pump (fuel supply pressure requirements are discussed in more

detail in section 2.3). The LNG delivered by tank trucks typically has a saturation

pressure in the 10 to 30 psig range, and heat transfer during the truck-to-station transfer

process increases this saturation pressure somewhat. The saturation pressure in the

station storage tank immediately after a delivery depends on the delivered LNG

saturation pressure, the state of the residual LNG in the storage tank prior to the

delivery, and the delivered-to-residual LNG mixture ratio. In most circumstances, this

pressure is substantially less than 100 psig. If LNG vehicles with SING engines are

refueled with this LNG, they will “run out of gas” because the pressure in the vehicle fuel

tank is less than the required engine fuel supply pressure.

The most common current approach for addressing this problem is to “condition” the

LNG in the station storage tank to increase its saturation pressure so that it exceeds the

engine fuel supply pressure requirement after it is dispensed into vehicle fuel tanks.

This conditioning is accomplished by adding heat to the freshly delivered LNG by

circulating it through a heat exchanger (which is sometimes called a vaporizer) located

at the station. Because this reduces the difference between the saturation pressure of

the LNG in the station storage tank and that tank’s pressure relief device (PRD) opening

pressure, the station tank’s time-to-vent is decreased, which exacerbates the station

venting potential. The LNG conditioning process is discussed in more detail in Section

3.3.

Besides increasing the station cost and venting potential, this conditioning practice has

another liability. Not all heavy-duty natural gas vehicle engines require LNG fuel tank

pressures near 100 psig. In particular, the Westport ISX-G high-pressure direct injection

(HPDI) engines have LNG fuel systems that include a pump (see Sections 2.3 and 2.4).

It is disadvantageous to refuel these vehicles with high saturation pressure LNG for two

reasons: First, this decreases the quantity of LNG that the fuel tank can hold, because

the higher-pressure LNG has a lower density (Appendix B). Second, this shortens the

fuel tank time-to-vent, because the pressure rise to the PRD pressure is less. Therefore,

the conditioned LNG currently dispensed by most LNG stations is not optimally suited

for vehicles with HPDI engines. As will be discussed in Section 3.3, a few stations are

equipped to dispense two “grades” of LNG in order to optimally refuel all types of LNG

vehicles.

LNG fueling station venting is also affected by other aspects of the LNG vehicle fuel

system design as well as the vehicle operating cycle. For example, if some combination

of these factors cause the vehicle LNG fuel tank pressure to be quite high when it

enters the station for refueling, vapor may have to be transferred from the vehicle fuel

tank to the station before LNG can be dispensed into the vehicle fuel tank. Specific

fueling station and vehicle conditions that may necessitate vapor return are discussed in

Sections 2 and 3.
6

Finally, another issue that affects potential vapor venting is LNG fueling station

economics. Simply put, LNG stations can incorporate well-understood design features

and equipment selections that minimize or eliminate vapor generation and venting, but

stations without these particular design features and equipment selections may be less

expensive. This tradeoff is sometimes an awkward issue for projects involving a very

small number of LNG vehicles, particularly if a dedicated station with cost proportional

to total vehicle cost is anticipated. The likelihood of vapor venting may be greater in

these situations due to low station utilization as well as station budget limitations.

1.4 Information Sources, LNG Quantity Units, and Report Organization

1.4.1 Prior Work

Many other studies have addressed aspects of LNG vehicle and fueling station vapor

generation and venting, and this report draws heavily from that prior work. References 3

through 27 are examples of prior reports, articles, and presentations that contain

material related to the subject of this report.

1.4.2 Information Sources and Citations

The information in this report is based on prior work (as noted in section 1.4.1),

analyses consistent with the principles summarized in Appendix A, observations of LNG

deliveries and refueling operations at dozens of LNG fueling stations, and interviews

with LNG station operators, designers, and equipment suppliers. With regard to these

interviews, candid information was usually provided based on the anticipation of

confidentiality, and so these information sources are not cited by name in this report.

Photographs used in this report are credited with regard to their source. Photographs

with no credit noted were taken by and are the property of the report author.

1.4.3 Patents and Commercial Products

Many patents describe inventions involving LNG vehicles and fueling stations with

features intended to reduce or eliminate vapor generation and venting losses. Specific

patents are not cited or discussed in this report because to do so might be misconstrued

as an opinion regarding the patent validity, and this would also be unfair to patents that

were not cited. Similarly, any reference to specific companies or products is for

illustration purposes only and is not intended to be an endorsement or recommendation.

1.4.4 LNG Quantity Units

Liquid transportation fuels such as gasoline and diesel fuel are traditionally quantified in

terms of gallons (or liters in most non-US countries), which is a volume measurement.

For cryogenic liquids such as LNG, which are usually transported, stored, and

dispensed at or near saturation, the liquid density depends strongly on temperature and

pressure, and so the mass in a gallon at one condition may be substantially different

from the mass in a gallon at another condition. For example, for high-purity LNG, a
7

gallon at 20 psig weighs 3.38 Lbm, but a gallon at 120 psig weighs 3.03 Lbm (i.e.,10.4%

less) 2.

For this reason, LNG supply contracts and pricing is usually based on fuel mass rather

than volume. However, most people have a strong preference to discuss LNG vehicle

fuel quantities in terms of gallons. An approach that minimizes the ambiguity of this unit

of measurement is to define a “LNG gallon” as the mass of fuel in one gallon of allmethane LNG saturated at one atmosphere of absolute pressure (14.7 psia), which is

3.53 Lbm. This convention is used in this report so that, regardless of pressure and

temperature, one “LNG gallon” means 3.53 pounds of LNG.

1.4.5 Report Organization

Section 2 summarizes various technical aspects of the LNG vehicle fueling

infrastructure that affect vapor generation and potential venting. With this background

established, Section 3 discusses the effects of different design and operation

alternatives on venting associated with LNG tank truck deliveries, refueling station

operations, and vehicle fuel system types. Options for avoiding venting by recovering

and productively using LNG vapor are reviewed in Section 4. Section 5 discusses the

emissions implications, both GHG and criteria pollutants, of LNG vapor atmospheric

venting. Best practices for avoiding LNG vapor venting are summarized in Section 6,

which also includes some recommendations regarding new technology directions.

This report includes two appendices. Appendix A summarizes the basic equations and

contains some useful graphs pertaining to the LNG storage tank heat leaks, pressure

and temperature rise rates, ullage fractions, hold times, and venting rates. For

reference, Appendix B contains graphs of selected thermodynamic properties (pressure,

temperature, density, enthalpy) of methane at and near the liquid-vapor mixture region

of the phase diagram.

2 Graphs of LNG density are in Appendix B.
8
9

Section 2

LNG INFRASTRUCTURE REQUIREMENTS SUMMARY

2.1 Overview

Vapor generation and potential venting from LNG fueling stations depends on various

technical issues and requirements associated with the overall LNG transportation fuel

infrastructure. These are briefly reviewed in the following subsections in order to provide

a basis for subsequent discussions of design options and operating practices that

prevent or minimize vapor venting.

2.2 LNG Saturation, Properties, and Weathering

LNG fueling station storage tanks and vehicle tanks contain a mixture of liquid and

vapor. The space occupied by the vapor is called the ullage. When the liquid and vapor

phases are in equilibrium (i.e., at the same pressure and temperature), the mixture is

said to be saturated. Although both phases have the same pressure and temperature,

the liquid is denser (e.g., pounds per cubic foot) than the vapor, and the vapor has a

higher internal energy (e.g., Btu per pound) than the liquid. As the pressure and

temperature increases, these differences between the phases decrease. At the critical

pressure (673 psia for methane) and temperature (-117°F for methane), the liquid and

vapor phases have the same density (10.1 Lbm/ft3for methane). At higher pressures

and temperatures, there is no distinction between the liquid and vapor phases, and the

fluid is said to be supercritical.

LNG usually consists of a very high percentage of methane, a much smaller percentage

of heavier hydrocarbons (e.g., ethane, propane, butane), and very small quantities of

other constituents (e.g., nitrogen). Because of differences in their vapor pressures, the

heavier hydrocarbon constituents are more concentrated in the liquid phase than the

vapor phase. Thus, when vapor is vented, the remaining LNG becomes more “enriched”

with respect to these heavier hydrocarbons. This process is referred to as “weathering.”

In rare cases (mainly for older heavy-duty natural gas engines that don’t have closedloop electronic controls), the fuel composition changes associated with weathering can

result in engine operation problems, and so weathering can be regarded as another

undesirable consequence of venting. LNG weathering, natural gas composition effects

on engine performance, and issues associated with government agency fuel

composition specifications are discussed in more detail in various of the listed

references.

In this document as in many other similar reports, LNG is usually assumed to be 100%

methane with regard to physical properties. There are two reasons for this: First, most

LNG currently sold as a transportation fuel is contractually required to be high-purity
10

(e.g., 99%) methane3, Second, if constituents other than methane are included,

calculation of LNG properties involves more complex multi-component, multi-phase

analyses, and the results cannot be shown in simple-to-understand graphs.

For reference, Figure 3 shows the temperature-pressure relation for saturated LNG that

is 100% methane. Methane is a superheated vapor at temperatures above the

saturation line and a subcooled (or compressed) liquid at temperatures below the

saturation line. Figure 4 shows the density variation with pressure of saturated methane

vapor and liquid. Appendix B contains more details regarding LNG properties.

-350

-300

-250

-200

-150

-100

-50

0

-100 0 100 200 300 400 500 600 700

Pressure ( psig )

T

e

m

p

erature (

o

F )

VAPOR REGION

LIQUID REGION

Saturation Line

Atmospheric

pressure

Critical

point

Figure 3. The temperature vs. pressure curve for saturated liquid and vapor methane.

3

In many cases, this high-purity LNG requirement appears to be based more on legacy contract

language than actual natural gas engine fuel composition specifications and realistic weathering

concerns. Some experts are of the opinion that relaxing unnecessarily rigid LNG contract composition

specifications would enable a slight LNG transportation fuel cost savings.
11

0

100

200

300

400

500

600

700

800

900

1,000

0 5 10 15 20 25 30

Density ( Lbm / ft3)

Pre

s

s

ure ( p

sig )

LIQUID

REGION

LIQUID + VAPOR

REGION

VAPOR

REGION

Saturation Line

SUPERCRITICAL

REGION Example

isotherm

(-180°F)

Figure 4. The density-pressure relation for saturated liquid and vapor methane.

2.3 LNG Tank Basic Characteristics

Like other cryogenic liquids, LNG must be stored in well-insulated containers in order to

minimize heat transfer from the environment, the rate of pressure and temperature

increase, the likelihood of venting, and the vent gas flow rate if venting does occur. LNG

fueling station storage tanks, LNG tank truck tanks, and LNG vehicle fuel tanks (such as

those shown in Figure 5) are all vacuum jacketed. Other design details and construction

features are somewhat different.

The vacuum jacket, which is an evacuated space between the inner tank and outer

shell, minimizes convection heat transfer. The system that supports the inner tank within

the outer shell as well as the plumbing to the inner tank is designed to minimize

conduction heat transfer. For LNG vehicle fuel tanks, multi-layer insulation (MLI) is

placed between the inner and outer tanks to minimize radiation heat transfer. MLI

consists of layers of highly reflective (i.e., low emissivity) foil-like material separated by

a spacer material such as silk or nylon netting. Most larger cryogenic vessels used to

store LNG at fueling stations or on tank-truck trailers use highly reflective granular

materials such as Perlite in the vacuum jacket. Details regarding cryogenic vessel

insulation systems and other design features are available in cryogenic textbooks such

as Reference 28. More information specific to LNG fueling station and vehicle fuel tanks

is contained in References 7, 11, 13, 16, 19, 20, and 25.
12

Figure 5. LNG fueling station tanks (A), vehicle fuel tanks (B), and tank-truck tanks (C)

are vacuum jacketed to minimize heat leaks.

Safety, codes, and common sense require LNG tanks of all types to be equipped with

multiple pressure relief devices (PRDs). The PRD purpose is to open and relieve the

tank pressure before it reaches a potentially dangerous level (which depends on the

tank construction details such as the inner tank diameter, thickness, and material). For

most currently used LNG vehicle fuel tanks, the first PRD opens at 230 psig. LNG

fueling station tanks are available with various maximum allowable working pressures

(MAWPs), but 175 psig is a common MAWP for these tanks, and the first PRD is

usually set at the MAWP.

The tank heat leak characteristics are usually specified in terms of the normal

evaporation rate (NER) and sometimes the hold time. The NER is the rate of vapor

withdrawal that maintains the tank saturation pressure at a constant level. NER is

usually expressed as a percent per day. In addition to the heat leak rate, the NER

depends on the particular cryogen and the pressure at which the vapor is withdrawn.

Similarly, in addition to the heat leak rate, the hold time depends on the cryogen, the

initial pressure and ullage fraction, and the ending (usually PRD) pressure. These

details are not always specified, and so interpretation of NER and hold time is

somewhat ambiguous in these cases.

The NER, hold time, and heat leak are all interdependent. For a given tank, cryogen, fill

pressure and ullage fraction, and PRD pressure, specification of any one of these

A B Image from Stirling Corp. press release 5/11/08

C
13

enables calculation of the other two (subject to a few assumptions4). For example,

Figure 6 shows the theoretical pressure, vent rate, and ullage fraction history for a 115-

gallon LNG vehicle fuel tank with a 5-day hold time and a 230-psig PRD that is filled

with LNG saturated at 120 psig and no fuel is consumed (e.g., vehicle is not driven). For

this tank and these conditions, the heat leak that results in a 5-day hold time is

approximately 18 Watts. Figure 6 shows that the pressure rises steadily to 230 psig on

day five, at which time the PRD opens and vapor vents at approximately 2.5 equivalent

LNG gallons/day until all the liquid is vaporized by day 39. This analysis is addressed in

more detail in Appendix A, which includes a graph showing that if the same tank is filled

with LNG saturated at 20 psig, the hold time is increased to 13 days.

0

50

100

150

200

250

0 5 10 15 20 25 30 35 40 45

Elapsed Time (days)

Saturation Prassure (psig) &

Ullage (%)

0

1

2

3

4

5

Venting

Rate (LN

G

gallons equivalent / day)

(230 psi PRD)

Pressure

Ullage %

5 days

(brief increase in venting as liquid is exhausted

and tank warms to ambient temperature)

Venting

rate

Figure 6. Hypothetical 115-gallon LNG vehicle fuel tank with 230-psig PRD and 5-day

hold time when filled with 120-psig saturation pressure LNG: pressure rise

rate, venting rate, and ullage fraction variation if vehicle is not driven after

tank filling.

If LNG tank venting must occur, it is much safer (and also more effective) to vent vapor

than liquid. Therefore, good practice as well as most codes require that, when LNG

tanks are filled, adequate ullage should remain so that there is still a vapor space (i.e.,

ullage > 0) if and when the saturation pressure increases to the PRD opening pressure.

If the ullage fraction decreases to zero before the PRD opens, the tank is said to be

liquid full, which is a situation that should be avoided. Any heat leak subsequent to a

liquid full condition produces an extremely rapid pressure rise rate.

4

The main assumption is that the tank contents are at a uniform pressure and temperature, which is

usually the case for smaller tanks but is less applicable for large stationary tanks in which stratification

may occur.
14

For LNG in a closed container with no withdrawal, the ullage fraction decreases as the

saturation pressure and temperature increase for most (but not all) conditions. The

ullage fraction that should be provided when a tank is filled can be calculated from

LNG’s properties and mass and energy conservation equations. For the example LNG

tank considered in Figure 6, a 9% ullage is needed if it is filled with 120-psig saturation

pressure LNG (although a minimum of 10% is required by the applicable SAE

Recommended Practice, Reference 29), and a 18% ullage is needed if it is filled with

20-psig saturation pressure LNG. Most LNG vehicle fuel tanks have an automatic

ullage-control feature to ensure that the tank can’t be over-filled with liquid.

Appendix A contains considerable more detail regarding, and useful graphs illustrating,

the relationships among LNG tank heat leak rate, pressure, temperature, ullage fraction,

hold time, and venting rate.

2.4 Natural Gas Engine Fuel Pressure Requirements

A factor that affects LNG fueling station designs and potential venting is the fuel supply

pressures required by various natural gas engines. Because essentially all current LNGfueled natural gas vehicles are heavy-duty vehicles, consideration here is confined to

heavy-duty natural gas engines. Table 2 lists some relevant heavy-duty natural gas

engines, their manufacturer-specified minimum engine fuel supply pressure

requirement, the manufacturers’ estimate of the pressure drop from the LNG fuel tank to

the engine5(if available), the consequent LNG fuel tank pressure requirement (if there is

no pump), and the information source.

2.5 LNG Vehicle Fuel System Design Options

A variety of on-vehicle LNG fuel system design strategies are described in Reference

19. Some of these have been demonstrated and a few have been used on significant

numbers of light-duty vehicles in the 1960s through 1980s and heavy-duty vehicles

(primarily in the 1990s through the present). However, nearly all currently operating

heavy-duty LNG vehicles employ one of two types of LNG fuel systems:

A. Most LNG vehicles have SING engines (Table 2) that require fuel supply pressures

near 100 psig. These vehicles generally employ LNG fuel systems that have no

pump or other pressure-building features. They require the saturation pressure of

the LNG in the fuel tank to exceed the required engine fuel supply pressure plus

the maximum anticipated pressure drop from the tank to the engine. Fueling

stations supporting these vehicles must be capable of dispensing LNG with

saturation pressures approximately6equal to those listed in column 5 of Table 2.

5

The pressure drop from the LNG fuel tank to the engine is associated with flow through the fuel lines,

vaporizer, valves, and (in some cases) regulators and/or filters. This pressure drop is highly dependent on

the particular application and operating conditions.

6

The exact dispensed LNG saturation pressure requirement depends on other factors such as heat

transfer associated with the dispensing process and the quantity and state of the LNG in the vehicle tank

at the beginning of refueling.
15

B. LNG vehicles with HPDI engines require an engine fuel supply pressure of at least

4,000 psig. An on-vehicle fuel system with an in-tank LNG pump is employed to

provide LNG at this pressure (which is actually a supercritical state, see Figure 4).

At the present time, only one engine of this type is commercially available (the

Westport ISX-G, Reference 30), and the engine manufacturer also provides the

special LNG tank and fuel system required to support the HPDI engine. As will be

discussed subsequently in more detail, vehicles with pump-equipped HPDI

engines can be refueled with LNG at almost any saturation pressure. However, as

summarized in Sections 2.2 and 2.3 and detailed in Appendix A, refueling with

lower saturation pressure LNG will provide a greater mass of fuel in the tank and a

longer hold time.

Natural gas

engine

Remarks (1) Min. engine

fuel supply

pressure

Tank-to-engine

delta-pressure

recommendation

Min. LNG

fuel tank

pressure

Source(s)

CumminsWestport

Inc. (CWI)

ISL-G

Currently

EPA/CARB

certified and

available SING

engine

75 psig 30 to 40 psi 105 to 115

psig

CumminsWestport Tech.

Bulletin

15.11.209,

“Natural Gas

Fuel SystemLNG”

Westport

ISX-G

Currently

EPA/CARB

certified and

available HPDI

engine

N/A (2) N/A (2) N/A (2) Westport

technical

literature

Clean Air

Partners

Caterpillar

C-12

Not currently

EPA/CARB

certified or

available, but still

in use PING

engine

98 psig (3) 128 to 130

psig

Clean Air

Partners C-12

engine

specifications

Other CWI,

DDC,

Deere, and

Mack SING

engines

Most of these are

not currently

EPA/CARB

certified or

available, but

some are still in

use

~60 psig to

~100 psig

(3) ~90 psig to

~140 psig

Manufacturers’

technical

literature and

Refs. 12, 16, 19

Notes:

1. SING = spark ignition natural gas, HPDI = high pressure direct injection, PING = pilot ignition natural gas

2. The ISX-G HPDI engine uses a pump-in-tank LNG fuel system, which has no minimum LNG fuel saturation

pressure requirement

3. The tank-to-engine minimum delta-pressure recommendation for these applications is assumed to be the

same as the CWI ISL-G recommendation

Table 2. Heavy-duty natural gas engine fuel supply pressure requirements.
16

Figures 7 A and B are simplified generic diagrams of previously listed LNG vehicle fuel

systems types A and B. The discussion here focuses on features that may affect

venting. More comprehensive explanations of these systems are available in Reference

19 as well as manufacturers’ literature (e.g., References 31 and 32). Both types of LNG

fuel tanks normally employ a single-line “vapor collapse” top-filling procedure. This

process relies on the fact that, most of the time, the interaction of incoming liquid with

the residual ullage vapor tends to condense much of that vapor to liquid so that the tank

pressure doesn’t increase to the maximum station pump discharge or PRD pressure

during the fill. Occasionally, this doesn’t work, and this is usually because the initial tank

saturation pressure and liquid/vapor ratio is such that, before or during filling, the station

pump discharge pressure (or recirculation valve opening pressure) is inadequate to

dispense LNG into the tank. In these cases, a two-line filling procedure must be used.

The second line is connected to the tank vapor return receptacle shown in Figures 7 A

and B, and vehicle tank ullage vapor is returned to the station before and/or during

filling7. Vapor returned to the fueling station can increase the station venting likelihood,

which will be discussed in Section 3.3. Occasionally, vehicle tank ullage vapor is simply

vented to the atmosphere (by opening the vent valve shown in Figures 7 A and B) in

order to reduce the tank pressure and enable or expedite refueling. This is obviously a

bad practice.

An important feature of the “saturated fuel” type of LNG vehicle fuel system illustrated in

Figure 7 A is the economizer valve and circuit. This circuit enables the tank pressure to

be reduced any time the vehicle is driven. If and when the tank pressure exceeds a setpoint, the economizer valve opens so that the engine draws vapor from the ullage. The

ratio of vapor-to-liquid withdrawal is increased if the liquid line is equipped with a checkvalve that provides a small additional pressure drop. Because energy is being

withdrawn from the tank at a substantial rate when the economizer valve is open, the

saturation pressure of the remaining liquid and vapor decreases. When the pressure

decreases to the economizer valve set point, the valve closes so that only liquid is

withdrawn.

Current versions of the “pumped” type of LNG vehicle fuel system illustrated in Figure 7

B do not have an economizer circuit or equivalent capability to withdraw vapor to supply

fuel to the engine. Studies (References 33 and 34) have demonstrated the feasibility of

pumps that can withdraw liquid-vapor mixtures, but these substantially complicate the

design and increase the cost of the overall system. It can be argued that, because

pumped systems can be refueled with very low saturation pressure LNG (which

provides a greater pressure rise to the PRD pressure), they have less need for an

economizer circuit.

It should be emphasized that there are many other LNG vehicle fuel system design

concepts. The discussion here is focused on the two in common use at this time and

their design features potentially affecting venting.

7

Alternatively, for some LNG fueling station designs, the vapor can be returned to the station through the

filling line before LNG dispensing starts.
17

A. “Saturated fuel” type of LNG vehicle fuel system depends on the LNG saturation

pressure to supply fuel to the engine.

Fuel pickup line (with

optional low ΔP check-valve)

Top fill line

Vacuum jacketed

tank

Primary

PRV

Secondary

PRV

Economizer

regulator/valve

Vapor vent

Refueling

Fuel to vaporizer

and engine

Excess flow

check-valve

Vapor line

B. “Pumped” type of LNG vehicle fuel system.

Vacuum jacketed

tank

Top fill line

Primary

PRV

Secondary

PRV

Vapor vent

Fuel to vaporizer,

accumulator, and

engine

Refueling

Liquid drain line

Pump drive

(e.g., hydraulic)

Vapor line

Cryogenic pump

Figure 7. Simplified generic diagrams of the two types of currently used LNG vehicle

fuel tanks and systems (components such as liquid level sensors and ullage

control features are not shown).
18

2.6 LNG Tank Trucks

LNG is usually delivered to LNG fueling stations in tank trucks. Most LNG tank trucks

are actually tractor-trailers such as the one shown in Figure 8. A Class 8 tractor pulls a

semi-trailer consisting of a vacuum-insulated LNG tank, fluid transfer plumbing, and

related components. LNG semi-trailers typically have a gross capacity of 10,000 to

13,000 gallons. The maximum LNG payload is slightly less due to ullage requirements.

Figure 8. LNG tractor-trailer tank truck.

Most LNG semi-trailers use a pressure-building circuit instead of a pump to offload

LNG. This circuit vaporizes a small quantity of LNG in an ambient heat exchanger

underneath the tank (which is visible in Figure 8) to create a temporary “false head8.”

The pressure-build necessary to transfer LNG to the station storage tank depends on

the station design and the saturation states of the LNG in the station and storage tanks.

As will be discussed in Section 3.2, nearly all currently operating LNG fueling stations

are equipped with LNG tank truck offloading pumps. Usually, this is a dedicated highcapacity pump, but some stations use the same pump for vehicle refueling and tank

truck offloading.

LNG tank semi-trailer design and construction features and operating procedures are

regulated by the U.S. Department of Transportation, which classifies LNG as a

hazardous material. The procedures used to transfer LNG from a tank truck to a fueling

station can affect potential venting from the truck and the station. These procedures are

discussed in Section 3.2.

8

The additional ullage vapor subjects the liquid to a pressure greater than its saturation pressure.

Image courtesy Clean Energy Fuels Corp.
19

2.7 Station Utilization

Station utilization and an appropriate balance of station utilization, station storage

capacity, and LNG delivery schedules are major factors affecting excess vapor

generation and potential venting. Station utilization is usually quantified in terms of

average LNG gallons per day, and it can be estimated as the number of vehicles

refueled at the station times their average fuel consumption rate. It is more

straightforward to avoid venting from stations with a high utilization, but LNG stations

with medium to low utilization can also be designed and operated to avoid atmospheric

venting.

In addition to utilization, various other factors also affect LNG fueling station design,

operation, and potential venting. Many of these factors involve economics. For example,

due to the economics of scale, larger LNG storage tanks are less costly per gallon than

smaller ones. However, station storage tank sizing is often affected by site issues as

well as economics. Most LNG stations have one or more tanks with approximately

15,000 gallon capacities, and some have larger tanks up to approximately 30,000

gallons. It is more cost effective to accept full rather than partial tank truck deliveries,

and this is possible with some flexibility with a 15,000 gallon tank.

Figure 9 shows the predicted storage tank saturation pressure and liquid content

histories for two hypothetical low-utilization LNG stations with 15,000-gallon storage

tanks and 10,000 LNG gallon tank truck deliveries. One station dispenses 1,000 LNG

gallons per day and the other station dispenses 500 LNG gallons per day (e.g., 5

vehicles, each consuming an average of 100 LNG gallons per day). This hypothetical

case assumes that the LNG is conditioned to 120 psig saturation pressure after each

delivery9, and the ullage is adequate to avoid a liquid full condition if no product is

withdrawn. Details pertaining to assumptions such as the tank heat leak and the

dispensing schedule are provided in Appendix A. Figure 9 indicates that the 1,000 LNG

gallon per day consumption case will of course require a 10,000 LNG gallon delivery

every 10 days, at which time the storage tank saturation pressure will have increased to

approximately 142 psig. However, the very-low 500 LNG gallon per day consumption

case is predicted to cause the storage tank saturation pressure to increase to the

assumed 175-psig PRD pressure by day 15, i.e., before the tank is able to accept a

10,000 LNG gallon delivery. Therefore, this hypothetical station would need a smaller

storage tank and more frequent deliveries of less than 10,000 LNG gallons (or some

type of active vapor management) to avoid atmospheric venting.

LNG vehicle project developers and LNG station designers/installers can balance

almost any anticipated current and future station utilization with site conditions and other

requirements to develop design concepts for LNG fueling stations with no atmospheric

venting.

9 Note that, based on the definition of “LNG gallon” in Section 1.4.4, one LNG gallon at 120 psig

saturation pressure occupies a volume larger than one gallon.
20

0

20

40

60

80

100

120

140

160

180

0 2 4 6 8 10 12 14 16 18

Elapsed Time ( days )

S

aturation Pre

s

sure ( p

sig )

0

5,000

10,000

15,000

20,000

25,000

30,000

L

N

G in T

ank ( "L

N

G

g

allons" )

1,000 LNG gal/day dispensed during 4-hr window

500 LNG gal/day dispensed during 2-hr window

(175 psi PRD)

Conditioning

to 120 psig

10,000 gal

added to tank

For this scenario, LNG storage tank

refilled every 10 days, and cycle repeats

For this scenario, LNG

storage tank starts venting

in ~15 days

Figure 9. Effect of LNG fueling station utilization on 15,000-gallon storage tank

saturation pressure and LNG content variation. 1,000 LNG gallon/day

utilization would enable 10,000 LNG gallon tank truck deliveries every 10

days, but 500 LNG gallon/day utilization would result in PRD venting before

storage tank was empty enough to receive a 10,000 LNG gallon delivery. See

Appendix A for assumption details.

2.8 Temporary and Mobile LNG Fueling Facilities

The primary focus of this report is on permanent LNG vehicle fueling stations. However,

it is important to acknowledge the use of temporary and mobile LNG fueling facilities

and the fact that they can involve special vapor management and venting issues.

Specific examples of these facilities include:

 QRS®– A truck-transportable skid-mounted temporary LNG fueling station

consisting of a 6,000-gallon vacuum-jacketed tank, sump-submerged LNG pump,

and associated conditioning, metering, and dispensing equipment. Developed by

MVE, which was subsequently acquired by Chart Industries.

 TVAC®– A 5,300-gallon gross capacity vacuum-jacketed cryogenic tank in an

easily transported intermodal container frame. Developed by Cryenco, which was

subsequently acquired by Chart Industries. Frequently used as a temporary station
21

LNG storage tank in combination with a Cryenco-developed LNG pump, metering,

and dispensing skid.

 ERVING – A trailer-mounted mobile LNG and LCNG fueling facility consisting of a

TVAC tank (see above), LNG pump, vaporizer, CNG buffer vessel, controls,

dispensing hoses, Etc. ERVING units assembled by Jack B. Kelley. Inc. (using

mostly Cryenco equipment) were used to refuel LNG and CNG buses at the 1997

Atlanta Olympics and various other NGV projects.

 ORCA®– A Chart Industries trailer or truck chassis-mounted mobile LNG fueling

facility consisting of a 3,500-gallon vacuum-jacketed tank, submerged pump, fuelconditioning vaporizer, flow meter, dispenser, and other equipment needed to

refuel LNG vehicles.

Venting is sometimes more frequent from temporary and mobile LNG fueling facilities10,

primarily because they are often employed to support LNG vehicle start-up and

demonstration projects with low utilization, sporadic refueling schedules, and extended

periods with no vehicle refuelings. Venting can be particularly severe from temporary or

mobile LNG fueling facilities that employ pumps that must be cooled in order to prime

(see Section 3.3 for more detailed discussion of LNG pumps).

In addition to the above temporary and mobile LNG fueling facility examples, LNG tank

trucks have occasionally been jury-rigged to enable LNG vehicles to be refueled directly

from the tank truck. The code compliance of this practice is arguable, and it is usually

accompanied by substantial vapor venting.

2.9 Weights and Measures Certification

Weights and measures certification of LNG fueling stations involves many technical

issues, and only those issues related to vapor management and venting are discussed

here.

The main factor connecting accurate and certifiable LNG vehicle fuel metering with

vapor generation is the fact that commonly used flow metering equipment cannot

accurately measure the mass flow rates of two-phase fluid mixtures11. Ensuring that

only liquid flows through the metering system restricts the station design with respect to

features such as pre-dispensing cool-down and recirculation processes. In addition,

dispensers that utilize what are basically volumetric flow meters must have temperature

compensation systems in order to accurately measure LNG mass flow. A few early10 For example, Reference 15, which is a NREL report on the Raley’s LNG truck project initial (1997-

1998) experience, states, “The temporary fueling station required a significant amount of natural gas to be

vented to the atmosphere...”. Venting was substantially reduced when the temporary station was

replaced by a permanent station, and more recent temporary facilities have design features that reduce

venting.

11 In theory, commonly used coriolis meters can measure mass flow rate independent of the fluid phase,

but field experience has shown that they cannot accurately measure the flow rate of natural gas liquidvapor mixtures.
22

generation LNG fueling stations metered both the LNG dispensed into vehicle tanks and

vapor returned from the vehicle (e.g., Reference 5). However, few if any currently

operating LNG fueling stations, even those that have received weights and measures

certification, measure any vapor that is returned from the vehicle fuel tank to the station,

or just vented to the atmosphere, during refueling12.

Even though weights and measures certifiable LNG station designs and dispensing

equipment are available, not all stations are certified. This is primarily because many

LNG stations are dedicated to support a specific heavy-duty LNG vehicle fleet (e.g.,

refuse collection, transit) and never used to refuel other vehicles. Since these stations

don’t sell fuel, they are not required to be weights and measures certified. Moreover,

fleet operators purchase LNG on a mass basis13, and accurate mass-balance analysis

to reconcile fuel delivered with fuel dispensed is not usually regarded as a high priority.

In these cases, precise measurements of dispensed LNG is also not a high priority, and

so it is not possible to quantify venting losses. This is the main reason why this

document doesn’t report a quantitative measurement of overall LNG transportation fuel

venting losses.

Uncertainties regarding fuel venting also sometimes thwart attempts to make accurate

diesel vs. LNG vehicle fuel consumption comparisons. For example, one such effort

(Reference 15) reported, “Losses from vent filling the LNG trucks may also have

affected the in-use fuel economy results.” Other researchers (who asked not to be

identified in this report) reported an interesting result based on their analysis of what

they believe to be accurate and equivalent LNG and CNG heavy-duty vehicle fuel

consumption data: the CNG vehicles appear to have a slightly lower average fuel

consumption (in equivalent units, such as pounds per mile) than comparable LNG

vehicles. These researchers speculate that unaccounted-for venting losses from the

LNG vehicles is the most likely reason for this otherwise-puzzling result.

2.10 Applicable Codes and Standards

Various regulations, codes, standards, and recommended practices (“codes and

standards”) that apply to LNG fueling stations, vehicles, and tank trucks specify design

and operation requirements related to vapor generation and venting. Because these

codes and standards are listed and explained in many available publications (e.g.,

References 7, 8, 20, and 21), these lists and explanations are not repeated here.

Applicable codes and standards are occasionally revised, and up-to-date lists are

maintained by web sites such as References 35 and 36.

12 Note that, because of the substantial difference between natural gas vapor and liquid densities (Figure

4 and Appendix B), the mass of any offloaded vapor is usually quite small relative to the mass of

onloaded liquid.

13 Usually, the LNG tank truck is weighed before and after delivering fuel, and the customer is billed

based on the weight difference.
23

Section 3

LNG AND LCNG FUELING STATION DESIGN

AND OPERATION EFFECTS ON VENTING

3.1 Overview

The following subsections sequentially address vapor generation and venting issues

associated with tank-truck-to-station LNG transfer, LNG and LCNG fueling station

operations, and LNG vehicle refueling and operation. The venting implications of

different design options and operating practices are discussed. These discussions

presume an understanding of the basic LNG transportation fuel technical requirements

reviewed in Section 2 as well as the LNG physical characteristics summarized in

Appendices A and B.

In many cases, LNG vaporization and venting from one infrastructure element may have

been caused by design features or operations associated with another infrastructure

element (e.g., stations with poorly designed LNG delivery receipt systems can provoke

LNG tank truck venting, stations that refuel with unnecessarily high saturation pressure

LNG can cause premature LNG vehicle venting). Therefore, the order in which these

topics are discussed in the following subsections is somewhat arbitrary.

3.2 Tank-Truck-to-Station LNG Transfer

The basic characteristics of LNG tank trucks were reviewed in Section 2.6. The process

by which tank trucks transfer LNG to fueling stations and associated vapor generation

and venting issues are discussed here. This transfer process depends on the LNG

fueling station design and equipment. Therefore, the tank-truck-to-station transfer

process is discussed separately for three categories of stations in Sections 3.2.1, 3.2.2,

and 3.2.3.

However, a few LNG tank truck venting issues are common to all LNG station types.

One such issue is the need to usually purge the truck-to-station transfer hose of air

before transferring LNG from the truck to the station and emptying the hose of LNG

afterward. Because it is impractical to put this air plus LNG and vapor mixture anywhere

else, it usually escapes to the atmosphere (e.g., Figure 10). Based on typical transfer

hose sizes, vapor equivalent to very approximately 5 LNG gallons is typically lost due to

hose purging and emptying, which is 0.05% of a 10,000 LNG gallon delivery.

3.2.1 Pressure Transfer Offloading

Some LNG fueling stations built in the 1990s or earlier relied on pressure transfer to

transfer LNG from the tank truck to the station storage tank. These stations have no

dedicated LNG tank truck offloading pump, and they are not designed to use the
24

dispensing pump for tank truck offloading. This type of station is a very small

percentage of all the LNG fueling stations in operation as of 2010.

Figure 10. A small

quantity vapor

associated with LNG

tank truck transfer hose

purging and emptying is

usually lost to the

atmosphere.

Three sources of venting may be associated with LNG delivery to a station requiring

pressure transfer:

1. Blow-down of the station storage tank pressure before the LNG delivery

2. Blow-down of the truck tank pressure after the LNG delivery

3. Transfer hose purging and emptying before and after the LNG delivery

Blow-down of the LNG station storage tank is required if its pressure is too high for a

pressure transfer from the tank truck. This might be due to one or both of the following

reasons: First, if the station utilization is low and significant time has elapsed since the

last delivery, the LNG storage tank saturation pressure and temperature may have

increased as discussed in Section 2.3. Second, if the station “conditions” LNG in order

to refuel vehicles with high fuel supply pressure requirements (Sections 2.4 and 2.5),

the storage tank pressure is likely to exceed 100 psig. For example, 70 psig is a

common MAWP and PRD pressure for LNG tank trucks (e.g., Reference 37). Therefore,

even with a pressure build, a tank truck with this MAWP cannot pressure transfer LNG

into a station storage tank at 100 psig, and so blow-down of the station tank to a lower

pressure is necessary.

The LNG tank blow-down process involves substantial venting. This is because the

liquid and vapor are assumed to be initially in equilibrium, so that as the pressure is

reduced, more liquid promptly boils (“flashes”), which adds to the mass of vapor that
25

must be vented14. As a purely hypothetical example, consider a 15,000-gallon LNG

storage tank that is initially 10% full of liquid saturated at 100 psig that is vented until its

pressure is 60 psig (i.e., slightly less than the maximum pressure-build capability of a

70-psig MAWP tank truck). Figure A-6 in Appendix A indicates that this process would

involve a vented loss of approximately 170 LNG gallons equivalent.

Pressure transfer requires the LNG tank truck to use the pressure-build circuit

(described in Section 2.6) to generate the pressure differential needed to transfer the

LNG from the tank truck to the station storage tank. While there is no vapor loss

associated with the pressure build itself, this process is often followed by vapor venting

after the LNG transfer to reduce the pressure in the trailer tank (e.g., Figure 2-B). The

tank truck operator’s decision to vent (“blow down”) the tank is based on consideration

of factors such as the tank pressure, quantity of remaining LNG, and future schedule

plans15.

The quantity of vapor released to reduce that truck tank pressure depends on many

factors such as the starting and ending pressures, the quantity of liquid in the tank, and

the extent to which the liquid in the tank may have approached saturation at the tank

pressure. For example, the initial pressure-build pressure may change as the transfer

proceeds because the liquid level in the truck tank drops and perhaps the station tank

pressure decreases (e.g., if the station tank is top filled with colder liquid that condenses

the ullage vapor). An LNG tank truck venting after an initial pressure build from 20 to 60

psig to transfer 10,000 gallons could release approximately 20 to 150 LNG gallons

equivalent, depending on these various factors. Therefore, the total vapor loss

associated with the previously mentioned pressure transfer example might be as much

as 2% to 3% of the total LNG transferred to the station.

In theory, a vapor line could be employed to connect the tank truck and station tank

ullage spaces prior to the tank truck pressure build in order to utilize some of the station

tank vapor, which would otherwise be vented, to provide part of the tank truck

pressurization. It is unclear how often this procedure is used as part of pressure

transfers, but an analogous process is often used to support pumped transfer tank truck

offloading (Sections 3.2.2 and 3.2.3).

3.2.2 Offloading Using Dedicated Pump

A tank-truck-to-station LNG transfer method that minimizes potential venting and

expedites the transfer process is for the station to have and use a separate and

dedicated LNG tank truck offloading pump. “Separate and dedicated” means the pump

is separate from the LNG dispensing pump and it is dedicated to tank truck offloading.

This type of station configuration was sketched in Figure 1, and an example separate

LNG transfer pump in operation is shown in Figure 11.

14 This illustrates that blowing down (i.e., venting) a cryogenic tank is not the exact opposite of

pressurizing (e.g., via a pressure-build circuit) a cryogenic tank.

15 DOT regulations stipulate that on-highway venting of LNG vapor is a reportable vapor release.
26

Figure 11. Separate and

dedicated cryogenic pump

for tank-truck-to-station LNG

transfer.

Because high flow capacity at relatively low pressure differential is desired, cryogenic

centrifugal pumps are used for dedicated tank-truck-to-station LNG transfer. A few

stations utilize sump-submerged pumps, but most do not (e.g., Figure 11). The tradeoff

between ambient or submerged pumps for LNG tank truck offloading is subtle. LNG

pumps that are at or near ambient temperature generate substantial vapor as they cool

down (management of this vapor is discussed subsequently). This is avoided with

sump-submerged pumps. However, even the low level of heat transfer into an insulated

sump continuously affects the LNG in the station storage tank by slightly increasing its

saturation pressure, temperature, and venting potential. Also, because the LNG sump is

at approximately the same saturation pressure as the station storage tank (which is

likely to be more than 100 psig), even a sump-submerged pump requires some cooldown in order to pump the lower saturation pressure and temperature LNG from the

tank truck. Equipment availability and costs are also considerations affecting this

choice.

A factor that strongly affects vapor venting during tank-truck-to-station pumped LNG

transfer is the use of one or two fluid transfer lines (cryogenic hoses) between the tank

truck and the station (Figure 12). In either case, one line is obviously for flowing liquid

from the truck tank to the station. The purpose of the second line can be explained as

follows: The station LNG storage tank is at a higher pressure than the truck tank and the

transfer pump suction and discharge before the pump is primed. Consequently, the

vapor generated to cool down and prime the pump cannot be routed to the station tank

ullage, and so (unless two-line transfer is employed), it is usually vented to the

atmosphere. However, in two-line transfer, the second line flows this vapor back to the

truck tank ullage.
27

Figure 12. Tank-truck-to-station LNG transfer using one liquid line (A) and a vapor line

in addition to the liquid line to minimize venting (B).

In the two-line transfer method, the vapor line connects the station transfer pump

discharge to the truck tank ullage. This opens a circulation path that enables LNG to

flow to the pump and vapor from the pump to flow back to the tank truck. This facilitates

cooling and priming of the pump. When the pump is primed and discharging liquid

(which is indicated by an abrupt discharge pressure increase), the operator actuates a

valve that closes the return path so that LNG flows directly to the station storage tank.

In most applications, the pressure differential associated with the truck tank liquid level

and the pump elevation is inadequate to flow enough liquid to prime the pump in a

reasonable time. In these cases, the discharge side of the offloading pump is

sometimes briefly vented to the atmosphere to increase the flow of LNG to the pump

and expedite priming. Depending on the station design and tank truck offloading

procedure, when two-line transfer is used, this brief vapor venting can be from the

fueling station vent or from the LNG tank truck ullage vent. Priming of the transfer pump

is also expedited if the pump is at an elevation significantly lower than that of the tank

truck. This is the case for LNG fueling stations in which the pump and storage tank are

in a below-grade containment16 pit (i.e., as an alternative to at-grade installations that

have containment walls).

As explained here, two-line tank-truck-to-station LNG transfer using a separate and

dedicated pump is generally the best approach for quickly offloading tank trucks with

16 Applicable codes, standards, and regulations require LNG fueling station storage tanks to be within an

impounding area (e.g., a wall, pit, or combination thereof) adequate to contain the tank contents in case

of a spill.

A B Image courtesy Gladstein, Neandross & Associates
28

minimum venting. However, even this technique usually results in a small amount of

vapor vented to the atmosphere.

3.2.3 Offloading Using Dispensing Pump

Some LNG fueling stations are designed to use the dispensing pump (i.e., the pump

that transfers LNG from the station to vehicles being refueled, which will be discussed in

section 3.3) to offload LNG deliveries from tank trucks. These are typically stations with

relatively low utilization that are not inconvenienced by a few hours of refueling

nonavailability during tank truck LNG deliveries. For example, a few LNG stations

dedicated to refueling refuse collection truck fleets (which typically refuel over a set time

period each day when LNG deliveries are not scheduled) are of this type.

These stations have plumbing and valves that enable the dispensing pump (which is

almost always submerged in a LNG sump) to be switched from station-tank-to-vehicle

transfer to tank-truck-to-station-tank transfer. The primary advantage of this approach is

lower station capital cost because only one pump is required. The primary disadvantage

is the substantially longer time required to offload LNG tank trucks (and, if required, to

condition the newly delivered LNG to a higher saturation pressure) because the sumpsubmerged pumps used for dispensing typically have much less flow capacity than

separate and dedicated tank truck offloading pumps (Section 3.2.2).

While configurations and equipment for stations with separate and dedicated LNG tank

truck offloading pumps are different from stations that simply use the dispensing pump

for tank truck offloading, the issues affecting vapor generation and venting during LNG

deliveries are similar. Single-line transfer of LNG from a tank truck to the station storage

tank is possible for either type of station, but this usually results in significant vapor

venting to the atmosphere. Two-line transfer (as discussed in Section 3.2.2) is the

preferred practice, because this usually involves less vapor venting.

In situations for which the trailer tank is at a high pressure after transferring LNG to a

fueling station, drivers sometimes vent some of the trailer tank ullage vapor to reduce

this pressure prior to highway transport. Whenever possible, these situations should be

avoided.

3.3 LNG and LCNG Station Design and Operation

There are many options pertaining to the design and operation of LNG and LCNG

fueling stations. The following subsections discuss some of these options with emphasis

on vapor generation and potential venting implications.

For reference, Figure 13 is a simplified schematic of an example LNG fueling station

configuration. This example has the following basic features:

 One above-ground vertical LNG storage tank (e.g., 15,000-gallon gross capacity)

 Above-grade containment/impoundment wall
29

 LNG “conditioning” circuit (which includes a forced-air heat exchanger)

 Sump-submerged centrifugal dispensing pump

 One LNG dispenser with one refueling line and one vapor-return line

 Separate and dedicated LNG tank truck offloading pump (centrifugal, not in sump)

 Tank truck offloading panel with two-line (liquid and vapor) connection receptacles

Figure 13. Example LNG fueling station simplified schematic.

For simplicity, many station features (e.g., instrumentation, controls, leak detection, fire

detection) and plumbing details are not shown in Figure 13. Also, while this sketch is

representative of some currently operating LNG stations, other configurations are

possible and may be more suitable for particular LNG vehicle fleet circumstances.

VJ LNG

dispensing

hose &

nozzle

Dispensing meter

& controls

Vehicle tank

vapor hose

(as needed)

LNG

refueling

dispenser

LNG bulk conditioning

circuit & heat exchanger

Vent

valve

Pressure

relief valve "Auto-vent"

pressure

regulator

VJ LNG

storage

tank

Vapor return

to tank truck

(during pump

priming)

Dedicated tank truck

offloading pump

Liquid

Recirculation line

and vapor

return line

Sump-submerged

dispensing and

conditioning pump

Containment

wall
30

3.3.1 Station Sizing

LNG fueling station sizing refers to the quantification of various related specification and

design parameters. Key parameters include: the total LNG storage capacity (and

number of storage tanks), the number of refueling dispensers, and the LNG dispensing

flow rates (total and per dispenser).

These sizing parameters are driven primarily by the anticipated station utilization, which

was discussed in Section 2.7. The station utilization expressed as average LNG gallons

per day dispensed is the main parameter affecting the total storage capacity choice as

well as the LNG tank truck delivery frequency. The number of vehicles that must be

refueled in a given time period (e.g., the extent to which LNG dispensing is highly

“peaked”17), typical per-vehicle dispensed LNG quantities, and how quickly vehicles

must be refueled are all factors affecting choices such as the number of dispensers and

dispensing pump flow rate capacities.

LNG vehicle fleets with a substantial and reasonably constant fuel utilization (e.g.,

>3,000 LNG gallons per day) present the most straightforward circumstances with

regard to fueling station sizing. If these fleets have well-designed and similar LNG

vehicles (e.g., all requiring LNG at the same saturation pressure) that are constantly

operating, their refueling stations can be designed and operated to produce almost no

atmospheric venting of LNG vapor18.

Stations with much less utilization (e.g., <1,000 LNG gallons per day), or highly sporadic

utilization, are more likely to experience vapor venting. Specification developers and

designers of low-utilization stations are faced with various dilemmas. The main dilemma

pertains to the choice of LNG storage tank capacity and tank truck delivery frequency.

For example, a 15,000-gallon storage tank will enable infrequent deliveries of full tank

truck loads of approximately 10,000 gallons, but the tank saturation pressure will

increase substantially between deliveries. This may result in venting if the PRD

pressure is reached, or it may provoke the very bad practice of using a back-pressure

regulator to constantly “auto-vent” (which will be discussed subsequently). Another

alternative is to specify a smaller LNG storage tank (such as a 5,000-gallon intermodal

tank discussed in Section 2.8). In this case, the station cannot accept full tank truck

loads, and delivery schedules must be more frequent and precise. Additionally, budgets

for low-utilization stations are often such as to make it more difficult to include design

features and equipment that minimize vapor generation and venting.

Perhaps the most challenging circumstance for LNG station specification development

and design is presented by fleets that want a LNG station that will initially support three

or four “demonstration” LNG vehicles but will accommodate growth to fifty or more

vehicles. A large-capacity station with very low initial utilization is likely to be

17 Heavy-duty LNG vehicle fleets such as most transit buses and refuse trucks typically queue up to be

refueled in sequence (usually in the late afternoon or early evening), which results in a highly peaked

station utilization profile.

18 A few LNG equivalent gallons of vapor venting associated with tank truck delivery transfer hose purging

and emptying is essentially unavoidable, as discussed in Section 3.2.)
31

problematic with regard to storage tank saturation pressure increases and potential

venting between deliveries (e.g., as illustrated in Figure 9). The best approach for

addressing these difficult requirements may be one of the active vapor management

options to be discussed in Section 4.

3.3.2 Dispensing Pump Options

An important LNG fueling station component that can significantly affect vapor

generation and venting is the pump (or other means) used to transfer LNG from the

station storage tank to the vehicle fuel tank. The various station-to-vehicle transfer

methods that have been used include:

 Pump submerged in separate sump

 External (i.e., not submerged in LNG) pump

 Pump submerged in LNG storage tank

 Pressure transfer

 Gravity transfer

Most currently operating LNG stations use a pump submerged in a LNG sump that is

connected to the main LNG storage tank(s). Before discussing the details of this

configuration, it is useful to briefly review other approaches from a historical and

lessons-learned perspective.

Various early-generation LNG stations employed external uninsulated centrifugal pumps

because this approach is simple and inexpensive. A well-documented example is the

station supporting the Roadway Express LNG truck project in 1991 through 1993

(Reference 5). External pumps generate substantial vapor associated with the cooldown process needed to prime the pump. Most cryogenic pumps cannot function unless

they are receiving a slightly subcooled liquid at their suction19. Therefore, external

pumps are generally installed underneath LNG storage tanks. Cool-down is

accomplished by flowing LNG into the pump, which boils as it is heated by the pump

structure. External pump priming can be expedited by building pressure in the LNG tank

(if it is equipped with a pressure-build circuit). Vapor generated by the cool-down

process can be vented to the atmosphere or recirculated back to the tank ullage (which

adds substantial heat and shortens the tank hold time). Cool-down times and vented

vapor quantities are highly situation-specific, but cool-down times as long as 20 minutes

have been reported (Reference 12).

A few stations have used cryogenic pumps submerged in the main LNG storage tank(s).

An early example is the LNG station installed in Yosemite National Park in the 1970s

(Reference 3), which used a centrifugal pump. More recent examples are the Orange

19 In technical terms, these pumps require a slightly positive net positive suction head (NPSH). If supplied

with vapor or a saturated liquid-vapor mixture, they will cavitate.
32

County Transportation Authority (OCTA) LNG stations in Garden Grove and Anaheim,

which used underground tanks with reciprocating pumps. This approach requires

additional protrusions into the vacuum-jacketed storage tanks to facilitate pump

operation and maintenance, which increases heat transfer and decreases hold time.

Pressure transfer (i.e., no pump) has also been applied to transfer LNG from the station

storage tank to the vehicle fuel tank. An example is the Greater Austin Transportation

Corporation LNG station installed in 1992 (Reference 38). This station employed a

combination of heat exchangers, compressors, intermediate LNG tanks, and CNG

vessels to manage vapor and minimize venting. LNG tank trucks that are jury-rigged to

directly refuel LNG vehicles also employ pressure transfer.

The possibility of gravity transfer has been acknowledged (e.g., Reference 7), and

Reference 8 lists a few early-generation small-capacity LNG stations as using a

combination of gravity and pressure transfer, but no stations are known to have used

only gravity transfer. An obvious problem is the substantial LNG storage tank elevation

required to produce adequate pressure differentials and flow rates.

Use of centrifugal pumps in a LNG sump that is separate from but connected to the

LNG storage tank(s) for station-to-vehicle transfer dates from the early 1970s (e.g., the

Atlanta Gas Light LNG station used a sump-submerged pump in 1973, Reference 7).

This approach has been relatively successful, and it is used in nearly all recently

installed LNG stations. Figure 13 illustrated the basic sump-submerged pump

configuration. Figure 14 shows an example sump-submerged pump installation at the

Clean Energy LNG station near the Ports of Long Beach and Los Angeles, California.

Even though the sump-submerged centrifugal pump has emerged as the current

method-of-choice for station-to-vehicle LNG transfer, this approach is not without

liabilities. The sump and associated LNG circulation increases the heat input to the LNG

storage tank. This is inconsequential for stations with high utilization and frequent LNG

deliveries, but it can create vapor management challenges for stations with low or

sporadic utilization.

Another liability derives from the fact that the centrifugal cryogenic pumps typically used

in this application have a limited pressure-ratio capability. This occasionally requires

venting of high-pressure vehicle tanks before LNG can be pumped into the tank (this

issue will be discussed in more detail in Section 3.3.4). Reciprocating cryogenic pumps,

which have much higher pressure-ratio capability than centrifugal pumps, do not have

this liability, and they have been used occasionally for station-to-vehicle LNG transfer

(e.g., the previously noted OCTA LNG stations with in-tank reciprocating pumps).

However, reciprocating pump drives are not generally sump-submerged, and so their

use in this application involves a more complicated installation and more heat transfer to

the stored LNG.
33

Figure 14. Example sumpsubmerged pump installation at a

LNG fueling station. The vertical

grey cylinder is the vacuumjacketed sump containing a

centrifugal pump submerged in

LNG.

3.3.3 LNG Fuel “Conditioning” Options

A controversial LNG vehicle and fueling infrastructure issue, and one that significantly

affects heat addition, vapor generation, and potential venting, pertains to the best way

to provide the fuel supply pressure required by most SING-type and some PING-type

heavy-duty natural gas engines. This pressure is typically approximately 75 psig or

more for current-generation engines of this type (Table 2). A variety of approaches for

addressing this requirement have been implemented or suggested. Approaches that

require no special LNG fueling station equipment include in-tank fuel pumps (which

have seen limited application for SING engines, Reference 9) and vehicle fuel systems

with pressure-building circuits ( References 39, 40, and 41). Approaches that require

special station equipment include “bulk conditioning” and “saturation-on-the-fly”. These

are discussed in detail in this section.

The great majority of LNG fueling stations installed within the last decade employ bulk

conditioning to increase the saturation pressure of the LNG in the station storage tanks.

If the LNG dispensed into vehicle fuel tanks has a saturation pressure greater than the

engine fuel supply pressure requirement plus the maximum pressure drop associated

with the vehicle fuel system, no on-vehicle fuel pump or other pressure-building

equipment is required20. Bulk conditioning is accomplished by circulating the LNG from

20 In rare circumstances involving continuous high-load operation and well-insulated tanks, the energy

removal associated with the LNG outflow decreases the saturation pressure in the vehicle fuel tank. In

these cases, the vehicle should be refueled with even higher saturation pressure to avoid “running out of

gas”.
34

the storage tank through a vaporizer and back to the storage tank until the resulting

heat addition raises the saturation pressure to the desired level. This is typically done

immediately after a LNG tank truck delivery. During conditioning, the dispensing pump

is almost always used to circulate LNG through the vaporizer by closing and opening

valves as sketched in Figure 13. Examples of the two types of vaporizers used at LNG

stations, ambient natural-draft and forced-draft, are shown in Figures 15 A and B,

respectively.

Figure 15. Bulk conditioning of LNG in fueling station storage tanks is accomplished by

circulating the LNG through a natural-draft (A) or forced-draft (B) ambient

vaporizer. Saturation-on-the-fly conditioning is accomplished by heating the

LNG as it is being dispensed, e.g., by the electric heater in the cylindrical

vessel above the LNG dispenser (C) at the OCTA Garden Grove station.

Because it is relatively simple and inexpensive in terms of station and vehicle

equipment, bulk conditioning has evolved as the current method-of-choice for

addressing the needs of LNG vehicles with fuel supply pressure requirements in the 80

to 130 psig range. The primary disadvantage is that by transferring heat to the LNG to

raise its saturation pressure, hold times are decreased and venting potential is

increased with respect to both the station storage tank and vehicle fuel tank. Also, as

will be discussed in Section 3.3.4, bulk-conditioned LNG is less suitable for refueling

vehicles capable of being refueled with low saturation pressure LNG.

Saturation-on-the-fly conditioning involves adding heat to the LNG as it flows from the

station storage tank to the vehicle fuel tank. The heat addition is controlled so that the

resulting saturation state increase ensures that the dispensed LNG has the desired

A B C
35

saturation pressure. For saturation-on-the-fly systems that have been installed to date,

the heat addition is provided by electric resistance elements in a heat exchanger vessel

located near the LNG dispenser (Figure 15 C) or by mixing vapor with the LNG being

dispensed (which will be discussed in Section 4.3).

The main advantage of saturation-on-the-fly is that it allows the LNG in the station

storage tank(s) to be maintained at the lowest possible saturation pressure, which

corresponds to the maximum density (Figure 4) and the longest hold time. In principle,

saturation-on-the-fly can also enable modulation of the saturation state of the LNG as it

is being dispensed so that the initial “slug” of LNG is colder and therefore more effective

in condensing (“collapsing”) the vehicle tank ullage vapor. In some cases, this would

eliminate the need to remove vapor from the vehicle tank (as will be discussed in

Section 3.4). However, no saturation-on-the-fly conditioning systems with this type of

control have been installed.

The main disadvantage of electrically heated saturation-on-the-fly conditioning is cost,

primarily operating cost (e.g., for the electric power, which can be substantial). Capital

costs (e.g., for heaters, power supplies, heat-exchanger vessel, controls) are also

greater than bulk conditioning equipment costs. Experience with vapor-mixing

saturation-on-the-fly technology is inadequate to articulate overall advantages and

disadvantages. Due primarily to the incremental costs, relatively few LNG fueling

stations with saturation-on-the-fly conditioning have been built.

3.3.4 Fueling Stations Without LNG “Conditioning” Equipment

As discussed in Section 3.3.3, special equipment must be added to fueling stations that

must dispense conditioned LNG for vehicles requiring LNG saturated at pressures near

100 psi. Stations with bulk conditioning systems need a vaporizer and associated

plumbing and controls. Usually, vehicles cannot be refueled while conditioning is in

process, the storage tank hold time is decreased, and the potential for atmospheric

venting is increased. Stations with saturation-on-the-fly conditioning require special heat

exchangers and incur higher operating costs for electric power.

If dispensing of conditioned LNG to vehicles isn’t required, the fueling station design is

simplified, station capital and operating costs are less, and the potential for venting is

reduced. Three circumstances for which conditioned LNG is not required are:

1. Current – Heavy-duty vehicles with Westport ISX-G HPDI natural gas engines

(Section 2.5 and Table 2) have fuel systems that include a high-pressure pump,

and so they do not require conditioned LNG. It is preferable to refuel these

vehicles with low-saturation-pressure LNG (to maximize the mass of onloaded

fuel as well as the tank hold time), but they can also be refueled with conditioned

LNG. At the present time, this is the only commonly used heavy duty natural gas

engine that doesn’t require refueling with conditioned LNG.

2. Previous – In the 1960s through the mid-1990s, many LNG vehicles were lightor medium-duty vehicles with gasoline engines that had been converted to
36

natural gas fueling by replacing the carburetor with a natural gas mixer21. These

engines usually required fuel supply pressures ranging from approximately 15

psig (if naturally aspirated) to 30 psig (if turbocharged), which were easily

accommodated by LNG dispensed without intentionally increasing the saturation

pressure. In the 1990s, more than 100 transit buses were powered by Detroit

Diesel Corporation 6V-92TA PING engines, which required fuel supply pressures

in the 300-400 psi range (Reference 42). These buses had LNG fuel tanks with

pumps similar to the system sketched in Figure 7 B. This type of pumped LNG

fuel system was also used on a LNG-fueled bus with a Cummins L-10 SING

engine that had a much lower fuel supply pressure requirement (Reference 9).

While these 1960s through 1990s LNG vehicles didn’t require conditioned LNG,

almost none of these vehicles are still operating, and the natural gas engine

technologies of this era are now obsolete.

3. Hypothetical – Various alternatives to LNG conditioning have been suggested for

addressing the fuel supply pressure requirements of current-generation SING

(and some PING) engines. These include on-vehicle low-pressure pumps,

various on-vehicle pressure-building strategies, (e.g., as reviewed in Reference

19), and a few unpublished proprietary concepts. Successful implementation of

these technologies would simplify fueling station construction, increase hold

times in station and vehicle fuel tanks, and potentially reduce vapor venting.

While none of these technologies are commonly used at this time, their potential

benefits may motivate future development and commercialization if LNG use as a

transportation fuel continues its current growth rate.

3.3.5 Stations Capable of Refueling All Types of LNG Vehicles

Planners of LNG fueling stations that must be capable of refueling all types of LNG

vehicles (e.g., vehicles with the variety of fuel supply pressure requirements listed in

Table 2) have two basic choices:

 Option 1 – Dispense conditioned LNG (i.e., saturation pressure ~120 psig) to all

vehicles

 Option 2 – Dispense LNG at multiple saturation pressures that are best suited to

each vehicle being refueled (e.g., ~120 psig for vehicles with Cummins Westport

ISL-G engines and ~30 psig for vehicles with Westport ISX-G engines)

The disadvantage of Option 1 is that some vehicles that don’t need conditioned LNG will

be refueled with high-saturation-pressure LNG, which, as previously discussed, reduces

the mass of fuel that can be dispensed to the vehicle, decreases the vehicle tank hold

time, and increases the likelihood of venting. This is, however, the lowest-cost option,

and most LNG fueling stations are of this type.

21 Reference 7 contains a listing of LNG vehicle projects in this time period.
37

At the present time, only two LNG stations have Option 2 capability: The Clean Energy

LNG station in Carson, California, and the nearby Clean Energy Ports of Long Beach

and Los Angeles LNG station. These stations have separate storage tanks and

dispensers for conditioned and unconditioned LNG (Figure 16). Therefore, from one

perspective, there are essentially two stations at each site. Clean Energy refers to them

as the “Blue Station”, which dispenses unconditioned LNG at a <-235°F & <35 psig

saturation state, and the “Green Station”, which dispenses conditioned LNG at

saturation states in the -195 to -207°F & 85 to 120 psig range (Reference 27).

Figure 16. The Clean Energy Ports of Long Beach and Los Angeles fueling station (A)

dispenses LNG at two saturation pressures: “Blue” LNG (B) has a low

saturation pressure for vehicles with engines such as the Westport ISX-G,

and “Green” LNG (C) has a higher saturation pressure for vehicles with

engines such as the Cummins Westport ISL-G.

Because it requires duplicate storage tanks, dispensers, and other equipment, the “two

grades of LNG” Option 2 strategy is much less cost effective for LNG stations with low

utilization than stations with high utilization. In theory, LNG fueling stations could utilize

saturation-on-the-fly technology (Section 3.3.3) to provide Option 2 capability, but no

stations of this type have been built to date.

A

B C
38

3.3.6 LNG Fuel Dispenser Cool-Down Options

LNG vehicle fuel tanks are refueled most effectively if the initial quantity (“slug”) of fuel

dispensed into the tank is liquid and not vapor. If a substantial slug of vapor is initially

dispensed into the vehicle tank, this can cause a pressure rise that terminates refueling

(because the pressure exceeds the dispensing pump capability or approaches the tank

PRD pressure), and it usually requires vapor offloading or venting before refueling can

proceed.

The potential for the initial slug of dispensed fuel to be mostly vapor is due to heat leaks

to the LNG in the plumbing in and near the dispenser between refueling episodes (i.e.,

when there is no flow), especially if the time increments between refuelings are long.

This heat transfer essentially boils some of the LNG in the plumbing. If the station has

no features designed to avoid this situation, the pump drives this vapor into the vehicle

fuel tank at the beginning of the next refueling.

LNG fueling station designs incorporate a variety of features intended to avoid or

minimize this situation. The most basic technique is simply to recirculate LNG through

the dispenser (as can be visualized from Figure 13) to cool down most of the affected

plumbing. Some stations have metering elements that are submerged in a small LNG

sump in the dispenser. These stations don’t require LNG recirculation prior to

dispensing, but a low level of constant recirculation is required to offset heat leaks and

maintain a constant level of LNG in the metering sump. With either of these

approaches, the recirculation process adds heat to the station storage tank22, which

shortens its hold time and may increase the likelihood of atmospheric venting.

Some LNG fueling station designs seek to minimize the volume of vapor generated

between refuelings by locating the sump with the dispensing pump very close to the

dispenser (which in these cases is usually a dispensing panel in the containment wall),

so that little or no recirculation is needed prior to refueling vehicles.

The heat addition and/or vapor management challenge associated with the need to cool

down the dispenser prior to vehicle refueling is much less for stations with high

utilization than those with low utilization (i.e., those with sporadic or lengthy periods

between vehicle refuelings).

3.3.7 Station LNG Storage Tank Pressure Management

For LNG fueling stations with adequate utilization and no excessive heat or vapor

injection into the storage tank(s), the saturation pressure and temperature of the LNG in

the storage tank(s) fluctuates very little between LNG tank truck deliveries. However, for

stations with low utilization (as discussed in Section 2.7), the saturation pressure of the

LNG in the storage tank can increase substantially between deliveries. If the station

utilization is extremely low, the saturation pressure can reach the storage tank PRD

pressure before the LNG level in the tank is low enough to accept another full tank truck

22 In a few stations, the vapor from the cool-down process is vented to the atmosphere (which is obviously

an inappropriate practice) instead of being returned to the LNG storage tank.
39

delivery (as illustrated in Figure 9). Even for stations with higher utilization, the

saturation storage tank pressure can increase substantially between deliveries if the

tank receives significant vapor input from vehicle fuel tank vapor offloading, LNG

transfer pump priming, many dispenser cool-down recirculation cycles, etc. A given

storage tank saturation pressure increase is of course a more challenging issue for

stations with bulk conditioning that have already increased the saturation pressure of

the LNG in the storage tank to 100 psig or more.

Stations that experience substantial LNG saturation pressure increases sometimes

address this problem by using a back-pressure regulator (as shown in Figure 13) to

constantly vent vapor to the atmosphere at a rate so as to maintain the storage tank

pressure at a constant and convenient level (e.g., 130 psig). This inappropriate practice

is occasionally referred to as an “auto vent” system or simply “riding the regulator.” A

more appropriate approach is to address and mitigate the basic cause of the substantial

saturation pressure increase or to manage the vapor by one of the means to be

discussed in Section 4.

3.3.8 LCNG Fueling Stations

As noted in Section 1, LCNG fueling stations are stations that receive and store LNG

(just like LNG stations), but they dispense CNG instead of or in addition to LNG. In

LCNG stations:

1. The LNG is pumped to a high pressure (e.g., ~4,500 psi),

2. Vaporized and warmed to near-ambient temperatures (in a vaporizer similar to

those shown in Figure 15 A and B),

3. In most cases, an odorant is added to the gas after it is vaporized (because LNG

contains no odorants; they are incompatible with the liquefaction process, and so

any odorants in the feedgas are removed by the pretreatment system),

4. The gas is stored in pressure vessels (either a buffer tank or a sequenced

cascade), and

5. The high-pressure gas is dispensed to refuel CNG vehicles.

Figure 17 shows an example of a LCNG fueling station. This particular example is

selected simply because most of the principal components are visible in the photograph.

LCNG stations are often combined with LNG stations so that CNG and LNG are

dispensed at the same station. These are usually referred to as LNG/LCNG stations,

but there isn’t uniform agreement regarding this nomenclature. Combining of LCNG and

LNG stations takes advantage of obvious economies because they can share the same

LNG storage vessels and other components. Also, combining LCNG and LNG refueling

enables certain vapor management options, which will be discussed in Section 4.
40

Figure 17. The Santa Cruz Metropolitan Transit District (“METRO”) LCNG fueling

station is an example of this type of facility. METRO chose LCNG primarily

because convenient access to an adequate-capacity natural gas pipeline

was unavailable.

The tradeoff between conventional gas-pipeline-supplied CNG stations and LCNG

stations is subtle and situation dependent. One advantage of LCNG stations is that LNG

pumps are less expensive and consume substantially less power than equivalent flow

capacity gas compressors. On the other hand, there are no vapor management or

venting issues associated with pipeline-supplied CNG stations. More detailed

information regarding LCNG station design features, advantages, and disadvantages is

available in References 13, 14, 17, 22, 26, and 43.

LCNG fueling stations have some, but not all, of the same vapor management issues as

LNG fueling stations. For example, due to LNG storage tank heat leak effects (Section

2.3), the tank capacity, average fuel dispensing rate, and tank truck delivery frequencies

15,000-gallon LNG

storage tank

Vaporizers

Pumps in

containment pit

High-pressure gas

storage vessels

CNG

dispensers
41

should be such that the tank saturation pressure never increases to the PRD pressure.

This is usually less of a challenge with LCNG stations than LNG stations, because there

is no need to condition the LNG and there are fewer sources of vapor that need to be

accommodated by the LNG in the storage tank.

On the other hand, some of the earlier LCNG station installations experienced a

substantial quantity of vapor generation and vapor venting associated with pump

priming. This is because reciprocating cryogenic pumps are required in order to produce

the pressure ratios necessary for CNG service, these pumps generally have greater

NPSH (Section 3.3.2) requirements than centrifugal pumps, and they are not usually

submerged in a sump. More recent LCNG stations have adopted a practice that

essentially solves this problem. LNG from the storage tank flows first to a sumpsubmerged centrifugal pump, which provides a more-than-adequate NPSH to a highpressure reciprocating pump. The centrifugal pump functions as an inducer for the

reciprocating pump so that it primes promptly with minimal vapor generation. Figure 18

illustrates this arrangement of multiple centrifugal and reciprocating pumps at a

relatively large-capacity LCNG fueling station. This arrangement is particularly cost

effective at stations with combined LCNG and LNG refueling capabilities, because the

same sump-submerged centrifugal pump(s) can be used for LNG dispensing and as a

LCNG pump inducer.

Figure 18. These pumps

at the Omnitrans San

Bernardino LCNG station

illustrate the practice of

using sump-submerged

centrifugal pumps as

inducers for high-pressure

reciprocating pumps.

3.4 LNG Vehicle Operations

Vapor can be vented directly from LNG vehicles (e.g., Figure 2 C), and/or certain

vehicle fuel tank and system situations can increase the likelihood of venting from the

fueling station.

Sump-submerged

centrifugal pumps

High-pressure

reciprocating pumps
42

Venting from LNG vehicles occurs when the saturation pressure of the LNG in the fuel

tank exceeds the PRD pressure. Codes and standards (Section 2.9) require LNG

vehicle fuel tanks to have two PRDs (Figure 7). The primary PRD is usually set at the

tank MAWP and the secondary PRD is usually set at 1.5 times the MAWP. The primary

PRD is connected to a discharge tube located so that any vented vapor is directed

upward and away from likely personnel locations.

Venting from LNG vehicles should not occur if the vehicle is driven regularly and its

equipment is operating properly. If the vehicle is not regularly driven (e.g., parked for

many days), normal heat leaks can cause the LNG saturation pressure to increase to

the PRD pressure and venting will occur as described in Section 2.3 and illustrated in

Figure 6. The LNG fuel tank saturation pressure variation between refuelings depends

on many factors including the tank heat leak characteristics, the driving cycle, the

saturation pressure and ullage fraction in the tank immediately after refueling, and

whether or not it is equipped with an economizer valve (or equivalent device).

An occasional LNG vehicle problem that substantially reduces fuel tank hold time and

increases venting likelihood is a partial loss of vacuum, which is usually referred to as a

“soft vacuum”. Sweating or frosting on the tank exterior (which may be evident before

venting) are likely indications of a soft vacuum condition. LNG vehicles that are venting

or show evidence of a soft vacuum should be taken out of service. They should be

parked outdoors in a safe location and inspected and/or tested to diagnose if the fuel

tank insulation has been compromised. If a soft vacuum condition is confirmed, the fuel

tank should be defueled (if possible) and repaired or replaced.

LNG vehicles can affect fueling station venting if and when vapor is transferred from the

vehicle fuel tank to the station storage tank. This may occur in either of two related

circumstances:

1. The pressure in the vehicle fuel tank at the beginning of refueling exceeds the

station dispensed LNG maximum pressure so that no fuel is pumped into the

vehicle tank. As discussed in Section 3.3.2, this may be because the dispensing

pump pressure ratio capability is such that it cannot “buck” the initial pressure in

the vehicle tank23. Or, for some stations, this may be because a dispenser

recirculation valve opens at a pressure less than the initial vehicle tank pressure.

In most cases, this condition is detected by the refueler who attaches the vapor

hose (Figure 13) to the fuel tank vapor receptacle and removes vapor until the

pressure decreases so that refueling can proceed. Reducing the vehicle tank

pressure by simply opening the vehicle fuel tank vapor valve and venting vapor

to the atmosphere is an inappropriate practice.

2. In some situations (which are affected by factors including the vehicle fuel tank

pressure and ullage fraction prior to refueling, the dispensed LNG saturation

state, and the station dispenser cool-down system design), the inflowing LNG

23 In some designs and situations, the vapor can actually flow “backward” through the main refueling

hose.
43

does not promptly condense (“collapse”) the vehicle fuel tank vapor, and the

vehicle tank pressure increases toward the PRD pressure (or beyond the

dispensing pump capability). In this case, as in circumstance #1, vapor must be

removed from the vehicle fuel tank and returned to the station before refueling

can proceed. Again, reducing the vehicle tank pressure by venting the vapor to

the atmosphere is a bad practice.

The above descriptions apply to almost all currently used LNG vehicle fuel systems.

Some systems used in the past employed two-hose refueling couplings, and some

vapor was automatically returned from the vehicle fuel tank to the station storage tank

as part of the refueling process (e.g., References 7, 16, 19, 23). Few if any of these

systems are in use at this time.

Closely related circumstances #1 and #2 described above both inject heat (in the form

of vapor) into the fueling station LNG storage tank, which increases the LNG saturation

pressure and temperature. This is the mechanism by which certain LNG vehicle fuel

tank and system situations increase the likelihood of atmospheric venting of vapor from

the fueling station.
44
45

Section 4

OPTIONS FOR RECOVERING VAPOR

GENERATED AT LNG FUELING STATIONS

4.1 Overview

There are two basic ways to mitigate atmospheric venting at LNG fueling stations:

1) design and operate the station so that no vapor is released to the atmosphere,

or 2) recover and use excess vapor for some useful purpose. Previous sections of this

report have discussed LNG station design principles and operating practices that avoid

or minimize vapor generation and venting. For situations where it is technically or

economically impractical to eliminate all vapor releases, there are various options for

recovering and using the otherwise-vented vapor. These options are discussed in the

following subsections.

Any LNG fueling station vapor management strategy that involves continuous or

frequent removal of vapor from the storage tank will cause the composition of the LNG

dispensed to vehicles to be different from that delivered to the station by tank trucks. In

most cases, this has no practical implications because most LNG currently delivered to

LNG fueling stations is of very high purity (e.g., ~99% methane, Section 2.2) and the

vapor removed is likely to be a very small fraction of the LNG dispensed. However, in

rare cases for which the LNG has a substantial percentage of heavier hydrocarbons

and/or the vapor removal rate is a large fraction of the LNG dispensing rate, the LNG in

the storage tank will become enriched (Section 2.2 and Appendix B) and the fuel

dispensed to vehicles may not comply with engine manufacturers’ fuel composition

specifications24. Any plans to remove and utilize LNG vapors should include

consideration of potential composition change implications.

It should be noted that technologies for utilizing vapors generated from LNG fueling

stations can be regarded as a subset of the more general problem of recovering and

productively using methane vapors from LNG tanker ships, LNG processing and

peakshaving plants, gas and oil well operations, gas compressor leakage, landfills, and

various agricultural activities. Because these sources produce methane releases many

orders of magnitude greater than those from LNG fueling stations, they have been the

subject of various international symposia (e.g., Reference 44), Environmental Protection

Agency programs (e.g., References 45, 46, and 47), and hundreds of special studies.

Even though there is significant overlap with methane-release-mitigation technologies

applicable to these sources, the focus here is confined to LNG fueling station vapor

utilization.

24 In extremely rare cases for which the LNG contains significant nitrogen, the vapor phase will have a

much higher nitrogen concentration and may not be suitable for some of the boil-off vapor utilization

options discussed in this section.
46

It should also be noted that there have been a few previous studies directed specifically

at LNG fueling station vent gas utilization. Reference 48 evaluated alternatives for one

particular station that was anticipated to have low initial utilization (the Barstow,

California, LNG/LCNG station). Other studies that have addressed aspects of LNG

fueling station vapor utilization include References 5, 7, 8, 16, and 25.

Options for recovering and utilizing otherwise-vented vapor (which is often referred to as

boil-off vapor) from LNG fueling stations are listed in Table 3. These options are

discussed in the following subsections with emphasis on prior application experience

and what was learned from that experience.

Reliquefaction of boil-off vapor

Utilize boil-off vapor for on-the-fly LNG fuel conditioning

Flaring of boil-off vapor

Sell boil-off vapor to local natural gas utility

Utilize boil-off vapor to supply facility natural gas requirements

Use boil-off vapor to generate electric power to be sold to local electric utility

Use boil-off vapor to generate electric power for on-site utilization

Compress boil-off vapor for use for CNG vehicle fueling

Table 3. Options for recovering and utilizing boil-off vapors from LNG fueling stations.

4.2 Reliquefaction of Boil-Off Vapor

Numerous studies have considered reliquefaction of LNG fueling station boil-off vapor,

but there has been only one known attempt to apply this technology, and this

application was unsuccessful. No currently operating LNG stations have a reliquefaction

capability.

The reliquefaction concept consists of processing excess vapors (which might otherwise

be vented to the atmosphere) through a liquefier to condense the vapor to the liquid

phase and return the liquid to the LNG storage tank. Almost any liquefaction or

refrigeration cycle (e.g., as reviewed in cryogenics textbooks such as Reference 28) can

be employed. However, even for very large LNG fueling stations, the vapor generation

rate is relatively small, and so the liquefier should be cost effective for low-throughput or

frequent-on/off applications.

Studies that have considered reliquefaction include References 8, 10, 16, 25, and 48.

While most studies considered reliquefaction based on liquefaction or refrigeration

cycles such as Joule-Thomson, Stirling, and Gifford-McMahon, the previously noted

Kellogg study (Reference 8) conceptualized two somewhat different strategies: LNG
47

vapor reliquefaction by heat transfer to evaporating liquid nitrogen (with inert nitrogen

vapor vented to the atmosphere), and integration of the reliquefaction system with an

on-the-fly fuel conditioning system (heat transferred from compressed boil-off vapor to

increase the saturation pressure of the dispensed LNG condenses the vapor, which is

similar to the concept considered in Section 4.3). Neither of these concepts have been

applied at actual LNG fueling stations. Reference 48 considered a simple reliquefaction

system utilizing a compressor, heat exchanger, and expansion valve for the Barstow

LNG station. Based on an approximate economic analysis, it was concluded that

reliquefaction would be much less cost effective than other vapor management options.

The only known non-confidential application of boil-off vapor reliquefaction at an actual

LNG fueling station was at the Orange County Transportation Authority (OCTA) station

in Garden Grove, California. The procurement specifications for this station required a

“recondenser system” to manage vapor and avoid atmospheric venting. A reliquefaction

system that utilized two 200-Watt CVI Gifford-McMahon refrigerators (Reference 16)

was initially applied to address this requirement. This system did not perform consistent

with expectations (Reference 49), and details regarding this experience were not

documented. Natural gas fueled electric generators (which are discussed in Sections

4.6 and 4.7) were subsequently installed at the OCTA LNG stations to accommodate

worst-case vapor management episodes.

Although there have not yet been any successful applications of reliquefaction for LNG

fueling station excess vapor management, several recent small-scale liquefier

technology advances may contribute to making this option more viable in the future.

One example is the natural gas liquefier technology developed by the Gas Technology

Institute (GTI), which utilizes a relatively inexpensive screw compressor and a proven

mixed-refrigerant cycle to provide a small-capacity liquefier with low capital and

operating costs (Reference 50 and 51). A prototype 1,000 LNG gallon per day GTI

liquefier is shown in Figure 19 A. There have also been recent advances in boil-off gas

reliquefiers for LNG carrier ships , which is an application analogous to (but with much

higher throughput than) LNG fueling station vapor reliquefaction. For example, the

Hamworthy Company has successfully applied this technology (References 52 and 53).

Figure 19 B shows a 600 LNG gallon per day laboratory liquefier cooperatively

developed by Hamworthy and SIMTEF (a large Norwegian research organization).

4.3 Utilization of Boil-Off Vapor for On-the-Fly LNG Conditioning

A small LNG vapor stream can be mixed with a larger stream of LNG liquid to produce a

LNG liquid stream saturated at a higher pressure. In principle, this process could be

utilized as part of an on-the-fly LNG conditioning system (see Section 3.3.3) that would

consume some of the station boil-off vapor while producing LNG at the saturation

pressure required by the vehicles being refueled. However, such a system would

require extra equipment (e.g., compressor, mixing chamber, sensors) as well as precise

control. Also, because the desired vapor removal rate and dispensed fuel saturation

pressure wouldn’t ordinarily be balanced, such a system would probably have to be

combined with another LNG conditioning technology (e.g., electric heaters).
48

Figure 19. Recent advances in economical small-scale liquefaction technology may be

applicable to LNG fueling station boil-off vapor reliquefaction. Examples

include this prototype of a GTI liquefier that utilizes a mixed-refrigerant cycle

and a low-cost screw compressor (A) and this 600 LNG gallon per day

laboratory liquefier develop by SINTEF in cooperation with Hamworthy (B).

A process similar to this has been developed and demonstrated by the Idaho National

Laboratory (INL, previously referred to as INEEL). The INL process achieves on-the-fly

LNG conditioning (Section 3.3.3) by combining controlled amounts of vapor with the

flowing LNG in a mixer located just upstream of the LNG dispenser. In the standard

embodiment of this system, the vapor is derived from LNG that is routed through a

vaporizer (References 43 and 54). However, the vapor mixed with the LNG could also

be drawn from the LNG storage tank ullage (perhaps with the aid of a compressor), in

which case the system could provide both on-the-fly conditioning and excess vapor

management. This technology (with the vapor from a LNG vaporizer and not from the

storage tank ullage) has been employed at INL and Southwest Transportation Agency

(Caruthers, California) LNG/LCNG fueling stations.

4.4 Flaring of Boil-Off Vapor

In a 1996 study of LNG vehicle fueling technologies, the M. W. Kellogg Company (which

is now part of the KBR Company) discussed and diagramed the possibility of flaring

(i.e., burning in an elevated incinerator) LNG fueling station boil-off vapors (Reference

8). This study pointed out that flaring is inexpensive and that releasing carbon dioxide

and water instead of methane reduces GHG emissions. While flaring is a common

practice in oil and gas well operations, and at some landfills, there is general agreement

that this is an inappropriate vapor management option for LNG fueling stations.

A B Image courtesy SINTEF

& Hamworthy

Image courtesy Gas Technology Institute
49

4.5 Sell Boil-Off Vapor to Local Natural Gas Utility

An obvious LNG fueling station excess vapor management strategy is to simply inject

the gas into the local gas distribution pipeline network and sell it to the natural gas

utility, i.e., the local distribution company (LDC). This option is not easily implemented,

however, and there is only one documented instance of LNG station boil-off gas being

routed to the LDC. The challenges involve the required process equipment and

contractual arrangements.

The process equipment requirements are illustrated, for example, by the one

documented implementation, which was the Roadway Express LNG truck station in

Copley, Ohio, in the early 1990s (Reference 5). This project required a special gas

compressor, buffer storage vessel, heat exchanger, and gas meter. In other cases, an

odorizer may be required to accommodate LDC requirements for gas injected into their

distribution network.

The major challenge is anticipated to be consummating the legal and contractual

arrangements with the LDC to permit and pay for gas received into their network. Issues

include accounting, pricing, composition, metering and scheduling. Selling gas to the

LDC at the distribution network level is an unusual situation, applicable regulations are

nonexistent or location dependent, and LDCs are not always eager to improvise.

Perhaps recent renewable percentage legislation and interest in biomethane will affect

this situation. It is significant to note that the previously cited Roadway Express project

LNG station, which fed boil-off gas to the nearby Consolidated Natural Gas 60-psig

pipeline, was in fact funded and managed by Consolidated Natural Gas (Reference 5).

4.6 Utilize Boil-Off Vapor to Supply Facility Natural Gas Requirements

An option that may be suitable for LNG fueling stations that are part of a larger facility

with natural-gas-consuming equipment (e.g., heaters, boilers) is to utilize excess vapor

from the fueling station to provide some of the facility natural gas requirements. This

strategy avoids most of the contractual and regulatory challenges associated with

selling natural gas to the LDC, which were discussed in Section 4.5.

This option is suitable only for facilities with LNG fueling stations that consume

significant quantities of natural gas. The facility natural gas demand schedule should be

in phase with the station excess vapor management needs, because any need to store

significant quantities of gas would probably make this option uneconomical. Other

equipment requirements (e.g., for compression, odorization, metering) depend on

specific facility situations. While this option avoids local gas utility contractual

challenges, it may encounter some facility management challenges pertaining to

odorization requirements, building codes, insurance policy restrictions, etc.

The Grand Canyon LNG/LCNG fueling station is the only station known to be using this

type of system at this time. In this application, boil-off gas is used to heat maintenance

buildings, which don’t have access to a natural gas pipeline.
50

4.7 Use Boil-Off Vapor to Generate Electric Power to be Sold to Local Electric

Utility

Excess vapor from a LNG fueling station can be supplied to an on-site natural-gasfueled electric generator, and the power can be sold to the local electric utility. In this

situation, the station owner/operator becomes an Independent Power Producer (IPP) or

Non-Utility Generator (NUG) and must comply with various regulations applicable to

these entities.

The main equipment item required is a natural-gas-fueled electric generator, i.e., a

“genset.” Given the range of LNG station sizes, likely excess vapor fractions, and typical

genset heat rates, the genset rating would probably be in the 20 kW to 200 kW range.

Gensets using natural gas internal combustion engines (which are usually diesel

derivatives) and small gas turbines are available in this power range. Depending on how

the genset is equipped, additional equipment that may be needed includes a gas

compressor, buffer storage vessel, controls, and electrical equipment for utility grid

interconnection.

The feasibility of this option benefits from the US Public Utility Regulatory Policy Act

(PURPA) of 1978, which requires utilities to purchase power from NUGs. With this

option, the fueling station would most likely be classified as a parallel operator, which

applies to entities that operate a generating facility that simultaneously delivers and

receives power while interconnected. Numerous state- and utility-dependent rules and

regulations apply to NUGs. For example, in California, the facility application,

interconnection, operation, and metering must comply with “Rule 21,” which is slightly

different for each of the electric utilities over which the California Public Utilities

Commission (CPUC) has jurisdiction. In addition to securing electric utility approvals, a

NUG must also obtain various other permits. In some locations such as California,

Authority to Construct and Operating Permits must be obtained from air quality

management or air pollution control districts, and this is not always a straightforward

process.

An economic assessment of this option should consider the avoided electric cost and

any reduced demand charges as offsets to the operating cost and amortized capital

cost. While using boil-off gas to generate electricity for sale to the local electric utility

may be an attractive option in some circumstances, no LNG fueling stations are known

to be IPPs or NUGs at this time.

4.8 Use Boil-Off Vapor to Generate Electric Power for On-Site Use

Although no LNG fueling stations are known to be IPPs or NUGs, a few stations have

installed gensets fueled with LNG vapor. Two examples are OCTA and Santa Monica

Transit (Big Blue Bus) in California. In each of these cases, the gensets are basically

backup generators that are not used for routine LNG station boil-off vapor management.

At OCTA, natural-gas-fueled internal combustion engine generators were installed after

the reliquefaction system (Section 4.2) was found to be ineffective. The stated intent of
51

the OCTA gensets is to avoid substantial atmospheric venting of boil-off vapors if no

LNG is dispensed into buses for an extended period of time (e.g., in case of a bus

drivers’ strike). The Natural-gas-fueled gensets at Big Blue Bus are essentially backup

power generators and are not routinely used (nor are they needed) for boil-off vapor

management.

The use of natural-gas-fueled gensets for LNG fueling station excess vapor

management, while producing electric power for facility use without becoming a parallel

operator and supplying power to the local grid, appears to be feasible. However, no

LNG stations are known to be currently operating in this fashion.

4.9 Compress Boil-Off Vapor for Use for CNG Vehicle Fueling

An excess vapor recovery and use method that is being applied successfully at a few

LCNG and LNG/LCNG fueling stations consists of compressing the vapor and

dispensing it to refuel CNG vehicles. In principle, this method could be applied to LNG

fueling stations, but it is more straightforward to implement at LCNG or LNG/LCNG

stations that already have dispensers, high-pressure gas storage vessels, and other

equipment needed for CNG vehicle refueling.

Equipment needed to implement this option at any station that stores LNG includes:

 A heat exchanger (to cool the vapor so that it meets compressor specifications)

 A gas compressor ( to ~4,500 psig)

 High-pressure cascade or buffer gas storage vessels (already exist at LCNG

stations)

 Gas odorization equipment25 (already exist at LCNG stations)

 A CNG dispenser (already exist at LCNG stations)

 Associated plumbing, controls, etc.

This option also obviously requires CNG vehicles that can be refueled at the station

location.

Figure 20 shows the heat exchanger and compressor installed at the Santa Cruz

Metropolitan Transit District LCNG fueling station to manage excess vapor. The quantity

of vapor that may need to be managed at any station is a small fraction of the total LNG

throughput (for LNG or CNG fueling), and so a relatively low-capacity and low-cost

compressor is adequate for this application.

25 In some cases, a waiver from regulations requiring odorized CNG vehicle fuel can be obtained. For

example, CNG dispensed into transit buses at the two Omnitrans LCNG stations is not odorized

(Reference 22).
52

Another facility that uses this method of LNG boil-off gas management is the

LNG/LCNG fueling station in Barstow, California. The Barstow facility planning study

(Reference 48) identified compression-to-CNG and supplying gas to the LDC network

(Section 4.5) as the two most highly ranked vapor management options. After

considering the various regulatory hurtles associated with selling gas to the LDC

network, Barstow management chose the compression-to-CNG option.

Figure 20. Small-capacity compressor

and heat exchanger (to the left of the

compressor) installed at Santa Cruz

Metropolitan Transit LCNG station to

manage excess vapor and avoid

atmospheric venting.
53

Section 5

EMISSIONS IMPLICATIONS OF LNG VAPOR ATMOSPHERIC VENTING

5.1 Overview

Atmospheric venting of vapor from LNG fueling stations should be avoided or minimized

for economic, safety, and environmental reasons. The negative environmental impacts

of LNG vapor venting are discussed here. Greenhouse gas effects are discussed in

Section 5.2 and criteria pollutant emissions are discussed in section 5.3.

5.2 Greenhouse Gas (GHG) Emissions

The quantitative effect of atmospheric venting of vapor at LNG fueling stations on

overall well-to-wheels LNG fuel cycle emissions can be estimated from results

generated using the Greenhouse Gases, Regulated Emissions, and Energy Use in

Transportation (GREET) model developed at the Argonne National Laboratory

(Reference 55). A GREET version that is well suited to this application is the CAGREET model (Reference 56), which includes various features specific to California

applications of alternative transportation fuels. Two publications that document CAGREET predictions of well-to-wheels GHG and criteria pollutant emissions for LNGfueled heavy-duty vehicles are References 57 and 58. The results from these two

studies are similar, but they differ slightly with respect to the fuel pathways considered

and a few quantitative assumption details (e.g., liquefier efficiencies).

The total well-to-wheels (WTW) emissions can be regarded as the well-to-tank (WTT)

plus the tank-to-wheels (TTW) emissions, i.e.: WTW = WTT + TTW. Absent any venting

during vehicle operation, the venting considered here affects only the WTT emissions.

GREET analyses account for boil-off and boil-off gas recovery associated with LNG

storage at the liquefaction plant, transportation (e.g., tanker ship), bulk terminal,

distribution (e.g., tank truck), and fueling station. The GREET default assumption for

fueling station boil-off is 0.1% per day with 80% recovery26 (which is equivalent to

0.02% per day vapor venting).

The discussion here is based on the analysis in Reference 58 because the results are

summarized in a suitably simple fashion and GHG emissions are expressed as grams

of CO2 equivalent per diesel equivalent gallon (g-CO2eq/deg). This analysis also

includes an especially representative WTW pathway, which is labeled NA-LNG-CE and

consists of:

 Natural gas from North American wells,

 Transported via pipeline to California,

26 GREET documentation doesn’t discuss specific assumptions regarding LNG fueling station boil-off

recovery technologies.
54

 Liquefied at the Clean Energy Fuels liquefaction plant in Boron, California,

 Transported via tank trucks to LNG fueling stations near the Ports of Long Beach

and Los Angeles, and

 Dispensed into heavy-duty LNG-fueled vehicles (with operating characteristics as

detailed in Reference 58).

For this pathway, the GHG emissions calculated by Reference 58 are:

WTT = 2,104 g-CO2eq/dge

TTW = 7,954 g-CO2eq/dge

WTW = 10,058 g-CO2eq/dge

The effect of additional atmospheric venting at the LNG fueling station can be

considered as a perturbation to these results. Venting at the station will have two

effects:

1. The methane escaping to the atmosphere will increase the WTT GHG emissions,

and this increase will be affected by the fact that the CO2 GHG equivalence of

methane is 2527.

2. If some of the LNG transported to the fueling station is vented to the atmosphere

and not dispensed into vehicles, more LNG must be delivered to the station in

order to maintain the same refueling throughput.

If the fraction of LNG that is vented at the station is small, these two effects can be

considered independently and then added without introducing a substantial error. For

this analysis, we consider a hypothetical case for which 1% of the LNG delivered to the

station is vented to the atmosphere. Therefore, for every 100 g of LNG delivered to the

station, 1 g will be vented and 99 g will be dispensed to vehicles. This 1 g of vented

methane vapor is equivalent to 25 g of CO2 emissions. Using the method of Reference

58 and the applicable diesel fuel and LNG heating values to reference this increase in

GHG emissions to diesel equivalent gallons dispensed to vehicles:

684 g CO / dge

47.4 Btu / g LNG

2,104 Btu / dge

99 g LNG

25 g CO

2eq

2eq

  















 



Therefore, venting 1% of the LNG at the station adds approximately 684 g-CO2eq/dge to

the WTT GHG emissions (effect #1 above), and the lost fuel requires the quantity of fuel

delivered to the station to be increased by approximately 1% (effect #2 above).

Therefore, the WTT GHG emissions with 1% venting at the station is:

2,816 g CO / dge

0.99

2,104 g CO / dge 684 g CO / dge

WTT 2eq

2eq 2eq

 

  



27 Different sources regard the CO2 GHG equivalence of methane to be between approximately 20 and

25. Here we use 25 to be consistent with References 57 and 58.
55

The TTW GHG emissions are unaffected, and so the WTW GHG emissions with 1%

venting at the station is:

WTW  2,816 g  CO2eq / dge  7,954 g  CO2eq / dge  10,770 g  CO2eq / dge

The increase in WTW GHG emissions associated with 1% of the delivered LNG being

vented at the fueling station is:

1.07

10,058 g CO / dge

10,770 g CO / dge

2eq

2eq







Thus, a very small percentage of venting at the LNG fueling station increases the WTW

GHG emissions of LNG-fueled heavy-duty vehicles (for this NA-LNG-CE pathway) by a

percentage that is approximately seven times the vented LNG percentage.

5.3 Criteria Pollutant Emissions

Criteria pollutant emissions of interest for transportation systems include reactive

organic gases (ROG), carbon monoxide (CO), oxides of nitrogen (NOx), particulate

matter28 (PM), and sometimes sulfur oxides (SOx). To compare the impacts of different

fuels and pathways on overall fuel cycle criteria pollutant emissions, the well-to-wheels

approach summarized in Section 5.2 is generally employed.

Reactive organic compounds, as defined by the California Air Resources Board (ARB),

specifically exclude certain compounds such as methane that have negligible

photochemical reactivity. The US Environmental Protection Agency (EPA) uses the

designation Volatile Organic Compounds (VOC), which is nearly the same thing as

ROG. The EPA also excludes photochemically non-reactive compounds such as

methane from the definition of VOC. Therefore, because LNG transportation fuel (and

especially LNG vapor) is almost all methane, atmospheric venting of LNG vapor at a

fueling station is not a ROG emission. Venting at the station does, however, increase

the quantity of LNG that must be delivered to the station in order to maintain the same

vehicle refueling throughput.

Consider the hypothetical case introduced in Section 5.2 for which 1% of the LNG

delivered to the fueling station is vented to the atmosphere. In this case, the quantity of

LNG delivered to the station must be increased by 1/0.99 in order to maintain the same

LNG vehicle refueling throughput. Therefore, vapor venting at the station increases all

WTT criteria pollutant emissions by a factor of 1/0.99, but the TTW criteria emissions

are unaffected.

For both diesel fuel and all credible LNG fuel pathways, the WTT portion of WTW

criteria pollutant emissions are quite small relative to the TTW portion. For example,

28 PM is usually subdivided into particle size ranges (e.g., PM10, PM2.5), but this distinction is unnecessary

for the purpose of this discussion.
56

Table 4, which is abstracted from Reference 58, lists the CA-GREET-predicted WTT,

TTW, and WTW criteria pollutant emissions, and the TTW/WTW ratio, for the NA-LNGCE pathway defined in Section 5.2. Urban criteria pollution emissions are tabulated in

tons per year for a heavy-duty LNG truck that averages 40,000 miles/year, has a 10-

year lifetime, and a fuel economy of 5 miles/dge. Other analysis assumptions are

detailed in Reference 58.

Criteria

Pollutant

WTT

(tons/yr)

TTW

(tons/yr)

WTW

(tons/yr)

WTT

WTW

ROG 0.0002 0.008 0.008 0.024

CO 0.0004 0.048 0.048 0.008

NOx 0.0009 0.061 0.062 0.015

PM2.5 0.00002 0.002 0.002 0.010

Table 4. Calculated criteria pollutant emissions for a heavy-duty LNG truck and a

North American natural gas to California liquefier and fueling station pathway

(from Reference 58).

Table 4 shows that, for this representative scenario, the WTT criteria pollutant

emissions (the only ones affected by station venting) are all much less than TTW

emissions (which are not affected by station venting). Consider NOx emissions, for

example. Based on the numbers in Table 4, a 1% increase in atmospheric venting at a

LNG fueling station would produce an overall WTW increase in NOx emissions of

approximately 0.015%. Changes this small should not be interpreted quantitatively

because they are beyond the precision of the model and input assumptions.

The overall conclusion is that atmospheric venting of vapor at LNG fueling stations can

have a substantial effect on WTW GHG emissions, but it has a negligible effect on

WTW criteria pollutant emissions.
57

Section 6

CONCLUSIONS AND RECOMMENDATIONS

6.1 Conclusions

How much fuel is lost due to atmospheric venting of vapor from LNG fueling stations,

LNG tank trucks, and LNG vehicles? The answer is that nobody knows. There have

been no documented attempts to directly measure venting losses. Indirect

measurement by subtracting the quantity of LNG dispensed to vehicles from the

quantity of LNG delivered to the station has not yielded definitive data because few LNG

stations perform this mass balance calculation and because the calculation is strongly

affected by “the difference between two big numbers” inaccuracies. A study conducted

in 1995 reported that, “75% of the stations surveyed vent excess vapors to the

atmosphere” (Reference 8), but the survey provided no information regarding the

quantity of vapor vented. Also, since 1995, LNG fueling station designs and operating

practices have advanced substantially, and average per-station utilization has

increased, both of which reduce venting. There have also been suggestions that, when

comparing the fuel consumption of otherwise-similar CNG and LNG heavy-duty

vehicles, the CNG vehicles appear to have slightly superior fuel economy, and the

difference may be due to LNG vapor venting. But this information is anecdotal,

undocumented, and not validated. Finally, expert opinions regarding the extent of vapor

venting associated with the LNG transportation fuel infrastructure range from

“negligible” to “substantial.”

While the magnitude of LNG fueling station vapor venting is quantitatively uncertain,

and it is clear that the GHG effects are infinitesimal relative to dozens of other sources

including cow flatulence (Section 1.2), there is general agreement that it is prudent to

design and operate LNG vehicle fueling stations so as to avoid or minimize atmospheric

venting of vapor. To this end, this report has sought to document what is known about

this subject, and some recommendations are summarized in the following subsections.

Recommended LNG fueling station design and operating practices to avoid or minimize

venting are listed in Section 6.2. Some areas of research and development that might

result in technologies that help to reduce atmospheric venting of LNG transportation fuel

vapors are suggested in section 6.3.

6.2 Best Practice Recommendations29

 While this is often easier said than done, project developers should ensure that LNG

fueling station capacities are well matched with LNG vehicle fleet characteristics so

as to minimize heat input accumulation and stored LNG saturation pressure

increases that might precipitate atmospheric venting. For example, the LNG storage

capacity should be consistent with the anticipated LNG dispensing throughput to

29 These recommendations are based on the use of current LNG fueling infrastructure technology.
58

enable full LNG tank truck deliveries that are frequent enough to avoid substantial

storage tank saturation pressure increases between deliveries.

 If the fueling station utilization is anticipated to be low (e.g., less than approximately

2,000 LNG gallons per day, although this threshold can vary substantially depending

on specific conditions), station planners should consider one of the following options:

– If anticipated station utilization is very low and not anticipated to increase:

Arrange to refuel vehicles at a nearby LNG station. If this is not possible,

reconsider the use of LNG-fueled vehicles.

– If station utilization is low and not anticipated to increase: Install a smallcapacity permanent station (e.g., skid-mounted) and plan for partial-load LNG

tank truck deliveries.

– If station utilization is initially low but anticipated to increase as more LNG

vehicles are deployed: Consider temporary use of a mobile or small skidmounted LNG fueling facility while a permanent LNG station is being planned

and installed.

– If initial utilization is low or highly sporadic, and/or future utilization is

uncertain: Consider installing a LNG fueling station with one of the excess

vapor recovery and utilization options discussed in Section 4.

 In almost all cases, LNG/LCNG fueling station plans should include equipment to

compress and dispense excess vapor as CNG, because the incremental cost of this

equipment is relatively low and this is a proven effective vapor management method.

 Plans for LNG tank truck delivery and offloading procedures should be carefully

developed and agreed on by the station owner/operator, the LNG supply contractor,

and the station designer. A key goal of these plans should be minimization of any

atmospheric venting of vapor from the station or tank truck during LNG deliveries.

 LNG fueling station designs should include a pump to transfer LNG from tank trucks

to the station storage tank. The pump and transfer system should be designed to

minimize any vapor generation and/or station heat input required to prime the

transfer pump. The station dispensing pump can be used for tank truck offloading, or

a separate dedicated offloading pump can be used if the time required for offloading

is a critical factor.

 Pressure transfer alone (i.e., without a pump) should never be used to transfer LNG

from a tank truck to a fueling station storage tank.

 Never expedite LNG tank truck deliveries by first blowing down the station storage

tank (i.e., venting vapor to the atmosphere) to reduce its pressure.

 LNG station designs and tank truck delivery procedures should employ a two-line

(LNG delivery and vapor return to the tank truck ullage) transfer system.
59

 LNG station designs and tank truck offloading procedures should be such as to

avoid or minimize any required vapor venting from the tank truck after transferring

LNG to the station (e.g., due to a pressure build needed to expedite transfer pump

priming).

 Personnel familiar with LNG fueling station operations should participate in LNG

vehicle procurement. For LNG vehicles not equipped with fuel pumps, engine fuel

supply pressure requirements should be taken into consideration. LNG vehicle

producers should ensure that the vehicle LNG fuel tank and system are designed

and installed so as to minimize the pressure drop from the fuel tank to the engine.

 LNG fueling station planners and designers should give careful consideration to the

best way to dispense fuel at the saturation conditions required by the vehicles being

refueled. If “conditioned” LNG dispensing is required, the choice between bulk and

on-the-fly conditioning should consider the latest demonstrated technologies,

reliability, initial and operating costs, and effects on potential vapor venting.

 If the LNG fueling station is anticipated to refuel vehicles that do and don’t require

conditioned LNG, station planners and designers should carefully consider the

tradeoffs (especially with respect to potential vapor venting) among:

1. Use of saturation-on-the-fly conditioning

2. Use of separate LNG storage tanks and dispensers for conditioned and nonconditioned LNG

3. Dispensing conditioned LNG to all types of LNG vehicles

 Never manage LNG fueling station storage tank pressure by constantly venting

vapor through a back-pressure regulator.

 LNG station designs should ensure that the initial quantity of fuel dispensed into

vehicle fuel tanks is liquid phase and at the lowest practical temperature. LNG

stations should be planned and designed to minimize heat addition to stored LNG

and any vapor generation associated with the dispenser cool-down process.

 LNG station planners and designers should carefully balance the need for a

dispensing pump with a high flow capacity (e.g., to expedite vehicle refueling and

possible bulk conditioning) and/or a high pressure ratio capability (e.g., to ensure

that LNG can be pumped into vehicle fuel tanks initially at a high pressure) with the

need to minimize heat input to the stored LNG.

 LNG vehicle fuel tanks should never be vented to the atmosphere. If vapor must be

offloaded to enable refueling, the vapor should be recovered and routed to the

station LNG storage tank.
60

6.3 Research and Development Recommendations

 A research effort to accurately quantify the extent of atmospheric venting associated

with the LNG vehicle fuel infrastructure would help to resolve uncertainties regarding

whether this is or is not a serious issue.

 Successful and cost-effective alternatives to bulk conditioning as a method for

addressing SING (and some DING) engine fuel supply pressure requirements would

provide multiple benefits possibly including increased LNG storage capacities,

enhanced station flexibility, less atmospheric venting, and improved economics.

Potential R&D areas in this regard include:

– On-vehicle fuel pressure increasing technologies

– Low-cost on-the-fly conditioning technologies

– New approaches to LNG vehicle fuel systems and/or refueling

 If vehicles that require refueling with conditioned LNG continue to operate for many

years into the future, better strategies to enable one LNG fueling station to

economically dispense LNG at the various saturation conditions best suited to

different types of LNG vehicles would be highly beneficial.

 Experience with LNG fueling station excess vapor recovery and utilization methods

is minimal and not well documented. A better understanding of the effectiveness and

costs of various options (especially those involving sale of natural gas or electricity

to local utilities) would benefit planners and designers of future LNG stations.

Implementation of trial projects at LNG stations could provide this information.

 Improved technologies in the related areas of net dispensed LNG fuel metering and

dispenser cool-down systems (e.g., to ensure that cold liquid is initially dispensed

into vehicles with no vapor venting and minimal heat rejected to stored LNG) would

significantly improve LNG fueling station functionality.

 LNG fueling stations and vehicles could benefit from cost-effective

pump/compressor technologies that can receive natural gas (NG) liquid-vapor

mixtures at their suction and discharge higher-pressure LNG (saturated or

subcooled) or supercritical NG. Such technologies, which have seen marginal

success in the past, could also enable less atmospheric venting of vapor.

 Transferring LNG from tank trucks to fueling stations may be one area where it is

impractical to completely eliminate all atmospheric vapor venting through prudent

use of current equipment. This dilemma might benefit from objective R&D to

reconsider the best overall LNG vehicle fuel infrastructure strategy (e.g.: Should the

transfer pump be at the fueling station or on the tank truck trailer?).

 The subjects of NGV fuel composition requirements, fuel composition effects on NG

engine emissions and fuel consumption, CARB CNG composition specifications,

LDC NG composition rules, composition specifications in LNG fuel supply contracts,
61

and LNG enrichment effects associated with venting are all intertwined in a

bewildering fashion. Any R&D that helps to unravel these issues and facilitate

broadly supported NG vehicle fuel composition specifications (at all levels) would be

highly beneficial.
62
63

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11. O’Brien, J., and Siahpush, A., “Investigation of Low-Cost LNG Vehicle Fuel Tank

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Meeting, Washington, D.C., April 26-28, 1999.
64

14. Moore, J, “Development of a Liquefied to Compressed Natural Gas (LCNG)

Fueling Station,” CVI Division of Chart Industries Final Report for Contract DEAC02-99CH10984, June, 1999.

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16. Wegrzyn, J., and Gurevich, M., “Liquefied Natural Gas for Trucks and Buses,” SAE

200-01-2210, presented at the SAE Government/Industry Meeting, Washington,

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17. Blue Fuels Group L.P., “Implementation of Advanced LCNG Fueling Infrastructure

in Texas Along the I-35 / NFTA Clean Corridor Project,” Final Report for DOE

Contract DE-AC02-99CH11012, May, 2001.

18. “Liquefied Natural Gas for Heavy-Duty Transportation,” Arthur D. Little Report FR01-101 for the Gas Technology Institute and Brookhaven National Laboratory,

May, 2001.

19. “Wiens, J., Powars, C., and Pope, G., “LNG Vehicle Fuel Pressure Strategy

Alternatives,” SAE 2001-01-1919, presented at the International Fuels & Lubricants

Meeting, Orlando, Florida, May, 2001.

20. Stephens, D., Herridge, J., and Gifford, M., “Reference Guide for Integration of

Natural Gas Vehicle Fuel Systems, “ Battelle report for GRI, DOE, SCAQMD, and

Transport Canada, GRI-02/0013, January, 2002.

21. Candler, K., Gifford, M., and Carpenter, B., ”Resource Guide for Heavy-Duty LNG

Vehicles, Infrastructure, and Support Operations,” GRI-02/0105, March, 2002.

22. Bach, R., “Omnitrans LNG-to-CNG Refueling Station Success,” APTA Bus and

Paratransit Conference, Milwaukee, Wisconsin, May 5, 2003.

23. Wegrzyn, J, “Processing, Transportation, and Storage of LNG,” presented at the

Natural Gas Vehicle Technology Forum, Albany, New York, Sept. 9-10, 2003.

24. “The Transit Bus Niche Market for Alternative Fuels, Module 4: Overview of

Liquefied Natural gas as a Transit Bus fuel,” part of the DOE Clean Cities

Coordinator Toolkit, prepared by TIAX LLC, Dec., 2003.

25. Chen, Q., Wegrzyn, J., and Prasad, V., “Analysis of Temperature and Pressure

Changes in Liquefied Natural Gas (LNG) Cryogenic Tanks,” Cryogenics (Elsevier),

Vol. 44, Issue 10, Oct. 2004.

26. Mackey, M. “LNG and Hydrogen Fueling Stations,” presented at the Southern

California Clean Vehicle Expo, Ontario, California, October 9-11, 2006.

27. Roche, G., “Fueling Infrastructure for Natural Gas Trucks,” presentation at the

Faster Freight – Cleaner Air California 2009 Conference, Long Beach, CA, March

23-25, 2009.

28. Timmerhaus, K.D., and Flynn, T.M., Cryogenic Process Engineering, Plenum

Press, NY, 1989.
65

29. SAE J2343, Recommended Practice for LNG Medium and Heavy-Duty Powered

Vehicles, July, 2008, SAE International, Warrendale, Pennsylvania.

30. Duggal, V., et al, “Development of the High-Pressure, Direct-Injected, Ultra LowNOx Natural Gas Engine: Final Report,” NREL/SR-540-35911, May, 2004.

31. Chart Industries, NexGen Fueling, On-Board Fueling systems

(http://www.nexgenfueling.com/p_onboard.html)

32. Westport, Cryogenic Storage & Delivery

(http://www.westport.com/business_dev/cryogenic.php)

33. Powars, C., and Derbidge, T., “LNG Vehicle High-Pressure Fuel System and ‘Cold

Energy’ Utilization,” DOE/ER/82468-2, March, 2001.

34. Harper, G., and Powars, C., “Advanced LNG Onboard Storage System (ALOSS),”

Cummins Westport Inc. Final Report for DOE Contract DE-FC36-02CH11138,

October, 2003.

35. Clean Vehicle Education Foundation, Natural Gas Vehicle Codes and Standards

(http://www.cleanvehicle.org/technology/image/code.pdf)

36. Chart Industries, NexGen Fueling, Codes, Standards & Advisories

(http://www.nexgenfueling.com/t_codes.html)

37. Alloy Custom Products, Inc., 13,000-gallon LNG transport trailer Model ACP ST-13

specifications (http://www.alloycustomproducts.com/uploads/ST13%20SALES%20INFO%201-2-06.pdf)

38. “MVE’s New LNG Station Design,” LNG Express (Zeus Development Corp.), Vol.

III, No. 1, Jan/Feb, 1993.

39. “Improvement in LNG Storage Tanks, Full-Scale Demonstration Testing,” Program

Status Report prepared by Cryogenic Fuels, Inc., for Brookhaven National

Laboratory Contract 723418, Nov., 1999.

40. Wilding, B., “Natural Gas Vehicle Program, INEEL,” presented at the Zeus

Development Corp. LNG: Prospecting Downstream Markets Conference, Colorado

Springs, Colorado, March 23-25, 1998.

41. Lenz, D., “Onboard Low-Pressure Fuel Delivery Systems,” presented at the LNG

as a Transportation Fuel SAE TOPTEC Meeting, Houston Texas, Jan. 25-27,

1993.

42. Miller, S., “LNG Usage in 2-Stroke Engines,” presented at the LNG as a

Transportation Fuel SAE TOPTEC Meeting, Houston Texas, Jan. 25-27, 1993.

43. “INL Technologies: LCNG Fueling Station, A ‘Natural’ Choice,”

(http://www.inl.gov/lng/factsheets/fuelingstation.pdf)

44. Flaring and Venting Reduction & Natural Gas Utilisation Forum, Amsterdam, Dec.

3-5, 2008 (http://www.flaringreductionforum.org/)

45. The EPA Natural Gas STAR Program (http://www.epa.gov/gasstar/)

46. The EPA Landfill Methane Outreach Program (http://www.epa.gov/lmop/)
66

47. The Methane to Markets Partnership, an international program steered by the US

EPA (http://www.methanetomarkets.org/)

48. Vapor Management Option Study, by Jim Lewis, PTL, which is part of unpublished

Barstow, California, LNG fueling station project planning materials provided by Erik

Neandross, Gladstein, Neandross & Associates, Jan., 2010.

49. Personal communication. Dennis Elefante, Orange County Transportation

Authority, Garden Grove, California, March, 2002.

50. Kountz, K., et al, “Development of a Small-Scale Natural Gas Liquefier,” GTI03/0101, April, 2003.

51. GTI Small-Scale Liquefier Development

(http://media.godashboard.com/gti/1ResearchCap/1_2EnergySyst/LiquefierOvervie

wBrief1205new.pdf)

52. Millang, H., “Possibilities and Barriers with Small-Scale LNG,” presented at the

Flaring and Venting Reduction & Natural Gas Utilisation Forum, Amsterdam, Dec.

3-5, 2008.

53. Kunert, S., and Larsen, O., “Small is Beautiful – Mini LNG Concept,” Hamworthy

Gas Systems AS presentation (http://www.dge- wittenberg.com/vortraege/

Small_is_beautiful_Hamworthy_MiniLNG_Concept_June_2008.pdf)

54. “LNG – L/CNG Fueling Station,” charts distributed by The Hanover Company at the

Southwest Transportation Agency Caruthers, California, LNG/LCNG station

inauguration ceremony, April 1, 2005.

55. Argonne National Laboratory, The Greenhouse Gases, Regulated Emissions, and

Energy Use in Transportation (GREET) Model, March, 2009

(http://www.transportation.anl.gov/modeling_simulation/GREET/index.html)

56. TIAX LLC, “Full Fuel Cycle Assessment: Well-to-Wheels Energy Inputs, Emissions,

and Water Impacts,” CEC-600-2007-004-REV, August, 2007.

57. California Air Resources Board, “Detailed California-Modified GREET Pathway for

Liquefied Natural Gas (LNG) from North America and Remote Natural Gas

Sources,” Version 1.0, July, 2009

(http://www.arb.ca.gov/fuels/lcfs/092309lcfs_lng.pdf)

58. Rosenfeld, J., and Jackson, M., “Life-Cycle Cost Estimator and Pollutant

Emissions Estimator – Greenhouse Gas and Criteria Pollutant Estimator,” TIAX

LLC report prepared for Westport Innovations Inc., March, 2008.

(http://www.westport.com/pdf/GHG_and_Criteria_Pollutant_Emissions_Estimator.p

df)
A-1

Appendix A

LNG Tank Pressure, Temperature, Ullage Fraction,

Heat Leak, Hold Time, and Venting Rate Relationships
A-2

A-1. Purpose

LNG tanks at fuel stations, on LNG-fueled vehicles, and LNG tank trucks, are vacuumjacketed cryogenic vessels designed to minimize the rate of heat transfer from the

environment to the LNG (the “heat leak”). Common cryogenic tank design features are

described in many articles and textbooks (e.g., Reference A-1). If no product is

withdrawn from or added to the tank, the heat transferred to the LNG increases its

internal energy, pressure, and temperature. The mass and volume ratios of the liquid

and vapor phases in the tank also shift in subtle ways. The tank volume occupied by the

vapor phase is referred to as the ullage. If and when the ullage decreases to zero, the

tank is said to be liquid full, which is a situation that should be avoided for safety

reasons.

Safe practice, as well as various codes and standards, requires LNG tanks to be

equipped with a pressure relief device (PRD). The PRD must discharge (usually vent)

some of the tank contents when the tank pressure increases to no greater than the tank

maximum allowable working pressure (MAWP). Because it is much safer to vent vapor

than liquidA-1(and a liquid-full condition is to be avoided as previously discussed),

cryogenic tanks are constructed so that the PRD communicates with the ullage.

Two closely related figures-of-merit that depend on the tank’s heat leak characteristics

are hold time and normal evaporation rate (NER). Hold time (also called time-to-vent) is

the elapsed time between when the tank is filled and when it vents (because the

pressure increases to the PRD set point) if no product is withdrawn. There is some

ambiguity to published hold times if the filling conditions (i.e., cryogen, saturation state,

ullage fraction) are not specified. NER is the rate of product withdrawal that maintains

the remaining product at a constant saturation pressure and temperature. NER is

almost always expressed as a percent per day (%/day), where the percentage is

defined as the vapor mass withdrawn daily relative to the full tank product mass.

Published NER numbers can also be ambiguous if the cryogen and withdrawal pressure

(i.e., atmospheric or PRD pressure?) are not specified.

With certain simplifying but generally applicable assumptions, mass and energy

conservation laws can be combined with the cryogen’s thermodynamic properties to

calculate important relations involving the tank pressure, temperature, ullage fraction,

heat leak, hold time, and venting rate (or NER). The purpose of this appendix is to

summarize the pertinent assumptions and equations and illustrate how these are

applied to calculate various LNG tank characteristics. The more general discussion in

this appendix provides a technical basis for the example graphs shown and described in

Section 2 of the main text.

A-1

It is also more effective to vent vapor. Because the enthalpy of saturated vapor is greater than that of

saturated liquid, removal of a given mass of vapor decreases the tank pressure and temperature more

than removal of the same quantity of liquid.
A-3

A-2. Assumptions

The LNG is all methane.

This assumption simplifies calculations because it avoids highly compositiondependent multi-component multi-phase calculations. It produces results that

are accurately applicable to most currently used LNG transportation fuels.

Implications of LNG components other than methane are discussed in

Appendix B.

When a tank contains both liquid and vapor phases, they are in thermodynamic

equilibrium, i.e., both phases are saturated.

If there is negligible stratification (see below), this is a reasonable assumption

if the tank contents have “settled” for a period of time, but it is not applicable

to tanks that have recently received a pressure-build to create a “false head.”

The liquid in the tank is not significantly stratified, i.e., all the liquid has the same

temperature and density.

This is a reasonable assumption for smaller tanks but not for large tanks that

have been left undisturbed for a substantial time (see Reference A-1 for

details).

Methane’s equation of state and thermodynamic properties are accurately modeled by

relations published by the National Institute of Standards and Technology (NIST).

See Reference A-2.

A-3. Equations

The equations needed to relate LNG tank pressure, temperature, ullage fraction, heat

leak, hold time, and venting rate are: conservation of mass and energy, a tank volume

equation, and the methane’s thermodynamic properties as noted in Section A-2.

VL Vv VT

Tank volume occupied by liquid and vapor :

Q mh

dt

dU

Energy conservation :

m

dt

dM

Mass conservation :

 

 

 






A-4

T denotes total tank

v denotes vapor phase

L denotes liquid phase

Subscripts :

t time

ρ density

u unit internal energy

h unit enthalpy of fluid (vapor or liquid) flowing out of tank

V volume

Q rate of heat transfer into tank

m mass flow rate out of tank

U total internal energy in tank ρ V u ρ V u

M total fluid mass in tank ρ V ρ V

Where :

L L L v v v

L L v v















  

  





Subject to the assumptions listed in Section A-2, these equations can be combined with

methane’s equation of state and thermodynamic properties to calculate various relations

among pressure, temperature, ullage fraction, heat leak, and venting rates for vessels

containing natural gas liquid and vapor. The specific mathematical manipulations are

straightforward and will not be detailed here.

These equations can be combined to express the pressure rise rate (and ullage fraction

change) of a tank with a known heat leak rate and no outflow or inflow, for example. Or,

the vapor outflow rate can be calculated for a tank venting at a constant pressure. This

relation can be applied to calculate the heat leak rate from a tank normal evaporation

rate (NER) specification. This venting or “boil-off” rate is sometimes estimated as the

heat leak rate divided by the fluid heat-of-vaporization at the venting pressure (e.g.,

Reference A-3):

m Q / (h h )  v  L

 

Examination of the prior equations shows that this relation is an approximation obtained

by assuming that the vent rate is equal to the liquid vaporization rate (i.e., neglecting the

mass accumulation in the increasing ullage space) and assuming that the internal

energy and enthalpy of the liquid phase are equal. Both of these effects are usually

small, and the error associated with this approximate equation is usually less than 1%.
A-5

A-4. LNG Quantitative Measurement and “LNG Gallons”

Liquid transportation fuels such as gasoline and diesel fuel are traditionally quantified in

terms of gallons (or liters in most non-US countries), which is a volume measurement.

For cryogenic liquids such as LNG, which are usually transported, stored, and

dispensed at or near saturation, the liquid density depends strongly on temperature and

pressure, and so the mass in a gallon at one condition may be substantially different

from the mass in a gallon at another condition. For example, for high-purity LNG, a

gallon at 20 psig weighs 3.38 Lbm, but a gallon at 120 psig weighs 3.03 LbmA-2

(i.e.,10.4% less).

For this reason, LNG supply contracts and pricing is usually based on fuel mass rather

than volume. However, there is still a strong preference to discuss LNG vehicle fuel

quantities in terms of gallons. An approach that minimizes the ambiguity of this unit of

measurement is to define a “LNG gallon” as the mass of fuel in one gallon of allmethane LNG saturated at one atmosphere of absolute pressure (14.7 psia), which is

3.53 Lbm. We accept this convention so that, in this document, regardless of pressure

and temperature:

One “LNG gallon” means 3.53 pounds of LNG

A-5. Example LNG Property and Quantity Graphs

The following figures are graphs that illustrate example relationships among LNG

properties based on the assumptions discussed in Section A-2 and equations listed in

Section A-3. These examples are selected to be applicable to issues of interest for LNG

fueling stations. The pertinent application, assumptions, and implications are

summarized in the captions beneath each graph.

A-2 Graphs of LNG density are in Appendix B.
A-6

0

20

40

60

80

100

120

140

160

180

200

0 10 20 30 40 50 60 70

Elapsed Time ( days )

S

aturation Pre

s

sure ( p

sig )

A: LNG tank heat leak only

B: LNG tank heat leak

and LNG dispensing

(including heat from

pump & sump)

(Initial saturation pressure = 20 psig)

( 175 psig PRD)

C: LNG tank heat leak and LNG dispensing

(including heat from pump & sump) and vapor

withdrawal (e.g., for CNG refueling)

(venting at 64 days)

(all liquid consumed at 24 days)

(all liquid consumed at 23 days)

Figure A-1. Illustration of the saturation pressure rise of LNG stored in a 15,000-gallon

LNG tank at a station with low utilization. Three different liquid and vapor

withdrawal schedules are shown. For all cases, key assumptions are: LNG

is 100% methane, all tank contents are saturated at the same pressure and

temperature, tank is filled with 12,295 gallons of LNG (= 43,347 pounds of

LNG) at an initial saturation pressure of 20 psig (which provides a 14.5%

ullage, which is the minimum ullage to ensure that the tank is not liquid-full

at the assumed 175-psig PRD pressure).

A. No liquid or vapor withdrawal; heat leak = 35,000 Btu/day (which

corresponds to NER = 0.3%/day of methane at 1 Atm.)

B. Time-averaged LNG dispensing rate = 500 gallons/day = 1,763 Lbm/day

(e.g., refueling 5 vehicles/day X 100 LNG gal/vehicle), heat leak =

35,000 Btu/day (as in A) plus 10,000 Btu/day associated with LNG pump

and sump operation.

C. Time-average LNG dispensing rate = 500 gallons/day = 1,763 Lbm/day

(as in B), heat leak = 35,000 Btu/day plus 10,000 Btu/day associated

with LNG pump and sump operation (as in B), plus vapor withdrawal

(e.g., compressed into storage vessels for CNG vehicle refueling) of

4,158 SCF/day (which is 176 Lbm/day, i.e., 10% of LNG withdrawal).
A-7

0

20

40

60

80

100

120

140

160

180

200

0 5 10 15 20 25 30 35

Elapsed Time ( days )

S

aturatio

n

Pre

s

s

ure ( p

sig )

( 175 psig PRD)

(Initial saturation pressure = 120

psig) B: LNG tank heat leak and

LNG dispensing (including

heat from pump & sump)

A: LNG tank heat leak only

C: LNG tank heat leak and LNG dispensing

(including heat from pump & sump) and vapor

withdrawal (e.g., for CNG refueling)

(venting at 14 days) (venting at 16 days)

(all liquid consumed at 23 days)

Figure A-2. Illustration of the saturation pressure rise of LNG stored in a 15,000-gallon

LNG tank at a station with low utilization. Three different liquid and vapor

withdrawal schedules are shown. For all cases, key assumptions are: LNG

is 100% methane, all tank contents are saturated at the same pressure and

temperature, tank is filled with 12,295 gallons of LNG (= 43,347 pounds of

LNG) at an initial saturation pressure of 20 psig (which provides a 14.5%

ullage, which is the minimum ullage to ensure that the tank is not liquid-full

at the assumed 175-psig PRD pressure), and tank contents are then

“conditioned” to a saturation pressure of 120 psig.

A. No liquid or vapor withdrawal; heat leak = 35,000 Btu/day (which

corresponds to NER = 0.3%/day of methane at 1 Atm.)

B. Time-average LNG dispensing rate = 500 gallons/day = 1,763 Lbm/day

(e.g., refueling 5 vehicles/day X 100 LNG gal/vehicle), heat leak =

35,000 Btu/day (as in A) plus 10,000 Btu/day associated with LNG pump

and sump operation.

C. Time-average LNG dispensing rate = 500 gallons/day = 1,763 Lbm/day

(as in B), heat leak = 35,000 Btu/day plus 10,000 Btu/day associated

with LNG pump and sump operation (as in B), plus vapor withdrawal

(e.g., compressed into storage vessels for CNG vehicle refueling) of

4,158 SCF/day (which 176 Lbm/day, i.e., 10% of LNG withdrawal).
A-8

0

20

40

60

80

100

120

140

160

0 2 4 6 8 10 12

Elapsed Time ( days )

Saturation Pressure ( psig )

0

5,000

10,000

15,000

20,000

25,000

L

N

G in Tank ( "L

N

G

gallons" )

1,000 LNG gallons dispensed

between 5 PM and 9 PM each day

(10-day

cycle

repeats)

10,000 LNG gallons added to storage tank

every 10 days (12 noon - 1 PM)

LNG in storage tank conditioned to

120 psig (1 PM - 3 PM)

Saturation pressure

Tank contents

Figure A-3. Hypothetical example LNG fueling station with 15,000 gallon storage tank,

showing the saturation pressure and LNG content variation between LNG

deliveries. Conditions and assumptions:

 Station utilization: 1,000 LNG gallons dispensed each day between 5 PM

and 9 PM (e.g., 10 vehicles refueled daily with 100 gallons)

 Tank truck deliveries: 10,000 LNG gallons (saturated at 20 psig)

transferred to station between 12 noon and 1 PM every 10 days

 Storage tank contains 2,564 LNG gallons (saturated at 143 psig) just prior

to deliveries, so that ullage fraction is approximately 10% after delivery

 Between 1 PM and 3 PM following each delivery, the LNG is conditioned

to raise its saturation pressure to 120 psig

 Tank heat leak = 35,000 Btu/day (which corresponds to NER = 0.3%/day

of methane at 1 Atm) plus 10,000 Btu/day associated with LNG pump and

sump operation

 LNG is 100% methane and all tank contents are saturated at the same

pressure and temperature
A-9

0

20

40

60

80

100

120

140

160

180

0 2 4 6 8 10 12 14 16 18

Elapsed Time ( days )

S

aturation Pre

s

sure ( p

sig )

0

5,000

10,000

15,000

20,000

25,000

30,000

L

N

G in T

ank ( "L

N

G

g

allons" )

1,000 LNG gal/day dispensed during 4-hr window

500 LNG gal/day dispensed during 2-hr window

(175 psi PRD)

Conditioning

to 120 psig

10,000 gal

added to tank

For this scenario, LNG storage tank

refilled every 10 days, and cycle repeats

For this scenario, LNG

storage tank starts venting

in ~15 days

Figure A-4. Effect of LNG fueling station utilization on 15,000-gallon storage tank

saturation pressure and LNG content variation. Key assumptions are

identical to those listed for Figure A-3. The 1,000 LNG gallon/day utilization

scenario results in a 143-psig saturation pressure and 2,564-gallon LNG

residual just prior to a tank truck delivering 10,000 gallons every 10 days (as

in Figure A-3). The 500 LNG gallons/day utilization scenario (e.g., 5 vehicles

refueled in 2 hours every day with 100 gallons) would result in the tank

saturation pressure reaching the assumed 175-psig PRD pressure in 15

days with 5,064 gallons remaining in the storage tank. This low-utilization

scenario would require a smaller storage tank with more frequent deliveries

of lower LNG quantities (or some form of active vapor management) to

avoid atmospheric venting.
A-10

0

50

100

150

200

250

0 5 10 15 20 25 30 35 40 45 50

Elapsed Time (days)

Saturation Prassure (psig) &

Ullage (%)

0

1

2

3

4

5

Venting Rate (LN

G gallons equivalent / day)

(230 psi PRD)

Pressure

Ullage %

5 days

(brief increase in venting as liquid is exhausted

and tank warms to ambient temperature)

Venting

rate

0

50

100

150

200

250

0 5 10 15 20 25 30 35 40 45 50

Elapsed Time (days)

Saturation Prassure (psig) &

Ullage (%)

0

1

2

3

4

5

Venting Rate (LN

G gallons equivalent / day)

(230 psi PRD) Pressure

Ullage % 13.4 days

(brief increase in venting as liquid is exhausted

and tank warms to ambient temperature)

Venting

rate

Figure A-5. Pressure rise rate, time-to-vent, venting rate, and ullage fraction variation for

hypothetical 115-gallon LNG vehicle fuel tank with a 230-psig PRD that is

left dormant (e.g., vehicle not driven). The top graph is for this tank and a 5-

day hold time and a 10% ullage (minimums required by SAE J2343,

Reference A-4) when filled with LNG saturated at 120 psig. This hold time

implies a heat leak of 1,485 Btu/day = 18.1 Watts. If no fuel is used, after 5

days, this tank will vent at 8.7 Lbm/day (= 2.5 LNG equivalent gallons / day)

until it is empty (assuming ideal PRD behavior). The bottom graph is for the

same tank filled with LNG saturated at 20 psig, which requires a 18% ullage

in order to avoid a liquid-full condition at the PRD pressure. This fill

condition would provide a hold time of approximately 13 days.
A-11

0

5

10

15

20

25

30

35

40

45

50

0 50 100 150 200 250

Starting and Ending Saturation Pressure ( psig )

Pro

d

u

ct L

o

s

s ( %

of startin

g liq

uid

m

a

s

s )

Solid curves denote tank initially 10% full

Broken curves denote tank initially 50% full

Figure A-6. Product loss associated with vapor venting to reduce the saturation

pressure in an LNG tank of any capacity containing both liquid and vapor

phases (sometimes referred to as tank “burping”).

Example illustrating quantitative use:

 Problem: A 50% full 15,000-gallon LNG tank is vented to reduce its

saturation pressure from 200 psig to 100 psig. How much vapor must be

vented?

 Solution: Select the broken (50% full) curve that originates from 200

psig. At 100 psig on the horizontal scale, read 14% on the vertical scale.

The vapor mass vented is 0.14 x 21.24 Lbm/ft3(saturated liquid density

at 200 psig, e.g., from Appendix B) x 0.5 x 15,000 gal ÷ 7.48 gal/ft3=

2,980 Lbm. And 2,980 Lbm ÷ 3.53 Lbm/LNG gallon = 844 LNG gallons.

 Answer: 14% of the tank contents must be vented. This is equivalent to

844 LNG gallons.
A-12

76

78

80

82

84

86

88

90

92

94

96

98

100

0 20 40 60 80 100 120 140 160 180 200 220 240 260

Pressure Relief Valve Setting ( psig )

M

a

ximum

Liquid

P

erc

enta

g

e ( = 10

0 - Ulla

g

e

P

erc

enta

g

e )

0

204060

80

100

200

120140160180

Tank Saturation Pressure After Filling ( psig )

Figure A-7. LNG tank maximum liquid filling percentage in order to avoid a liquid-full

condition if no liquid or vapor is withdrawn and the saturation pressure

increases to the PRD pressure. Note that this maximum liquid filling

percentage is 100 - the ullage percentage.

Example (illustrated by broken-line arrows):

 Problem: A LNG tank with a 230-psig PRD is to be filled so that its

settled saturation pressure is 100 psig after filling, and substantial time

may lapse before any LNG is withdrawn. To what level can the tank be

filled?

 Answer: As indicated by the arrows, the tank should be filled so that

LNG occupies no more than 89.7% of its total volume (i.e., A 10.3%

vapor ullage). If it is filled with a higher percentage of liquid, it will

become liquid-full (0% ullage) before the saturation pressure increases

to the PRD pressure. This shortens the hold time and produces

potentially dangerous situation.
A-13

0

0.2

0.4

0.6

0.8

1

1.2

0 10 20 30 40 50 60 70 80 90 100

% Liquid by Volume

H

e

at L

e

a

k / ( Pre

s

s

ure

Ris

e

R

ate

x

V

olu

m

e )

[ W

att-h

o

ur / p

si-g

allo

n ]

Saturation pressure:

10

20

30

40

50

100

150

200

230

5 psig

Tank contents follow

these curves during

pressure build-up

Figure A-8. Generalized graphical representation of the relations among various

quantities of interest for any LNG tank containing a saturated methane liquid

and vapor mixture and for which nothing is added or withdrawn. For

example, this graph shows the saturation pressure rise rate (and therefore,

hold time) for any tank with a known heat leak, volume, and fill condition. It

also shows the ullage change with increasing saturation pressure.
A-14

References to Appendix A

A-1 Timmerhaus, K., and Flynn, T., Cryogenic Process Engineering, Plenum Press,

New York

A-2 Friend, D., Ely, J., and Ingham, H., National Bureau of Standards Technical Note

No. 1325, 1989 (see also: same authors, “Thermal Properties of Methane,” J.

Phys. Chem., Ref. Data, Vol.18, No. 2, 1989, pp. 583-638)

A-3 Chen, Q., Wegrzyn, J., and Prasad, V., “Analysis of Temperature and Pressure

Changes in Liquefied Natural Gas (LNG) Cryogenic Tanks,” Cryogenics, Vol. 44,

Issue 10, October 2004, pp. 701-709

A-4 SAE J2343, Recommended Practice for LNG Medium and Heavy-Duty Powered

Vehicles, July, 2008, SAE International, Warrendale, PA
B-1

Appendix B

METHANE PHASE DIAGRAM
B-2

This appendix contains graphs illustrating various aspects of methane’s phase diagram.

All graphs show the saturated liquid and saturated vapor curves (i.e., corresponding to

the temperatures and pressures at which the phases coexist in equilibrium).

Quantitative values are based on the thermodynamic property data in Reference B-1.

-350

-300

-250

-200

-150

-100

-50

0

-100 0 100 200 300 400 500 600 700

Pressure ( psig )

T

e

m

p

erature (

o

F )

VAPOR REGION

LIQUID REGION

Saturation Line

Atmospheric

pressure

Critical

point
B-3

0

100

200

300

400

500

600

700

800

900

1,000

0 5 10 15 20 25 30

Density ( Lbm / ft3)

Pre

s

s

ure ( p

sig )

LIQUID

REGION

LIQUID + VAPOR

REGION

VAPOR

REGION

Saturation Line

SUPERCRITICAL

REGION Example

isotherm

(-180°F)

-350

-300

-250

-200

-150

-100

-50

0

0 5 10 15 20 25 30

Density ( Lbm / ft3)

T

e

m

p

erature (

o

F )

VAPOR

LIQUID + VAPOR

REGION

LIQUID

REGION

Saturation Line

SUPERCRITICAL

REGION

Example

isobar

(200 psig)
B-4

-100

0

100

200

300

400

500

600

700

800

-200 -150 -100 -50 0 50 100 150

Enthalpy & Internal Energy ( Btu/Lbm )

Pre

s

s

ure ( p

sig )

Enthalpy

Internal energy

VAPOR

LIQUID

Saturation lines

Reference to Appendix B

B-1 Friend, D., Ely, J., and Ingham, H., National Bureau of Standards Technical Note

No. 1325, 1989 (see also: same authors, “Thermal Properties of Methane,” J.

Phys. Chem., Ref. Data, Vol.18, No. 2, 1989, pp. 583-638)