Methane glossary
Climate change
THE GLOBAL OIL AND GAS
INDUSTRY ASSOCIATION
FOR ENVIRONMENTAL
AND SOCIAL ISSUES
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Methane glossary
2 — Methane glossary
Contents
Introduction 3
Methane sources 5
Emission estimation methodologies 17
Methane detection and measurement technologies 20
and work practices
General terms 25
Acronyms 26
Bibliography 27
Further reading 33
Section 1
3 — Methane glossary
METHANE IN CONTEXT
Natural gas can play an important role as part of the global energy mix in a lowercarbon
future, provided that levels of methane emissions from the extraction,
processing and transmission of natural gas to the end user are limited. Due to the
relatively short-lived but potent warming effects understood to be associated with
methane, there is increasing focus on actions by the oil and gas industry (as well
as other sectors) to increase reporting and further reduce methane emissions.
To enhance understanding of these issues, IPIECA has undertaken a range of
activities including:
l a workshop and report on short-lived climate forcers;
l a fact sheet entitled Exploring methane emissions; and
l a methane workshop, held jointly with the Oil and Gas Climate Initiative (OGCI),
discussing the current gaps in knowledge, and considering data, studies and
measurements from a wide range of oil and gas operations globally.
The objectives of this glossary are to support the industry and other stakeholders
in the use of consistent terminology, and to improve confidence in understanding
and managing methane emission sources to further improve performance in
reducing methane emissions.
ABOUT THE GLOSSARY
This glossary is part of IPIECA’s efforts on the topic of methane emissions. It is
intended to provide additional details for some of the key terms used within the
methane discourse, and aims to provide a clear and consistent description of
each term. The glossary details the technical information related to each term
and, where deemed pertinent, provides additional contextual information
(highlighted in italics) to further support a clear and consistent understanding of
the term being described. The descriptions used in this text are based upon
publicly available documentation, academic papers and industry experience.
Introduction
Section 1
Introduction
4 — Methane glossary
Any scientific concepts and terms referred to in the glossary are not internal to
IPIECA or its members unless otherwise specified.
The terms ‘methane leakage’, ‘methane loss’, ‘methane emissions’ and ‘fugitives’
are often used interchangeably to refer to methane emitted to the atmosphere
from equipment, infrastructure and processes. There is often no differentiation
between sources of methane emissions that are planned (e.g. gas pneumatics,
tanks) and those that are unintentional (e.g. through joints, connections, etc.).
Throughout this glossary the term ‘methane emissions’ will be used.
It should be noted that, throughout this document, the use of the term ‘gas’
refers to ‘natural gas’, unless specifically stated otherwise.
It is important to note that the type of gas asset or gas value chain is often a
material factor in the presence or absence of methane emission sources, and will
further impact the overall scale of methane emissions for the asset or value
chain. As an example, the main sources of methane emissions found in onshore,
dispersed oil and gas operations are typically different from those sources found
in offshore operations. Care should therefore be taken when drawing global,
industry-level conclusions about data, mitigation potential and costs based on
information from a specific region or type of activity.
Section 2
5 — Methane glossary
This section details some of the main
sources of methane emissions, providing
context around what they are, where
they are found and why they occur. This
list is not exhaustive. As stated
previously, it is important to note that
the type of gas operation, e.g. onshore
dispersed versus offshore, is often
directly linked to the prevalence and
significance of certain methane sources.
The elimination of a methane source is
the preferred solution where technical
and economically feasible. However,
routing the gas to a flare system is also
an acknowledged mitigation practice as
the methane, which is a primary
component of natural gas, is combusted
to carbon dioxide which is understood to
have a lower global warming potential.
BLOW-DOWN/DEPRESSURIZING
The depressurization and purging of
piping, pipelines, compressors, vessels and
other equipment under controlled
conditions prior to maintenance and,
potentially, when the equipment is taken
offline. Piping, compressors, vessels and
other equipment may also depressurize
when operational upsets or abnormal
conditions occur.
Natural gas from depressurization activities
may be recovered as fuel, or routed to a
flare system or an atmospheric vent.
CASINGHEAD GAS
In the context of methane emissions, this is
gas which builds up in the tubing/casing
annular space in marginal ‘stripper’ oil wells
with a low gas-to-oil ratio (GOR). Methane
emissions occur when this gas is vented to
reduce annular pressure and enhance flow
from the reservoir into the wellbore,
thereby increasing oil production.
Additional information
The GOR indicates gas volume in relation to
the oil extracted under standard conditions.
It can be reported, for example, in units of
standard cubic feet per barrel.
COMPRESSOR
Equipment which can be responsible for
several potential equipment-specific
sources of methane emissions that vary
according to the type and design of the
compressor and compressor seals. Each
unique compressor-related source is
defined and discussed separately in the
following text.
Methane sources
Section 2
Methane sources
6 — Methane glossary
These unique sources are:
l centrifugal compressor dry seal buffer
gas vent/leakage;
l centrifugal compressor wet seal
degassing tank vent;
l reciprocating compressor rod-packing
leakage; and
l blow-down vent valve or isolation vent
valve leak-through/leakage.
Additional information
It is relevant to note that, in addition to the
compressor-specific sources described in
more detail below, compressors also have
components that are typically associated
with other types of equipment and emission
source categories, e.g. valves and pneumatic
controllers.
l Centrifugal compressor dry (gas) seals:
mechanical face seals, consisting of a
mating (rotating) ring and a primary
(stationary) ring. During operation,
grooves in the mating ring generate a
fluid-dynamic force causing the primary
ring to separate from the mating ring,
creating a ‘running gap’ between the
two rings.
Inboard of the dry gas seal is the
inner labyrinth seal, which separates the
process gas from the gas seal. A sealing
gas is injected between the inner
labyrinth seal and the gas seal,
providing the working medium for the
running gap and the seal between the
atmosphere or flare system and the
compressor internal process gas.
Outboard of the dry gas seal is a barrier
seal, which separates the gas seal from
the compressor shaft bearings. A
separation gas (typically nitrogen or air)
is injected into the barrier seals.
Typical dry gas seal assemblies are
‘tandem’ seals which consist of a primary
seal and a secondary seal contained
within a single cartridge. During normal
operation, the primary seal absorbs the
total pressure drop to the user’s vent
system, and the secondary seal serves as
a backup should the primary seal fail
(Stahley, 2002).
Additional information
Emissions from a dry seal are of the seal
gas itself, typically a cleaned and
conditioned natural gas, rather than the
process gas internal to the compressor.
The seal gas flow rate into the seal
assembly is controlled to maintain
adequate flow velocity across the inner
labyrinth seal to prevent process gas
from the compressor flowing into the
seal assembly. Most of the seal gas flows
into the compressor case across the
labyrinth seal, with a small portion
flowing between the mating and
primary rings where it is vented from the
seal assembly primary seal vent and may
be routed to an atmospheric vent or
flare system.
Section 2
Methane sources
7 — Methane glossary
Some seal gas will flow between the
secondary seal mating and primary rings,
and exit the seal assembly from the
secondary seal vent which may be
routed to an atmospheric vent or flare
system. A typical centrifugal compressor
will have two seal assemblies—one at
each end of the compressor shaft.
l Centrifugal compressor wet seals:
a seal system that uses special seal-oil,
which is circulated internally to the seal
assembly under higher pressure than
the gas in the adjacent compressor
case, and which serves as the sealing
fluid/mechanism. Wet seals can be
mechanical seals, with the seal oil
providing liquid film sealing, lubrication
and cooling.
Seal oil acts as a liquid film and barrier
fluid, for example between the rings
around the compressor shaft (similar to
a dry gas seal). Wet seals have an
inboard labyrinth seal that keeps
higher-pressure seal oil from flowing
into the compressor case. The inboard
seal oil comes into contact with the
process gas and is contaminated with
entrained and absorbed gas (this
contaminated seal oil is often called
‘sour seal oil’). The outboard seal oil
does not come into contact with the
process gas and, hence, is not
contaminated. Inboard contaminated
seal oil is routed to an atmospheric
pressure degassing tank where the
entrained and absorbed gas is removed
prior to recirculation.
seal oil inlet
process gas leaks
through ÔinboardÕ
labyrinth seals
compressor
side ÔinboardÕ
spinning shaftseal oil
(contaminated with gas)
seal oil
(uncontaminated)
ÔoutboardÕ
labyrinth
motor and
shaft bearing
side ÔoutboardÕ
seal housing
Example of a typical centrifugal compressor with wet seal assemblies
(Source: US EPA (2006)
Section 2
Methane sources
8 — Methane glossary
Very little gas escapes through the oil
seal barrier and emissions are typically
from the degassing tank vent, in those
cases where the entrained and absorbed
gas is vented (as opposed to recycled or
flared). Many seal-oil systems have a
‘sour seal-oil trap’ (essentially a small
separator) where the majority of the
entrained and absorbed gas is removed
from the seal oil at higher pressure and
routed to a recovery or flare system
before it reaches the seal oil degassing
tank (newer systems use dry seals).
Additional information
A typical centrifugal compressor will
have two seal assemblies, one at each
end of the compressor shaft, and one
seal-oil degassing tank serving both seal
assemblies.
l Reciprocating compressor rod
packing: consists of a series of
mechanical rings, contained in a
packing case, that provide a seal against
the piston rod to restrict the leakage of
compressed gas from the compressor
cylinder along the compressor rod. Rod
packing designs and materials vary
according to operating and process
conditions. Different compressor duties
require different packing ring designs
and material selection. The gas
properties, pressure differentials,
compressor speed and type of service
are all used to determine the proper
combination of ring style and material
that will provide the optimum pressure
seal and oil wiping.
Additional information
A reciprocating compressor will have a
rod packing assembly on each cylinder
or ‘throw’. For example, a compressor
with four cylinders will have four rod
packing assemblies.
Pressure packing assemblies typically
have a packing case vent designed to
enable gas that has leaked past the
sealing rings to be vented to a safe
location. These packing case vents can
be routed either to an atmospheric vent
or flare system. Any gas leakage not
vented from the packing case vent may
leak into the compressor distance piece
which operates at atmospheric pressure,
and is typically vented to the atmosphere.
l Compressor blow-down valves:
valves which are opened when a
compressor is in a depressurized mode.
In normal operation, these valves isolate
the pressurized compressor from the
blow-down vent stack or line routed to
the flare header. Leakage through the
valve trim can often occur, which
results in gas being vented from the
compressor blow-down vent stack or
flowing into the flare header. This
source is not specific to the type of
compressor and can occur with
centrifugal, reciprocating and other
types of compressors.
Section 2
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9 — Methane glossary
l Compressor isolation valves:
the suction and discharge valves that
are closed when a compressor is in a
shutdown and depressurized mode,
and which isolate the compressor from
gas/pressure in the suction and
discharge piping/headers. Similar to the
blow-down vent isolation valve, these
valves may leak through, with the gas
then vented from the blow-down stack
or flowing into the flare header
depending on the routing of the blowdown
line. This source is not specific to
the type of compressor and can occur
with centrifugal, reciprocating and other
types of compressors.
COMBUSTION
The combustion of gas in fuel-burning
equipment is not 100% efficient, and some
methane emissions occur as a result of
uncombusted gas being released via the
equipment exhaust stream. The
uncombusted proportion of gas varies
between internal and external combustion
sources (engines, turbines and
heaters/boilers) and, therefore, equipmentspecific
data or emission factors are
typically used for emissions quantification.
FLARING
The controlled burning of gas, including
associated gas, in the course of oil and gas
operations. In many types of operations,
including those where gas is sold, reinjected
or otherwise utilized, safety flaring represents
an important and necessary activity to
ensure safe operations. The combustion
efficiency of a well-designed and operated
flare is generally assumed to be greater than
98%, meaning that less than 2% of the gas
passes through the flare stack unburnt. At
the individual flare level, consideration of
the local parameters such as gas content
and quality, flare design, flow rates, exit
velocities and steam use will all contribute
to the overall combustion efficiency. There
are currently no straightforward methods to
continuously measure or monitor the
actual combustion efficiency or destruction
and removal efficiency of a flare.
FUGITIVES
Unintentional emissions of gas from
equipment and processes. Typical
equipment components where fugitive
emissions can occur are valves, screwed
connections, flanges, open-ended lines
and pump seals.1
1 Other organizations and stakeholders have different definitions or criteria for what constitutes fugitive
emissions that fall on the spectrum between this definition and the IPCC broad definition (which includes
almost all greenhouse gas (GHG) emissions except those from fuel combustion).
Section 2
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10 — Methane glossary
GLYCOL DEHYDRATOR
Process unit that removes water from gas
by contacting high pressure wet gas with
glycol, which absorbs the water from the
gas. Emissions from a glycol dehydration
unit are highly dependent on how the unit
is configured and operated. The two
potential emission points from a glycol
dehydrator are the flash tank overhead gas
(if equipped with a flash tank) and the
regenerator distillation still vent off-gas.
Estimating air emissions from glycol units
using triethylene glycol (TEG), diethylene
glycol (DEG) or ethylene glycol (EG) can be
performed by using a Windows®-based
program such as GRI-GLYCalc™.
Additional information
Additional information on operation and
methane mitigation methods can be found
in the US EPA Natural Gas Star Program
(https://www.epa.gov/natural-gas-star-
program).
HYDRAULIC FRACTURING/‘FRACKING’
Part of the completion process by which
fluids are injected at high pressure down a
wellbore and through perforated casing.
Fractures are created in the targeted
hydrocarbon bearing strata, creating
pathways for hydrocarbons and water to
flow into the wellbore. Specifically, the
process includes directing pressurized fluids
containing a combination of water,
chemicals and proppant (sized particles
mixed with fracturing fluid to hold fractures
open after a hydraulic fracturing treatment),
to stimulate tight formations, such as shale
formations, to release hydrocarbons.
Natural gas may be returned with water and
hydrocarbon liquids from the wellbore
during the flowback phase as well as during
production. The flowback process has the
potential to result in the venting of
significant volumes of gas to the
atmosphere unless equipment is in place to
separate the gas from the liquids and solids
that are also returned, and allow the gas to
be captured.
HYDRAULIC FRACTURING—
REDUCED EMISSION COMPLETION/
GREEN COMPLETION
The process by which natural gas is
recovered during the flowback phase and
either sold or used for beneficial purposes.
Hydraulic fracturing is considered a
‘reduced emission completion’ (REC) or
‘green completion’ when flowback
emissions from the gas outlet of the
separator are vented, captured, cleaned
and routed to the flow line or collection
system, re-injected into the well (or into
another well), used as an on-site fuel
source, or used for some other useful
purpose that a purchased fuel or raw
material would serve, with de minimis
direct venting to the atmosphere. Short
periods of flaring during a reduced
emission completion may occur.
Section 2
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11 — Methane glossary
LIQUIDS UNLOADING
A generic term describing a variety of
technologies and techniques for managing
and preventing the buildup of a wellbore
liquid column, particularly in low
production-rate gas wells. It is also known
as wellbore deliquification. As the
production rate in a gas well declines with
age, the velocity of the gas flow up the
tubing may fall below the critical velocity
necessary to ‘drag’ liquid droplets up
through the wellbore. When this occurs, a
liquid column will build up in the tubing,
which puts hydraulic back pressure on the
reservoir and further reduces the gas
inflow rate. A variety of different techniques
and technologies are used to manage this
buildup of wellbore liquid, and to prevent
production from slowing or ceasing. These
techniques and technologies can be
grouped into two categories—those that
depend on the reservoir energy, and those
that add energy to the wellbore. Those
dependent on reservoir energy include
intermitting (shutting in a well for buildup
which increases the flow rate when
restarted), installing plunger lift systems
along with appropriate control systems,
and installing velocity tubing (smaller
diameter) in the wellbore. Technologies
that add energy include pumps of various
types and gas lift systems.
Additional information
Emissions associated with deliquification
occur when wells using techniques
dependent on reservoir energy are vented
to the atmosphere to increase the pressure
differential between the bottom of the well
and the surface. The number of atmospheric
venting cycles, and hence the volume of
emissions, is highly dependent on the
approach taken to manage the reservoir
energy to achieve the necessary flow rate or
pressure differential. The importance of the
type of approach taken can be
demonstrated by looking at US data
collected in the US EPA’s Greenhouse Gas
Reporting Program. These data show a
highly skewed distribution, with ~4% of
company/basin reports accounting for
more than 75% of reported emissions.
Once a technique which adds energy
(pump or gas lift) is implemented, venting
will not typically occur.
PLUNGER LIFT
A system installed on a well to assist in
deliquification when there is no longer
consistent and sufficient flow velocity to
produce the well. A plunger lift system uses
the well’s own energy (gas/pressure) to lift
liquids from the tubing by pushing the
liquids to the surface; this is achieved
through the movement of a free-travelling
plunger ascending from the bottom of the
well to the surface.
Section 2
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12 — Methane glossary
When directed by the plunger control
system, the plunger drops from the well
lubricator and falls to the bumper spring
and landing tool that is typically located at
the production zone. As pressure increases
in the well, typically after well shut-in, the
plunger acts like a pipeline pig and begins
lifting the liquids to the surface. Flow can
be directed to the separation equipment
and sales line, in which case emissions do
not occur. Flow can also be directed to
storage tanks, with the gas vented to the
atmosphere, or to separation equipment
with gas vented to the atmosphere.
PNEUMATIC GAS EMISSION SOURCES
Sources of emissions where natural gas
pressure is used as an energy source to
operate various instrumentation and
equipment, ultimately resulting in
emissions of the actuation gas. This type of
instrumentation and equipment is
normally used in places where electrical
power or instrument air are not available.
Typical pneumatic gas uses and emission
sources are:
l pneumatic controllers and their
associated valve actuators/positioners
or end devices such as louvre
positioners or plunger-pin actuators;
l pneumatic pumps; and
l miscellaneous pneumatic equipment
such as engine/turbine starter motors.
Each of these uses and emission sources
are discussed in more detail below.
l Pneumatic controller:
an instrument that takes a mechanical,
electrical or pressure input signal
proportional to a process variable or
position being controlled, and which
controls the flow of pneumatic power
gas to and from an end device (most
often a control valve actuator) to
change the state or magnitude of the
process variable being controlled. A
complete control loop includes: a
sensing device which senses the state
of a process variable such as pressure,
temperature, differential pressure
(surrogate for flow), level or position;
the pneumatic supply gas; the
controller; the end device, such as a
valve actuator; and miscellaneous
tubing.
Additional information
From an emissions perspective,
pneumatic controllers can be classified
into the following distinct categories:
n Continuous bleed controllers emit
gas continuously, with the rate
dependent on the critical orifice
diameter, supply gas gravity and
supply gas pressure. In the US,
continuous bleed controllers have
been subdivided into low bleed
(<6 scf/hr) and high bleed (>6scf/hr)
devices.
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13 — Methane glossary
n Intermittent vent controllers vent
gas to the atmosphere to reverse an
actuation action taken. Most often
this involves venting all or part of the
volume of a valve actuator and supply
tubing to partially or fully reverse the
actuation action. Intermittent
controllers, if working correctly, have
much lower emissions than
continuous bleed controllers. The
vented gas rate (scf/hr) is dependent
on the supply gas gravity, supply gas
pressure, tubing and actuator bonnet
volume, and the number of actuations
per hour.
n Safety/shutdown devices/controllers
typically hold a fail-close valve open
and, if functioning properly, release
emissions only in abnormal operation
scenarios.
n Zero emission controllers are
integrated controller, actuator and
control valve devices that discharge
the pneumatic control gas into the
lower pressure downstream of the
controller rather than to the
atmosphere, and do not emit natural
gas. These types of devices use gas
from the system upstream of the
device. Examples are back pressure
control and pressure regulator type
devices where the downstream
system pressure is less than the
upstream pressure.
n Hybrid controllers combine features
of intermittent vent and continuous
bleed design or other novel designs.
These are not common types of
devices, and most controllers can be
classified into one of the four
categories above.
l Pneumatic controllers—bleed vs vent:
Bleed: a pneumatic process where the
control media is intentionally bypassed
from source pressure to the
atmosphere through a bleed port, to
provide a constant downstream
reference pressure for control purposes.
Vent: the release of pneumatic control
gas, while the supply gas is isolated
from the actuation space.
l Pneumatic actuator:
a pneumatic device that creates linear
or rotary motion to move or actuate an
end device (typically a control valve) by
converting pneumatic gas pressure to
motion. Pneumatic actuators enable
large forces to be produced from
relatively small pressure changes acting
on the cross-sectional area of the
diaphragm or plunger.
Section 2
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14 — Methane glossary
l Pneumatic control loop
instrumentation and end device:
a device that uses pneumatic gas
pressure (typically air, nitrogen, or
natural gas) as the energy source for
control. Pneumatic instrumentation
using natural gas is most likely to be
employed where there is no electricity
for an instrument air system, and/or
where there is insufficient pneumatic
demand to justify an instrument air
system.
l Pneumatic pump:
a device that uses natural gas pressure
as the energy source required to pump
fluids. Two common types of pneumatic
pumps are used in the oil and gas sector,
generally when other sources of on-site
power are not available. These are:
l high discharge-pressure piston pumps,
used for pumping relatively low rates
of chemicals or methanol into highpressure
equipment/wells on a more
or less continuous basis; and
l low discharge-pressure diaphragm
pumps, used for pumping higher
rates of fluids for transfer
(intermittent use) or speciality uses
such as in hot glycol heat trace
systems used at remote wells in cold
environments (seasonal use).
Additional information
Emissions from a pneumatic pump are
dependent on the volume of fluid
pumped, the discharge pressure of the
pump, and the design of the pump. The
manufacturer’s pump curve or pump
modelling program should be used to
determine emissions for a particular
model of pump in a particular
service/use.
l Miscellaneous pneumatic
equipment/pneumatic gas-powered
equipment: may be used for other
miscellaneous services such as engine
or turbine starter motors.
Additional information
The use of pneumatic gas-powered
equipment for miscellaneous uses such
as engine/turbine starter motors is
becoming less common.
SEAL BUFFER GAS
A gaseous compound (inert or volatile) that
is injected into the seal assembly in a
compressor to prevent process gas from
entering the seal assembly and to provide
a ‘seal fluid’ for some seal designs.
(See also ‘Centrifugal compressor dry (gas)
seals’ on page 6.)
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15 — Methane glossary
STORAGE TANK
In the context of methane emissions and
emissions management, any vessel that
stores produced hydrocarbon liquids or
produced water and operates at or near
ambient atmospheric pressure. The
hydrocarbon liquids or produced water
may have been stabilized or be
unstabilized. Methane emissions occur
when the pressure of the liquids decreases
and the entrained gas ‘flashes’ out of
solution, resulting in the gas being vented.
Tank venting equipment is designed in
accordance with engineering standards for
both normal and emergency venting.
Storage tanks downstream of the point
where initial equilibration to atmospheric
pressure occurs do not have the potential
for substantial methane emissions. Other
emissions can occur when the fluid is
being pumped into, or out of, the tank and
the movement of the fluid creates airborne
vapour (working losses) that is either
released or captured, or when vapour
generated within the tank as a result of
temperature or pressure variations escapes
the system (breathing losses).
Additional information
The amount of gas a hydrocarbon or
produced water liquid will hold in solution is
proportional to the pressure. The higher the
pressure, the higher the quantity of solution
gas, and the higher the potential flash
emissions. Separating gas at the lowest
pressure feasible minimizes the potential for
methane flash emissions and may negate
the need for post-flash controls such as
vapour recovery units (VRUs) or routing to
‘low low pressure’ (LLP) flare systems to
control methane emissions.
TANK BLANKET GAS
A gaseous compound flowed into a fixed
roof tank at low pressure. This is a common
practice for minimizing the amount of air
entering a tank and creating an explosive
atmosphere. Natural gas is sometimes
used for tank blanketing, but other gases,
such as inert gases, could be used instead.
WELL COMPLETION AND FLOWBACK
Completion: a process undertaken to
complete a well after it has been drilled,
and prepare it for production. The
subsurface well casing is perforated, often
hydraulically fractured, and tubing and
downhole well flow equipment is installed
in the wellbore. The process is a precursor
to, and allows for, the flowback of
petroleum or natural gas from newly drilled
or recompleted wells, to expel drilling and
reservoir fluids and test the reservoir flow
characteristics.
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16 — Methane glossary
Flowback: a process that occurs after a
well is completed or recompleted, whereby
fluids and entrained solids are allowed to
flow from a natural gas or oil well following
a treatment, either in preparation for a
subsequent phase of treatment or in
preparation for clean-up and returning the
well to production. The term ‘flowback’ also
refers to the fluids and entrained solids that
emerge from a natural gas well during the
flowback process.
The flowback period begins when material
introduced into the well during a treatment
returns to the surface following hydraulic
fracturing or refracturing. The flowback
period ends when either the well is shut in
and permanently disconnected from the
flowback equipment or at the start-up of
production. The flowback period includes
the initial flowback stage and the
separation flowback stage.
(See also ‘Hydraulic fracturing—reduced
emission completion/green completion’
on page 10.)
Additional information
Flowback also occurs after drilling and/or
well work that does not include hydraulic
fracturing. It is also mostly relevant to the US
onshore type of development.
Section 3
17 — Methane glossary
This section documents some of the main
methodologies and related terms used in
relation to estimating methane emissions.
BOTTOM-UP EMISSION ESTIMATE
Method of using ‘ground-based’ techniques
to directly measure or estimate emissions
at the facility level (e.g. well pad, compressor
station) or the emissions source/activity
level (e.g. compressor engine exhaust,
storage tanks, equipment leaks).
(See also ‘Top-down emission estimate’ on
page 19.)
BOTTOM-UP EMISSION INVENTORY
Inventory based on direct measurements,
engineering calculations, manufacturer
data and emissions factors for emissions
sources/activities, compiled to develop an
account of emissions discharged to the
atmosphere from a facility (e.g. compressor
station) or a geographic area (e.g. basin,
state, region).
DETECTION THRESHOLD
The minimum quantity or concentration of
a gas (e.g. methane) which is detectable by
detection equipment.
EMISSION FACTOR
Factor relating activity data (e.g. tonnes of
fuel consumed, tonnes of product
produced, number of pneumatic
controllers) to emissions. Emission factors
generally take the form of the amount of
emissions per activity unit, for example
standard cubic feet of gas per hour (scf/hr)
per pneumatic controller. Emission factors
are typically developed based on a
population of direct measurements of
emission sources/activities.
GLOBAL TEMPERATURE CHANGE
POTENTIAL (GTP)
The ratio between the global mean surface
temperature change at a given time
horizon that is understood to follow an
emission of an amount of gas relative to
the same amount of carbon dioxide (CO2).
Emission estimation
methodologies
Section 3
Emission estimation methodologies
18 — Methane glossary
GLOBAL WARMING POTENTIAL (GWP)
A factor which estimates the contribution
to global warming of a given mass of a
greenhouse gas species, relative to the
same mass of CO2 over a particular time
frame. The time period for any quoted GWP
is important as there are significant
differences between 1-year, 20-year and
100-year GWPs; for example, the GWP for
methane is understood to range from 25
to 84 depending on the timeline adopted.
The time period usually used for GHG
inventory reporting is 100 years. The IPCC
Assessment Reports provide relevant GWPs
for methane and other GHGs.
SHORT-LIVED CLIMATE FORCERS
(SLCFS)
Atmospheric compounds, including
methane, hydrofluorocarbons and black
carbon, that are understood to have an
important but relatively short-lived effect
on global temperature. It is thought that in
insolation, early action on SLCFs could
affect the projections for temperatures and
other climate impacts that would be
observed by today’s generation of decision
makers, but would have little impact on the
warming that may be experienced by
future generations. Unless it is
accompanied by ambitious reductions in
CO2 emissions, it is understood that early
SLCF mitigation would also have little
impact on eventual peak warming.
SUPER-EMITTER
A term used to describe the concept that
certain methane sources can represent a
disproportionate amount of the total
methane emissions released from all
sources. The term ‘super-emitter’ can
refer to malfunctioning equipment,
particularly in unmanned installations
where such equipment has the potential
to exist for long periods of time. The
determination of a super-emitter is best
associated with emissions data from a
given source and should not be viewed as
an attribute of an entire site. Care should
be taken when utilizing methodologies
for identifying super-emitters to
differentiate between episodic events
(e.g. gas actuation events), erroneous
measurements and/or malfunctioning
equipment. The term ‘fat-tail’ is often
used to describe the statistical
representation of the data—a probability
distribution that is highly skewed relative
to a well-behaved distribution such as the
normal or an exponential distribution.
Having super-emitters at a few sites could
skew significantly the distribution of
emissions from a sample of sites.
Section 3
Emission estimation methodologies
19 — Methane glossary
TOP-DOWN EMISSION ESTIMATE
Estimate made using different ‘aerial-based’
techniques to measure ambient air
concentrations of methane, calculate
methane flux based on atmospheric and
meteorological conditions, and then
attribute the emission portion due to
different activities. Each measurement
technique has different resolution
capabilities, strengths and weaknesses.
Methane emissions are allocated to the
natural gas industry by: (a) using a ratio of
methane to ethane or propane (longer
chain aliphatics which do not occur from
biogenic sources); (b) isotopic ratio analysis,
using a co-located tracer (such as SF6 or
C2H2); or (c) subtracting estimates of other
sources of methane emissions such as,
livestock, wetlands, agriculture, waste
management, etc. together with
background methane concentrations.
(See also ‘Bottom-up emission estimate’ on
page 17.)
Section 4
20 — Methane glossary
This section lists some, but not all,
technologies and work practices that can
be used to both quantitatively and
qualitatively measure methane emissions.
ACOUSTIC DETECTION DEVICE
A device used to detect the acoustic signal
that results when pressurized gas leaks
through a valve or other small diameter
opening. The acoustic signal is detected by
the analyser, which provides an intensity
reading on the meter. Acoustic detectors
do not measure leak rates, but can provide
an indication of leakage rate based on
empirical derived correlations.
CALIBRATED ANTI-STATIC VENT BAG
An anti-static bag calibrated to a specific
volume and used to estimate the flow rate.
It is used to enclose an emission source to
completely capture the leaking gas. The
time required to fill the bag with emissions
is measured using a stop watch. The
volume of the bag and time required to fill
it is used to determine the rate of
emissions.
Additional information
Different equipment leak detection
instruments have different levels and types
of detection capabilities, i.e. some
instruments provide a visual image while
others provide a digital value on a scale (not
necessarily directly related to mass
emissions). Hence the magnitude of actual
emissions can only be determined after
measurement.
DIRECTED INSPECTION AND
MAINTENANCE (DI&M)
A programme designed to provide a costeffective
way to proactively detect,
measure, prioritize and repair equipment
leaks. Based on initial surveys, directed
maintenance practices may be
implemented to inspect and repair
equipment before leaks occur. Leak survey
frequencies may also be established for
areas, facilities and even specific
equipment based on observed leak
frequencies and/or leak size.
(See ‘Leak detection and repair (LDAR)’ on
page 21.)
Methane detection and
measurement technologies
and work practices
Section 4
Methane detection and measurement technologies and work practices
21 — Methane glossary
EQUIPMENT LEAK DETECTION
The process of identifying emissions from
equipment, components and other points
by screening for, and detecting, fugitive
emissions. A screening device may be used
to screen a wide area to detect the presence
of fugitive methane or vented methane, and
a detection device can be used to identify
a specific fugitive or vented source of leak.
Note that most detection and screening
instruments and devices (particularly
handheld devices) do not quantify the
volume or mass of the emissions.
HIGH VOLUME SAMPLER
A device used to measure the
concentration of emissions from a source.
INFRARED (IR) CAMERA
Refers to a device (camera) equipped with
infrared sensors for detecting gases that
have infrared absorption bands within the
band-pass filter installed in the device.
Includes Optical Gas Imaging (OGI) and
forward-looking IR cameras. The camera
can ‘see’ hydrocarbon-based equipment
leaks as well as other compounds, e.g.
steam. IR cameras detect leaks but do not
quantify them.
Additional information
Compared to handheld technologies that
employ a ‘sniffing’ technique to detect each
possible leak component, IR cameras are
easier to use, very efficient (they can detect
multiple leaks at the same time) and can be
used to perform a comprehensive survey of
a facility. The main disadvantage of an IR
camera is that it may involve substantial
upfront capital investment depending on
the features that are made available. It
should also be noted that operators should
be trained in the use of the camera and
inspection procedures to ensure that
meaningful results are obtained.
LEAK DETECTION AND REPAIR (LDAR)
A programme to identify and repair the
equipment or infrastructure that can be a
source of methane leaks. While LDAR in
certain jurisdictions can have a specific
regulatory definition it is more generally
used to describe the processes and
systems by which leaking equipment is
identified, prioritized and then repaired.
Within the LDAR programme, a variety of
techniques can be employed such as the
use of optical gas imaging cameras.
(See ‘Directed Inspection and Maintenance
(DI&M)’ on page 20.)
Section 4
Methane detection and measurement technologies and work practices
22 — Methane glossary
METHANE DETECTION
Can be defined as the process of
identification of methane emissions from
potential sources, without the
measurement of the mass quantity (flow
rate, e.g. kg/hr). Several devices, screening
instruments and methodologies are
available to detect methane emissions,
including optical gas imaging cameras, laser
leak detectors, portable analysers (OVAs,
TVAs), soap bubble screening and/or AVO
methods. Some of these are able to detect
and provide a concentration level (volume,
e.g. ppmv) that can be used to estimate
the mass emission (e.g. by applying specific
emission factors or correlation equations
available from literature).
METHANE EMISSIONS
A broad term to cover all releases of
methane including planned (e.g. process
equipment) and unplanned (fugitive)
sources.
METHANE FLUX
The rate of mass flow of methane through
a unit area perpendicular to the wind flow
direction. Units of measure are expressed
in g CH4/m2/yr. Flux can be calculated
using methane concentration and wind
speed, and estimated across the entire
cross-sectional area of one square metre.
The calculation therefore assumes a
homogeneous flux perpendicular to the
one square-meter window. Uncertainties
include a potentially different wind speed
at the height of where the wind is
measured compared to the methane
sensor’s height.
METHANE INTENSITY
The ratio of methane emissions
(numerator) over a selected variable
(denominator). It can be determined for a
facility (e.g. compressor station), an area
(e.g. production basin) or even an entire
value chain (e.g. natural gas production
through to distribution). A methane
intensity prevalently used is total methane
emissions in gigagrams emitted from a
facility, area or value chain (numerator)
divided by well production volume, facility
throughput or area production volume in
gigagrams (denominator) and reflected as
a percentage.
METHANE LEAK
The unplanned release of methane from
plant, production operations, systems and
processes, typically from flanges, joints and
connections. Often referred to as fugitives.
(See ‘Fugitives’ on page 9.)
Section 4
Methane detection and measurement technologies and work practices
23 — Methane glossary
METHANE MEASUREMENT
The process of taking a reading of the
methane concentration or methane
emission rate within an air sample at a
specific point in time. Typical units for a
measurement would be parts per million
(ppm), parts per billion (ppb) or kilograms
per hour. Note that it is important to
understand global and local background
methane concentrations to contextualize
the data. Emissions measurements may
be performed as one-time activities, at
regular intervals or on a continuous basis,
but it is important that the measurements
are representative. A variety of techniques
are described in this section of the
document.
METHANE QUANTIFICATION
Includes methods for determining the size
of a methane emission source in terms of
customary units of emissions rate, such as
mass per time (e.g. kilograms per hour) or
volume per time (e.g. standard cubic
metres per hour). This can be
accomplished by engineering estimations,
direct measurement of the methane
source (such as bagging procedures,
US EPA Method 21—see definition on
page 24), and from models that use
ambient measurements and
meteorological data to infer an emission
rate (‘top-down’ or ‘bottom-up’
approaches—see definitions on pages 19
and 17, respectively).
SOAP BUBBLE TEST
Test conducted to determine the location
of pressurized outgassing of fugitive
emissions or venting, by applying a soapwater
liquid solution over the surface of
the suspected area. The soap bubble test
represents an alternative to other forms of
leak detection. Gas emissions can be
confirmed by the presence of bubbles and
the growth in size of those bubbles. This
leak detection method is best performed
with surface temperatures below that of
evaporation, and with continuous visual
observation of the soap bubble growth.
TUNABLE DIODE LASER ABSORPTION
SPECTROSCOPY (TDLAS)
An optical method for detecting trace
concentrations of one or more selected
gases mixed with other gases. This gas
detection technology has many unique
advantages, such as intrinsic safety, good
stability, good selectivity and long
working life.
Additional information
TDLAS sensors are gaining acceptance for
natural gas and methane leak surveying and
other standoff detection applications.
Handheld, and vehicle- and aircraftmounted
versions are currently in use.
Section 4
Methane detection and measurement technologies and work practices
24 — Methane glossary
US EPA METHOD 21
US EPA Technical Guidance on
‘Determination of Volatile Organic
Compound Leaks’. This method is
applicable for the determination of VOC
leaks from process equipment. These
sources include, but are not limited to,
valves, flanges and other connections,
pumps and compressors, pressure relief
devices, process drains, open-ended valves,
pump and compressor seal system
degassing vents, accumulator vessel vents,
agitator seals and access door seals.
Section 5
25 — Methane glossary
UPSTREAM, MIDSTREAM AND
DOWNSTREAM
The oil and gas value chain is typically
divided into three sectors, typically referred
to as upstream, midstream and
downstream, though other divisions and
terms may also be used. Because these
terms are used so broadly, the activities
and operations included in the concept of
one sector may vary depending upon how
the term is used and by whom. It is
therefore difficult to set definitive
boundaries between each sector. Differing
use of these, and other, sector terms, e.g. in
publications and public reports, may lead
to confusion. The descriptions of these
terms below are therefore intended only to
provide general guidance.
l Upstream: activities and/or operations
involving the exploration, development,
and production of oil and gas.
l Midstream: the sector of the oil and gas
value chain that includes the
transportation of crude oil to petroleum
refineries and natural gas to processing
facilities, and the further distribution of
natural gas to local distribution
companies. It may include oil
processing or natural gas processing
plants, either for upgrading the product
to market specifications, for example
through the removal of sulphur
contaminants, or for separation into gas
and natural gas liquids (NGLs).
l Downstream: considered to be the last
sector in the hydrocarbon value chain
over which the oil and gas industry has
influence. This sector includes the
refining, marketing and distribution of
oil and gas products to end users. Some
organizations and standards may
include other stages of the value chain
within their definition of downstream,
depending on the boundaries that they
have used to differentiate each sector.
In general, however, ‘downstream’
encompasses the last stages of the life
cycle of a product.
When using the sector definitions stated
above, care should be taken with regard to
terminology used by others.
General terms
26 — Methane glossary
AVO Audio/visual/olfactory
C2H2 Ethyne (acetylene)
CO2 Carbon dioxide
CH4 Methane
DEG Diethylene glycol
DI&M Directed Inspection and
Maintenance
EG Ethylene glycol
GHG Greenhouse gas
GOR Gas-to-oil ratio
GTP Global temperature change
potential
GWP Global warming potential
IPCC Intergovernmental Panel on
Climate Change
IR Infrared
LDAR Leak detection and repair
LLP Low low pressure
NGL Natural gas liquid
OGCI Oil and Gas Climate Initiative
OGI Optical gas imaging
OVA Organic vapour analyser
PPMV Parts per million by volume
REC Reduced emission completion
Scf/hr Standard cubic feet per hour
SF6 Sulphur hexafluoride
SLCF Short-lived climate forcers
SLCP Short-lived climate pollutants
TDLAS Tunable diode laser absorption
spectroscopy
TEG Triethylene glycol
TVA Toxic vapour analyser
US EPA United States Environmental
Protection Agency
VOC Volatile organic compounds
Acronyms
27 — Methane glossary
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IEA (2016). Balance Definitions. International Energy Agency (website).
https://www.iea.org/statistics/resources/balancedefinitions
EIA (2016). Definitions, Sources and Explanatory Notes. U.S. Energy Information
Administration (website).
https://www.eia.gov/dnav/ng/TblDefs/ng_enr_nprod_tbldef2.asp
IPIECA (2013). The expanding role of natural gas. Comparing life-cycle
greenhouse gas emissions. www.ipieca.org/resources/awareness-briefing/the-
expanding-role-of-natural-gas-comparing-life-cycle-greenhouse-gas-emissions
IPIECA (2015). Exploring methane emissions.
www.ipieca.org/resources/fact-sheet/exploring-methane-emissions
IPIECA (2015). Natural gas: Into the future (The Paris Puzzle).
www.ipieca.org/resources/fact-sheet/natural-gas-into-the-future-the-paris-
puzzle
IPIECA/API/IOGP (2011) Petroleum industry guidelines for reporting greenhouse
gas emissions, 2nd Edition, May 2011. www.ipieca.org/resources/good-
practice/petroleum-industry-guidelines-for-reporting-greenhouse-gas-
emissions-2nd-edition
Further reading
Further reading
34 — Methane glossary
Kirchgessner, D. A., Lott, R. A., Cowgill, R. M., Harrison, M. R. and Shires, T. M. (1997).
Estimate of methane emissions from the U.S. natural gas industry.
In Chemosphere, Volume 35, Issue 6, pp.1365-1390.
www.sciencedirect.com/science/article/pii/S0045653597002361
Schlumberger (2017). Oilfield Glossary: Where the Oil Field Meets the Dictionary
(website). www.glossary.oilfield.slb.com
SPE (2016). Associated and nonassociated gas. SPE International (website).
http://petrowiki.org/Associated_and_nonassociated_gas
US EPA (2015). Controlling Air Pollution from the Oil and Natural Gas Industry.
New Source Performance Standard (NSPS) OOOOa reporting. US Environmental
Protection Agency (website). https://www.epa.gov/controlling-air-pollution-oil-
and-natural-gas-industry
or e-CFR (2015). Electronic Code of Federal Regulations (2015), Subpart OOOO.
http://www.ecfr.gov/cgi-bin/retrieveECFR?gp=&SID=c2b7aa31b53f055d7b011
38d85787720&mc=true&n=pt40.8.60&r=PART&ty=HTML#sp40.8.60.oooo
US EPA/Natural Gas EPA Pollution Preventer (2014). Wet Seal Degassing
Recovery System for Centrifugal Compressors. Partner Reported Opportunities
(PROs) for Reducing Methane Emissions.
https://www.epa.gov/sites/production/files/2016-06/documents/capture
methanefromcentrifugalcompressionsealoildegassing.pdf
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