kSIST-TS FprCEN/TS 17874:2022

SLOVENSKI STANDARD
01-september-2022
Metodologija za vrednotenje emisij metana za sisteme za prenos, distribucijo in
skladiščenje plina ter terminale za utekočinjeni zemeljski plin
Methodology for methane emissions quantification for gas transmission, distribution and
storage systems and LNG terminals
Abschätzung von Methanemissionen für Gastransportund -verteilnetze
Evaluation des emissions de methane pour les réseaux de transport et de distribution de
gaz
Ta slovenski standard je istoveten z: FprCEN/TS 17874
ICS:
75.200 Oprema za skladiščenje Petroleum products and
nafte, naftnih proizvodov in natural gas handling
zemeljskega plina equipment
2003-01.Slovenski inštitut za standardizacijo. Razmnoževanje celote ali delov tega standarda ni dovoljeno.

FINAL DRAFT
TECHNICAL SPECIFICATION
FprCEN/TS 17874
SPÉCIFICATION TECHNIQUE
TECHNISCHE SPEZIFIKATION
July 2022
ICS 75.200
English Version
Methodology for methane emissions quantification for gas
transmission, distribution and storage systems and LNG
terminals
Méthodologie pour la quantification des émissions de Abschätzung von Methanemissionen für
méthane relatives aux réseaux de transmission, de Gastransportund -verteilnetze
distribution, aux stockages de gaz, et aux terminaux
GNL
This draft Technical Specification is submitted to CEN members for Vote. It has been drawn up by the Technical Committee
CEN/TC 234.
CEN members are the national standards bodies of Austria, Belgium, Bulgaria, Croatia, Cyprus, Czech Republic, Denmark, Estonia,
Finland, France, Germany, Greece, Hungary, Iceland, Ireland, Italy, Latvia, Lithuania, Luxembourg, Malta, Netherlands, Norway,
Poland, Portugal, Republic of North Macedonia, Romania, Serbia, Slovakia, Slovenia, Spain, Sweden, Switzerland, Turkey and
United Kingdom.
Recipients of this draft are invited to submit, with their comments, notification of any relevant patent rights of which they are
aware and to provide supporting documentation.

Warning : This document is not a Technical Specification. It is distributed for review and comments. It is subject to change
without notice and shall not be referred to as a Technical Specification.

EUROPEAN COMMITTEE FOR STANDARDIZATION
COMITÉ EUROPÉEN DE NORMALISATION

EUROPÄISCHES KOMITEE FÜR NORMUNG

CEN-CENELEC Management Centre: Rue de la Science 23, B-1040 Brussels
© 2022 CEN All rights of exploitation in any form and by any means reserved Ref. No. FprCEN/TS 17874:2022 E
worldwide for CEN national Members.

FprCEN/TS 17874:2022 (E)
Content
European foreword . 5
Introduction . 6
1 Scope . 7
2 Normative references . 7
3 Terms and definitions . 7
4 Symbols and abbreviations . 14
5 Quantification of methane emission sources . 17
5.1 Strategy for quantification of methane emission from a gas system . 17
5.1.1 General. 17
5.1.2 Materiality of emissions considerations . 17
5.1.3 Starting point . 17
5.1.4 Other issues . 21
5.1.5 Building further knowledge of methane emissions . 22
5.2 Emission types for gas systems . 23
5.3 Identification of emission sources. . 24
5.3.1 General. 24
5.3.2 Identification of Emissions Sources for UGS . 26
6 Quantification . 28
6.1 General concept of quantifications . 28
6.2 Determination of Emission Factors (EF) . 30
6.2.1 General. 30
6.2.2 Measurements . 30
6.2.3 EF estimations . 30
6.3 Determination of Activity Factor (AF) . 31
6.4 Quantification of fugitive emissions . 31
6.4.1 Fugitive emissions from permeation . 31
6.4.2 Fugitive emissions due to connections (e.g. flanges, pipe equipment, valves, joints,
seals) . 32
6.5 Quantification of vented emissions . 36
6.5.1 General considerations . 36
6.5.2 Operational emissions . 37
6.6 Emissions from incidents . 41
6.6.1 General. 41
6.6.2 Incidents on an individual basis . 42
6.6.3 Incidents grouping . 42
6.6.4 Emission rate of incidents 𝑸𝑸𝑸𝑸 . 43
6.6.5 Duration of gas escape . 43
6.6.5 Number of Incidents . 44
6.7 Methane emissions from incomplete combustion . 44
6.7.1 General. 44
6.7.2 Measurement . 44
6.7.3 Emissions based on emission factor . 44
7 Methods for detection and/or quantification (Informative) . 46
8 Uncertainty calculations . 55
8.1 Introduction . 55
8.2 Example of uncertainty calculation based on deterministic calculation . 56
Annex A (informative) Permeation coefficients for plastic pipelines . 60
FprCEN/TS 17874:2022 (E)
Annex B (informative) Permeation of plastic pipelines – Influence of the soil temperature
................................................................................................................................................................. 63
Annex C (informative) Approaches to determine emission rates Q_V for underground leaks
................................................................................................................................................................. 65
C.1 Direct measurement of the emission rates . 65
C.2 Determination of soil coefficients and calculation of the emission rate from leak size and
pipeline pressure . 65
Annex D (informative) Fugitive emissions: Approaches to determine leak duration . 67
D.1 Leak duration depending on the monitoring period and the maximum repair time . 67
D.2 Leak duration by verified expert estimations . 67
Annex E (informative) Estimating volume flow rate for aerial leaks for different types of
flow conditions . 68
E.1 General . 68
E.2 Formulas for Subsonic Flow . 69
E.3 Formulas for Supersonic Flow . 70
E.4 Discharge coefficient (see [53]) . 70
Annex F (informative) Technologies for measurements of fugitive emissions on pipelines
................................................................................................................................................................. 71
F.1 General . 71
F.2 Overview of technologies for Measurements on Facilities . 72
F.2.1 General . 72
F.2.2 Method of EN 15446 - Direct Measurement of the Emission Rates . 72
F.3 Guidance for EF estimation . 73
Annex G (informative) Examples uncertainty calculation . 75
G.1 Example 1: . 75
G.2 Example 2 . 76
G.3 Example 3 . 76
Annex H (informative) Terms used to define granularity . 79
Annex I (informative) OGMP 2.0 level and tier description and correspondence . 80
Annex J (informative)  Chapters linked to reporting categories . 83
J.1 Transmission system operator (TSO) . 83
J.2 Underground Gas Storage Operator (UGS) . 88
J.3 LNG Terminal . 92
J.4 Distribution System Operator (DSO). 94
Bibliography . 97

FprCEN/TS 17874:2022 (E)
European foreword
This document (FprCEN/TS 17874:2022) has been prepared by Technical Committee CEN/TC 234 “Gas
infrastructure”, the secretariat of which is held by DIN.
This document is currently submitted to the Vote on TS.
FprCEN/TS 17874:2022 (E)
Introduction
Greenhouse gas (GHG) emissions, and more specifically methane (CH ) emissions are considered to have
an important impact on climate change. It is crucial for the gas industry to assess and to mitigate
methane emissions in the gas supply chain to support and contribute actively to European greenhouse
gas emission reduction targets.
Methane emissions management and reduction is a priority for the European natural gas industry. To
address this challenge a high level of transparency and reliability when reporting its emissions of
methane is required with harmonized standards.
A lack of harmonized standards to address the quantification of methane emissions from the natural gas
industry has been detected and, therefore, developed the present document that describes a
methodology, based on a source-level approach, to identify and to quantify all types of methane
emissions from transmission, distribution and storage systems and LNG terminals.
Some international initiatives have been recently launched with the intention to tackle the methane
emissions issue in the energy sector. Among those, the Oil and Gas Methane Partnership (OGMP), a
multi-stakeholder partnership supported by UNEP, stands out and intends to provide the industry with
a credible mechanism to address their methane emissions. The new OGMP standard commits
participating companies to increase the accuracy and granularity of their methane emissions reporting
for operated and non-operated assets.
Following the launch of the European methane strategy in October 2020, the European Commission is
encouraging the widespread adoption of the measurement and reporting framework developed under
the OGMP standard.
The quantification methodology described in this document can be used for OGMP reporting needs. It
should be a technical guideline for gas companies across Europe to support fast and harmonized
implementation of methane emissions quantification process.
This methodology is based in large parts on the document prepared by Marcogaz “Assessment of
methane emissions for gas Transmission and Distribution system operators” [18]. Marcogaz is the
Technical Association of the European Natural Gas industry.
FprCEN/TS 17874:2022 (E)
1 Scope
This document describes a methodology to identify different types of methane emissions from gas
infrastructure and it explains, step by step, how to quantify each type of emission in a gas transmission,
distribution and/or storage system and in an LNG terminal. Gas is considered any product with a high
methane content that is in gaseous form inside the respective gas infrastructure (e.g. natural gas, biogas
or mixtures thereof with each other or with hydrogen).
Methane emission from utilisation, CNG/LNG fuelling stations, biomethane production and upgrading
plants and LNG liquefaction and transport are not covered in this document, except if they are inside the
covered asset (see Annex I on granularity).
NOTE 1 These principles can also be applied to other parts of the gas value chain.
NOTE 2 Natural emission by the soil or seepage of methane due to gas field above or next to the storage reservoir
are not taken into account.
The document specifies a source-level method of quantification of identified methane sources.
NOTE 3 Source-level method - Emissions from each identified source are individually quantified. Total emissions
on a given asset are calculated by adding each type of emission source data.
This quantification method consists in splitting the gas systems into groups of  assets, devices and
components and indicating categories of emission that can be expected from these groups to determine
the emission factors (EF) and the activity factors (AF). It comprises measurements of the amount of
methane emitted from different origin, estimation of emissions from groups of assets or calculation
based on available data. In case of individual measurements or calculations, the total emissions are
found by summing the quantified methane emissions.
Finally, a general method to calculate the uncertainties associated with the quantified amounts of
emitted methane is described.
NOTE 4 Part of the methods of this document are retrieved by an international research program initiated by
GERG for DSO.
2 Normative references
There are no normative references in this document.
3 Terms and definitions
For the purposes of this document, the terms and definitions given in CEN/TC 234 standards and the
following apply.
ISO and IEC maintain terminological databases for use in standardization at the following addresses:
— IEC Electropedia: available at http://www.electropedia.org/
— ISO Online browsing platform: available at http://www.iso.org/obp
NOTE The terms and definitions of CEN/TC 234 are compiled in CEN/TC 234 Doc N 776 [7]. Any new terms
used in CEN/TC 234 standards and related to hydrogen are to be added to CEN/TC 234 document.
FprCEN/TS 17874:2022 (E)
3.1
Activity Factor
AF
numerical value describing the size of the population of emitting equipment such as length of pipelines,
number of valves (per type), number of pneumatic devices (per type), or the number of emitting events
such as number of operating vents, multiplied, if relevant, by the duration of the emission
Note 1 to entry: The question whether or not to multiply by the duration of the emission is examined later in this
document.
3.2
annulus
space between two strings of pipes or between the casing and the borehole
3.2
asset
part of the gas system owned by a natural gas company, comprising multiple devices that allows the
company to process, transport, store, and/or distribute gas (see Annex I)
3.3
block valve
valve used to isolate a segment of the main transmission pipeline for tie-in or maintenance purposes
Note 1 to entry: Block valves are located along each line to limit the amount of piping that may need to be
depressurized for tie-ins and maintenance, and to reduce the amount of gas that would be lost in the event of a
line break.
3.4
blow down valve
valve used to empty a gas pipeline section or a whole asset and, when actuated, initiates the gas
blowdown (e.g. when gas compressor units are shut down)
3.5
component
part or element of a larger whole, e.g. flange, valve, connection (see Annex I)
3.6
connection
area of contact between two or more linked parts, axially or radially, normally sealed by mechanical
means in order to keep tightness
3.7
device
equipment (active or passive) related to a gas system and needed in order to keep the normal operation
of the network (see Annex I)
Note 1 to entry: It can be found as in-line equipment (like valves) or auxiliary equipment (like analysers).
Note 2 to entry: Methane emissions can appear from devices in unexpected way or as consequence of its function.
FprCEN/TS 17874:2022 (E)
3.8
control valve
modulating valve that controls either the flow rate or pressure through the pipeline and flowlines
Note 1 to entry: In the latter case, it is often referred to as a regulator station.
Note 2 to entry: High pressure gas from the pipeline may be used as the supply medium needed to energize the
valve actuator.
3.9
discharge coefficient
C
D
coefficient, which relates the actual flowrate to the theoretical flowrate through an opening and
accommodates the friction of the real flow as well as boundary layer effects (jet contraction)
Note 1 to entry: Needs to be determined experimentally and is nearly one for well-rounded openings.
Note 2 to entry: According to several data sources, a value of about 0.6 can be applied for sharp edged holes,
welding cracks or ruptures ([24], [25], [26]).
3.10
equipment
asset, device or component (see Annex I) of a gas system depending on the considered granularity
3.11
emission factor
EF
factor that describes typical methane emissions of a component or part of the gas system (e.g. valve,
pipeline section) or from an event and can have units like [kg/km] or [kg/event]
3.12
fugitive emission
leakages due to tightness failure and permeation
Note 1 to entry: Some type of vented emissions, e.g. those from specific connections detected during survey, cannot
always be clearly distinguished from fugitive emissions. When reporting methane emission double counting
should be avoided.
Note 2 to entry: This term comprises the sum of various unaccounted channelled emissions, fugitive emissions and
area emissions.
Note 3 to entry: Permeation is leakage intrinsic to the use of permeable materials.
3.13
gas compressor station [5]
asset used for:
— transporting gas in pipelines;
— compressing gas from a pipeline to a gas storage facility or vice versa
Note 1 to entry: More than one of the above functions could be done simultaneously or alternatively.
FprCEN/TS 17874:2022 (E)
3.14
gas distribution system [7]
pipeline system for supplying natural gas comprising mains and service lines including piping above
and below ground and all other equipment necessary to supply the gas to the consumer
Note 1 to entry: Operating pressure is normally less than 16 bar.
3.15
gas transmission system [12]
gas transport network, which mainly contains high-pressure pipelines, other than an upstream pipeline
network and other than the part of high-pressure pipelines primarily used in the context of local
distribution of gas, with a view to its delivery to customers, but not including supply
Note 1 to entry: Transmission lines transport natural gas across long distances and occasionally across interstate
boundaries. They are connected to the distribution grid via city gate stations and/or pressure regulating stations.
Note 2 to entry: High-pressure gas transport over long distance including pipelines, compressor stations, metering
and regulating stations and a variety of above-ground facilities to support the overall system. Underground gas
storage and LNG terminals are excluded. Operating pressure is normally equal or greater than 16 bar.
3.16
gate station
facility located adjacent to a transmission grid where at least one of the following functions is
performed: pressure reduction, odorization, measurement or flow of gas through a splitter system for
distribution to different districts or areas
3.17
gas system [13]
any transmission networks, distribution networks, LNG facilities and/or storage facilities owned and/or
operated by a natural gas undertaking, including linepack and its facilities supplying ancillary services
and those of related undertakings necessary for providing access to transmission, distribution and LNG
3.18
incident [5]
unexpected occurrence, which could lead to an emergency situation
3.19
incident emission
methane emissions from unplanned events
Note 1 to entry: This will be from failures of the system due to third party activity, external factors, corrosion, etc.
3.20
incomplete combustion emissions
unburned methane in the exhaust gases from natural gas combustion devices, such as turbines, engines,
boilers or flares
3.21
LNG terminal
asset which is used either for the liquefaction of natural gas, exportation, or for the importation,
offloading, and re-gasification of LNG, and includes ancillary services and temporary storage necessary
for the re-gasification process and subsequent delivery to the transmission system, but does not include
any part of LNG terminals used for storage
FprCEN/TS 17874:2022 (E)
3.22
methane emission
release of methane to the atmosphere, whatever the origin, reason and duration
3.23
main lines of distribution [3]
pipework in a gas supply system to which service lines are connected
3.24
operational emission
methane emissions from normal or planned operating activities
1 to entry: This includes release through stacks; blow off valves, pressure release and purging of turbines
Note
and emissions due to normal maintenance inspection and control. Operational vents comprise planned venting
and purging of pipelines, which is usually done during commissioning, decommissioning, renewal and
maintenance of pipelines for safety reasons to prevent the risk of explosions. Pneumatic emissions are also
operational emissions.
3.25
permeation
penetration of a permeate (such as a liquid, gas, or vapour) through a solid
Note 1 to entry: In case of natural gas through pipelines made of polymer materials, it is directly related to the
pressure of the gas, intrinsic permeability of polymer materials and wall thickness. Polymers can be polyethylene,
polyamide or PVC.
3.26
pneumatic emission
emissions caused by gas operated valves, continuous as well as intermittent emissions
3.27
point of delivery [7]
point where the gas is transferred to the user
Note 1 to entry: This can be at a means of isolation (e.g. at the outlet of an LPG storage vessel) or at a meter
connection. For this document the point of delivery is typically nominated by the distribution system operator and
can be defined in National Regulations or Codes of Practices.
3.28
pressure regulating station [3]
asset comprising all the equipment including the inlet and outlet pipework as far as the isolating valves
and any structure within which the equipment is housed, used for gas pressure regulation and over-
pressure protection
3.29
purge factor
f
purge
factor, which accounts for the emissions caused by purge operations
Note 1 to entry: Purging of the air inside a pipeline or facility is necessary to mitigate the risk of explosions. The
purge factor herein does not refer to the amount of purge gas used but to the amount of the gas vented.
EXAMPLE: If purging is done with 1.5 times the pipeline volume, one volume stays in the pipe and 0.5 volumes are
vented to the atmosphere. The purge factor is in this case 0.5. If the actual purge factor is not known for an
operation, country specific factors should be used.
FprCEN/TS 17874:2022 (E)
3.30
purging [7]
process for safely removing air or inert gas from pipework and/or pipeline components and replacing
it with gas, or the reverse process
3.31
regulator [1]
device which reduces the gas pressure to a set value and maintains it within prescribed limits
3.32
service lines [3]
pipework from the main lines to the point of delivery of the gas into the installation pipework
Note 1 to entry: Service line is usually a short, small diameter pipeline that delivers gas from distribution main or
transmission pipeline to the customer. They are usually made of steel pipe or steel tubing (either cathodically
protected or not), or plastic (usually polyethylene, but sometimes PVC or other plastic), although copper tubing
was also used in the past. Service lines can be installed under or above ground.
3.33
site
all sources within a physical unit
Note 1 to entry: They can be compressor station, transmission station, pipeline segment, LNG terminal, etc.
Note 2 to entry: Site-level measurement/reporting would consider sites as the appropriate level to reasonably and
transparently reporting Level 4.
3.34
source
component within a process or equipment that releases methane to the atmosphere either intentionally
or unintentionally, intermittently or persistently
3.35
subsurface containment
capability of the storage reservoir or cavern and the storage wells to resist leakage or migration of the
fluids contained therein
3.36
uncertainty (of measurement) [19]
parameter, associated with the result of a measurement, that characterizes the dispersion of the values
that could reasonably be attributed to the measurand
Note 1 to entry: The parameter may be, for example, a standard deviation (or a given multiple of it), or the half-
width of an interval having a stated level of confidence.
Note 2 to entry : Uncertainty of measurement comprises, in general, many components. Some of these
components may be evaluated from the statistical distribution of the results of series of measurements and can be
characterized by experimental standard deviations. The other components, which also can be characterized by
standard deviations, are evaluated from assumed probability distributions based on experience or other
information.
Note 3 to entry: It is understood that the result of the measurement is the best estimate of the value of the
measurand, and that all components of uncertainty, including those arising from systematic effects, such as
components associated with corrections and reference standards, contribute to the dispersion.
Note 4 to entry: The definition of uncertainty can also apply to characterize the dispersion for estimated values
and calculated values.
FprCEN/TS 17874:2022 (E)
3.37
underground gas storage
UGS
part of the gas supply chain that stores natural gas underground under pressure, to be used when there
is a high demand
Note 1 to entry: Underground gas storage facilities are created in depleted gas or oil reservoirs, salt cavern
formations and aquifers.
3.38
vented emissions
gas released into the atmosphere intentionally from processes or activities that are designed to do it, or
unintentionally when equipment malfunctions or operations are not normal
Note 1 to entry: In the case of transmission and distribution grids, unintentional vented emissions during not
normal operation cover also vents due to external interference (third-party damage), ground movements, over
pressure, etc.).
3.39
venting
operational release of gas into the atmosphere
Note 1 to entry: Often carried out in order to maintain safe conditions.
3.40
well
borehole and its technical equipment including the wellhead
3.41
well integrity
well condition without uncontrolled release of fluids throughout the life cycle
3.42
working gas
portion of the gas in an underground gas storage that may be stored and retrieved during normal
operation cycles
FprCEN/TS 17874:2022 (E)
4 Symbols and abbreviations
Table 1 provides an overview of symbols used in this document and Table 2 provides an overview of
abbreviations used in this document.
Table 1 — Symbols applied within this report
Unit
Symbol Description
(if not specified otherwise)
𝐴𝐴 Area 𝑚𝑚
shall be consistent with EF unit (examples:
Activity factor (used in
𝐴𝐴𝐴𝐴 number of events, km of pipelines, number of
combination with EF)
devices)
𝑐𝑐 Concentration 𝑣𝑣𝑣𝑣𝑣𝑣 %
𝐶𝐶 Discharge coefficient −
𝐷𝐷
𝑑𝑑 Diameter 𝑚𝑚
𝑘𝑘𝑘𝑘
𝐶𝐶𝐶𝐶4
𝐸𝐸 Methane emission
𝑎𝑎
𝑘𝑘𝑘𝑘
𝐶𝐶𝐶𝐶4
shall be consistent with AF unit (examples:
Emission factor (used in
𝑎𝑎
𝐸𝐸𝐴𝐴
𝑘𝑘𝑘𝑘 𝑘𝑘𝑘𝑘
𝐶𝐶𝐶𝐶4 𝐶𝐶𝐶𝐶4
combination with AF)
, , )
𝑘𝑘𝑘𝑘 𝑎𝑎 𝑒𝑒𝑒𝑒𝑒𝑒𝑒𝑒𝑒𝑒
𝐴𝐴
Super compressibility factor −
𝑝𝑝𝑒𝑒
𝑓𝑓
Purge factor −
𝑝𝑝𝑝𝑝𝑝𝑝𝑘𝑘𝑒𝑒
𝑘𝑘 Permeability of the soil 𝑚𝑚
𝜅𝜅; 𝛾𝛾 Adiabatic index of natural gas −
𝑣𝑣 Length of pipelines 𝑘𝑘𝑚𝑚
𝑘𝑘𝑘𝑘
𝑀𝑀 Molar mass
𝑘𝑘𝑚𝑚𝑣𝑣𝑣𝑣
µ Dynamic viscosity of the gas 𝑃𝑃𝑎𝑎∙𝑠𝑠
Number (e.g. of leaks, incidents, 𝑙𝑙𝑒𝑒𝑎𝑎𝑘𝑘𝑙𝑙 𝑙𝑙𝑒𝑒𝑎𝑎𝑘𝑘𝑙𝑙
𝑛𝑛 𝑣𝑣𝑜𝑜 , 𝑒𝑒𝑒𝑒𝑐𝑐.
𝑎𝑎 𝑘𝑘𝑘𝑘∙𝑎𝑎
events, etc.)
𝑐𝑐𝑚𝑚
𝑃𝑃𝐶𝐶 Permeation coefficient

𝑚𝑚∙𝑏𝑏𝑎𝑎𝑜𝑜 ∙𝑑𝑑
P Absolute pressure 𝑏𝑏𝑎𝑎𝑜𝑜(𝑎𝑎)
𝑘𝑘𝑘𝑘
𝑄𝑄 Mass flow rate
𝑘𝑘
𝑎𝑎
𝑚𝑚
𝑄𝑄 Volume flow rate
𝑒𝑒
𝑎𝑎
𝐽𝐽
𝑅𝑅 Ideal gas constant
𝑚𝑚𝑣𝑣𝑣𝑣∙𝐾𝐾
𝑜𝑜 Radius 𝑚𝑚
𝑘𝑘𝑘𝑘
𝜌𝜌 Density
𝑚𝑚
FprCEN/TS 17874:2022 (E)
Unit
Symbol Description
(if not specified otherwise)
𝑠𝑠 Wall thickness 𝑚𝑚
𝑇𝑇 Temperature 𝐾𝐾
U Uncertainty −
𝑒𝑒 Duration of gas escape ℎ

𝑉𝑉
Geometric volume of the pipeline 𝑚𝑚
𝑘𝑘𝑒𝑒𝑔𝑔
𝑥𝑥 Fraction −
𝑍𝑍 Compressibility factor −
FprCEN/TS 17874:2022 (E)
Table 2 — Abbreviated terms applied within this report
Abbreviation Description
AF activity factor
BOG boil-off gas
DN nominal diameter
DSO distribution system operator
TSO transmission system operator
EF emission factor
EPA Environmental Protection Agency (USA)
FID flame ionization detector
GERG european gas research group
HFS high flow sampler
HP high pressure
LNG liquefied natural gas
LP low pressure
LSO lng system operator
MEEM Methane Emission Estimation Method
MP medium pressure
MOP maximum operating pressure
OGMP Oil and Gas Methane Partnership
PEMS predictive emission monitoring system
PN nominal pressure
PRMS pressure regulating and metering station
PRS pressure regulating station
SDR standard dimension ratio. The ratio between the outside diameter
and the wall thickness of a pipe.
SSO storage system operator
UGS underground gas storage
UNFCCC United Nations Framework Convention on Climate Change
FprCEN/TS 17874:2022 (E)
5 Quantification of methane emission sources
5.1 Strategy for quantification of methane emission from a gas system
5.1.1 General
This clause aims to give the reader an overview of the process of developing a methane emission
estimation for a gas system. The process is the same whether managing a large complex system or just
a small simple one. The overview is given in two figures depending on the starting point in the process,
and the accompanying paragraphs will give a brief process description and guide to the paragraphs
where further information are given.
5.1.2 Materiality of emissions considerations
Both accuracy and effort required of alternative methods to determine emissions from the same source
can differ. One goal should be to efficiently achieve greatest accuracy of total emissions for the entire
asset. To achieve this, types/sources of emissions that are deemed materially contributing to the overall
emissions of the asset shall be determined with methods with low uncertainty. Types/sources that can
be considered contributing only marginally to the overall emissions allow for determination methods
with greater uncertainty.
5.1.3 Starting point
5.1.3.1 General
If no previous estimation of the methane emission from the gas network exists.
Figure 1 gives an overview and provides a systematic approach for methane emission estimation. The
following sub-paragraphs provide further information on each step in the process.
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Figure 1 — Process for a preliminary quantification of methane emission from a gas system
NOTE Preferably each category comprises a statistical homogeneous population.
5.1.3.2 Estimation of methane emission
First step is to establish an estimation of the methane emission from the gas system. This is done in
order to find out from which particular part of the gas system the emission is likely to be most important.
This will vary for each gas system according to their design of the infrastructure and the technologies
used.
Figure 2 gives an overview of the gas system. For all the group of assets of the grid, emission sources
have to be identified. (i.e. identification of all potential sources, taking into account the characteristics
of the asset).
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The first thing to consider is the assets, devices or components (see Annex I) and how these can be
divided into manageable groups. The aim is to build groups, in which the equipment is expected to
behave similarly with respect to different types of methane emissions. Examples of equipment groups
are: steel pipeline, PE pipeline and metering and pressure regulation stations. It is important that the
groups are quantifiable groups (e.g. the length of pipeline, the number of stations). Chapter 5.3 includes
the list of different equipment groups to consider.
Secondly, available knowledge on emissions of methane for each of the equipment groups will be
needed. If measurements of methane emissions are available for some parts of the system, such data
might be able to provide emissions factors for some of the equipment groups. Note that some assets
have different ways of contributing to the emissions, and make sure that measurements / estimates
include all possible emission types. Table 4 provides information on emission types from different
equipment groups. If, for some equipment groups no company information is available, it is possible at
this stage to use information generated by others. MARCOGAZ provides emission factors ranges ([14],
[15], [16], [17]).
Finally, combine the equipment groups with the emission factors to generate the estimate of methane
emissions from the gas grid system. This will provide an overview of the methane emission of the whole
system, and which parts give the largest contribution to the total methane emission.
Based on the knowledge from the first step on which equipment groups that contribute the most to the
total methane emissions, it is possible to reorganise the equipment into other groups and to go into
more detail in certain segments or continue with the current equipment division.

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NOTE Gas production, biogas injection as well as industrial sites and houses are excluded elements.
Key
a Compressor station h Pipeline
b Valve station i Service line
c Blending station 1 Production
d Pressure regulation 2 Biogas
e City gate 3 LNG receiving station
f Stopcock 4 Underground storage
g Gas meter 5 Above ground storage
Figure 2 — Overview of the gas system
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5.1.3.3 Planning field work
The next step is to decide for which equipment groups the methane emission measurements should be
performed. Focus as a first approach on equipment groups that give the largest contribution to the
preliminary estimated methane emissions. Other aspects to take into consideration are budget, planned
maintenance activities, and practical limitations.
When making the planning, it is important to consider the type of emissions for the asset group (see
Table 4) and the measuring techniques which are suitable for those types of emissions (see 7). During
the planning, it should also be ensured that the reporting from field measurements on methane
emissions includes data on sampling and method uncertainties.
5.1.3.4 Perform a measuring and data collection campaign
Perform the measuring and data collection campaign on the equipment groups planned and perform
quality assurance for each data set. Collect accepted methane emission data sets in a database.
NOTE For quality assurance procedures and checks to be undertaken before, during or following emission
measurements used to update emission or activity factors, refer to the measurement standard being used where
available. For example, the calibration and quality assurance checks within EN 15446.
When the measuring campaign has been performed, calculate new emission and activity1 factors for
the relevant equipment groups, see Clause 6 for guidelines.
5.1.3.5 Quantify company methane emission with available data
For quantifying methane emissions, a combination of measurements, simulation tools, detailed
engineering calculations and estimations can be used. When the emission factors have been reviewed,
a new estimation of the total methane emissions can be performed.
5.1.3.6 Reporting methane emission results and uncertainty calculation
A report on the methane emission shall contain the gas system considered, the asset division into groups
and emission types, documentation on which standard emission factors have been used, and reference
to documentation of own determination of group emission factors and their uncertainty. Chapter 8
provides a guideline for uncertainty calculations. An uncertainty analysis for the total emission of
methane will provide detailed knowledge about which assets groups contribute most and where future
improvements are possible for the methane emission estimation. Emissions per source shall be
recorded in an inventory.
This document can be used to comply with the OGMP 2.0 reporting framework, The Annex K gives
guidance on the part of the technical specification that have to be used to do so.
5.1.4 Other issues
Be aware that the process generates knowledge on assets considering maintenance procedures and risk
of leakage and emissions. This might give valuable clues when companies are planning asset
maintenance. This knowledge should be shared with the asset management team.

Emission factors as well as activity factor can need adjustment. E.g. the emissions of pressure regulators are
dependent of their mode of operation (stand by position or open regulating position). This might reflect the
emission factor as well as the activity factor.
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5.1.5 Building further knowle
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