ISO 6338:2023

INTERNATIONAL ISO
STANDARD 6338
First edition
2023-05
Method to calculate GHG emissions at
LNG plant
Méthode pour calculer les émissions de GES dans les usines GNL
Reference number
© ISO 2023
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ii
Contents Page
Foreword .v
Introduction . vi
1 Scope . 1
2 Normative references . 1
3 Terms and definitions . 2
4 Principles . 3
4.1 General . 3
4.2 Relevance . 3
4.3 Completeness . 4
4.4 Consistency . 4
4.5 Transparency . 4
4.6 Accuracy . 4
4.7 Conservativeness. 4
5 GHG inventory boundaries .4
6 Quantification of GHG emissions . 5
6.1 Identification of GHG sources and quantification approach . 5
6.1.1 General . 5
6.1.2 Emissions from fuel combustion . . 6
6.1.3 Emissions from flaring and venting . 6
6.1.4 Fugitive emissions . 7
6.1.5 Emissions associated with imported energy, utilities, and consumables . 7
6.2 Calculation of GHG emissions . 8
6.2.1 Requirements and guidance . 8
6.2.2 GHG inventory . . 9
6.2.3 GHG quantification methods for fuel combustion . 11
6.2.4 GHG quantification methods for flaring and venting . 11
6.2.5 GHG Quantification methods for fugitive emissions . 11
6.2.6 Quantification methods for emissions from imported energy, utilities, and
consumables . 12
6.2.7 Relevant period and frequency .12
6.3 Preferred units . 13
6.4 Allocation . 13
6.4.1 Principles .13
6.4.2 Methodology . . 13
6.5 Carbon capture . 16
6.5.1 Opportunities for carbon capture: . 16
6.5.2 Quantification of carbon capture benefit . 16
7 GHG inventory quality management .16
7.1 General . 16
7.2 GHG Emission Calculation approach . 17
7.3 Estimation of inventory uncertainties . 17
7.4 Procedures for documentation and archiving . 17
7.5 Quality Control . 17
7.6 Quality Assurance . 18
8 GHG reporting .19
8.1 General . 19
8.2 Additional information. 19
8.3 GHG emission reduction . 19
8.4 Carbon offset and emission trading . 20
9 Independent review . .20
iii
Annex A (informative) Conversion factors for reference .21
Annex B (informative) International initiatives on climate ambitions .22
Annex C (informative) Example allocation calculation .24
Bibliography .30
iv
Foreword
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This document was prepared by Technical Committee ISO/TC 67, Oil and gas industries including lower
carbon energy, Subcommittee SC 9, Production, transport and storage facilities for cryogenic liquefied
gases.
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v
Introduction
Natural gas will play a key role in the energy transition (e.g. by replacing coal to produce electricity)
and the use of LNG to transport natural gas is expected to increase. The process of liquefying natural
gas is energy-intensive. Gas producers are increasingly accountable for their greenhouse gas (GHG)
emissions and the ambition to reduce them. Furthermore, there is an emerging marketing demand for
GHG data to enable commercial mechanisms such as offsetting to be utilized.
There is no standardized and auditable methodology to calculate the carbon footprint of the whole LNG
chain (including but not limited to the well, upstream treatment, transportation, liquefaction, shipping,
regasification and end user distribution). Various standards indicate possible approaches but these are
not consistent in their results or easily applicable.
vi
INTERNATIONAL STANDARD ISO 6338:2023(E)
Method to calculate GHG emissions at LNG plant
1 Scope
This document provides a method to calculate the GHG emissions from an LNG liquefaction plant,
onshore or offshore.
The frame of this document ranges from the inlet flange of the LNG plant’s inlet facilities up to and
including the offloading arms to truck, ship or railcar loading. The upstream supply of gas up to the
inlet flange of the inlet facilities and the distribution of LNG downstream of the loading arms are only
covered in general terms.
This document covers:
— all facilities associated with producing LNG, including reception facilities, condensate unit (where
applicable), pre-treatment units (including but not limited to acid gas removal, dehydration, mercury
removal, heavies removal), LPG extraction and fractionation (where applicable), liquefaction, LNG
storage and loading, Boil-Off-Gas handling, flare and disposal systems, imported electricity or on-
site power generation and other plant utilities and infrastructure (e.g. marine and transportation
facilities).
— natural gas liquefaction facilities associated with producing other products (e.g. domestic gas,
condensate, LPG, sulphur, power export) to the extent required to allocate GHG emissions to the
different products.
— all GHG emissions associated with producing LNG. These emissions spread across scope 1, scope
2 and scope 3 of the responsible organization. Scope 1, 2 and 3 are defined in this document. All
emissions sources are covered including flaring, combustion, cold vents, process vents, fugitive
leaks and emissions associated with imported energy.
The LNG plant is considered “under operation”, including emissions associated with initial start-up,
maintenance, turnaround and restarts after maintenance or upset. The construction, commissioning,
extension and decommissioning phases are excluded from this document but can be assessed separately.
The emissions resulting from boil-off gas management during loading of the ship or any export vehicle
are covered by this document. The emissions from a ship at berth, e.g. mast venting are not covered by
this document.
This document describes the allocation of GHG emissions to LNG and other hydrocarbon products
where other products are produced (e.g. LPG, domestic gas, condensates, sulphur, etc.).
This document defines preferred units of measurement and necessary conversions.
This document also recommends instrumentation and estimations methods to monitor and report GHG
emissions. Some emissions are measured and some are estimated.
This document is applicable to the LNG industry.
Applications include the provision of method to calculate GHG emissions through a standardized and
auditable method, a means to determine their carbon footprint.
2 Normative references
The following documents are referred to in the text in such a way that some or all of their content
constitutes requirements of this document. For dated references, only the edition cited applies. For
undated references, the latest edition of the referenced document (including any amendments) applies.
ISO 14044, Environmental management — Life cycle assessment — Requirements and guidelines
ISO 14064-1, Greenhouse gases — Part 1: Specification with guidance at the organization level for
quantification and reporting of greenhouse gas emissions and removals
API Consistent Methodology for Estimating Greenhouse Gas Emissions from Liquefied Natural Gas (LNG)
Operations
3 Terms and definitions
For the purposes of this document, the terms and definitions given in ISO 14064-1 and the following
apply.
ISO and IEC maintain terminology databases for use in standardization at the following addresses:
— ISO Online browsing platform: available at https:// www .iso .org/ obp
— IEC Electropedia: available at https:// www .electropedia .org/
3.1
facility
single installation, set of installations or production processes (stationary or mobile), which can be
defined within a single geographical boundary, organizational unit or production process
[SOURCE: ISO 14064-1:2018, 3.4.1]
3.2
global warming potential
GWP
ratio of the time-integrated radiative forcing (warming effect) from the instantaneous release of 1 kg of
the GHG relative to that from the release of 1 kg of CO2
3.3
greenhouse gas
GHG
gaseous constituent of the atmosphere, both natural and anthropogenic, that absorbs and emits
radiation at specific wavelengths within the spectrum of infrared radiation emitted by the Earth’s
surface, the atmosphere and clouds
Note 1 to entry: For a list of GHGs, see the 6th Intergovernmental Panel on Climate Change (IPCC) Assessment
Report.
Note 2 to entry: Water vapour and ozone are anthropogenic as well as natural GHGs, but are not included as
recognized GHGs due to difficulties, in most cases, in isolating the human-induced component of global warming
attributable to their presence in the atmosphere.
[SOURCE: ISO 14064-1:2018, 3.1.1]
3.4
organizational boundary
grouping of activities or facilities in which an organization exercises operational or financial control or
has an equity share
[SOURCE: ISO 14064-1:2018, 3.4.7]
3.5
reporting boundary
grouping of greenhouse gas (GHG) emission or GHG removals reported from within the organizational
boundary, as well as those significant indirect emissions that are a consequence of the organization’s
operations and activities
[SOURCE: ISO 14064-1:2018, 3.4.8]
3.6
scope 1
direct greenhouse gas emissions
direct GHG emissions
emissions coming from sources that are owned or controlled by the facility
Note 1 to entry: This can be the emissions that are directly created by product fabrication or synthesis, for
example, combustion fumes from a refinery.
3.7
scope 2
indirect greenhouse gas emissions from purchased and consumed energy
indirect GHG emissions from purchased and consumed energy
emissions from the generation of imported electricity, steam, and heating/cooling consumed by the
facillity
Note 1 to entry: These emissions physically occur at the facility where electricity, steam and cooling or heating
are generated but as a user of the energy, the consuming party is still responsible for the greenhouse gas
emissions that are being created.
3.8
scope 3
other indirect greenhouse gas emissions
other indirect GHG emissions
emissions from sources that are not owned and not directly controlled by the facility
Note 1 to entry: However, they are related to the company’s activities. This is usually considered to be the
supply chain of the company, so emissions caused by vendors within the supply chain, outsourced activities, and
employee travel and commute. In many industries, other indirect GHG emissions account for the biggest amount
of GHG emissions. This is due to the fact that in today’s economy, many tasks are outsourced and few companies
own the entire value chain of their products.
3.9
quality assurance
QA
planned system of review procedures conducted by personnel not directly involved in the inventory
compilation/development process
3.10
quality control
QC
planned system of review procedures conducted by personnel not directly involved in the inventory
compilation/development process
4 Principles
4.1 General
The application of the following principles is fundamental to guarantee that GHG calculations are a true
and fair account.
4.2 Relevance
Use data, methods, criteria, and assumptions that are appropriate for the intended use of reported
information. The quantification and reporting of GHG emissions shall include only information that
users — both internal and external to the plant — need for their decision-making. This information
shall thus fit the intended purpose of the GHG project and meet the expectations or requirements of
its users. Data, methods, criteria, and assumptions that are misleading or that do not conform to this
document are not relevant and shall not be included.
4.3 Completeness
Consider all relevant information that can affect the accounting and quantification of GHG reductions,
and complete all requirements. All relevant information shall be included in the quantification of GHG
emissions. A GHG monitoring plan shall also specify how all data relevant to quantifying GHG reductions
will be collected.
4.4 Consistency
Use data, methods, criteria, and assumptions that allow meaningful and valid comparisons. The credible
quantification of GHG emissions requires that methods and procedures are always in the same manner,
that the same criteria and assumptions are used to evaluate significance and relevance, and that any
data collected and reported will be compatible enough to allow meaningful comparisons over time.
4.5 Transparency
Provide clear and sufficient information for reviewers to assess the credibility and reliability of GHG
emissions claims. Transparency is critical for quantifying and reporting GHG reductions, particularly
given the flexibility and policy-relevance of many GHG accounting. GHG information shall be compiled,
analysed, and documented clearly and coherently so that reviewers can evaluate its credibility.
Information relating to the GHG assessment boundary, the estimation of baseline emissions shall be
sufficient to enable reviewers to understand how all conclusions were reached.
4.6 Accuracy
Uncertainties with respect to GHG measurements, estimates, or calculations shall be reduced as much as
is practical, and measurement and estimation methods shall avoid bias. Acceptable levels of uncertainty
will depend on the objectives for implementing a GHG project and the intended use of quantified GHG
reductions. Where accuracy is sacrificed, data and estimates used to quantify GHG reductions shall be
conservative.
4.7 Conservativeness
Where data and assumptions are uncertain and where the cost of measures to reduce uncertainty is not
worth the increase in accuracy, make best endeavours to use the most probable data, with an analysis
of the impact of likely uncertainty margins.
5 GHG inventory boundaries
The reporting boundaries of the GHG report for an onshore or offshore LNG liquefaction plant shall
cover all facilities which are associated with the production of LNG. Table 1 provides examples of LNG
plant facilities.
[1]
Table 1 — List of LNG plant facilities
Out of
In scope of
LNG Plant Facility scope of
the report
the report
Natural Gas Production X
Shipping / Pipeline Transport X
Inlet gas Receiving Facilities X
Condensate Unit (where applicable) X
Pre-treatment Units (e.g. acid gas remov-
al, dehydration, mercury removal, heavies X
removal, others)
TTabablele 1 1 ((ccoonnttiinnueuedd))
Out of
In scope of
LNG Plant Facility scope of
the report
the report
LPG Extraction and Fractionation (where
X
applicable)
Liquefaction Unit X
LNG Storage and Loading X
Flare and Disposal Systems X
Carbon Capturing Unit X
Utilities Supply (on-site power generation) X
Utilities Supply (imported) X
Plant Utilities and Infrastructure (e.g.
X
plant piping and marine facilities)
Regasification X
The organization having financial and/or operational control over the LNG liquefaction plant shall
report all GHG emissions and removals within the reporting boundaries at least on an annual average
basis.
6 Quantification of GHG emissions
6.1 Identification of GHG sources and quantification approach
6.1.1 General
The main emission sources to consider derive from fuel combustion, flaring, releases to atmosphere
(including fugitive emissions) and emissions associated with imported energy or consumables. Tables 2
to 5 give an initial checklist of emission sources to consider, and an overview of typical quantification
methods suitable for different emission sources.
The chosen method of quantification per emissions source will differ from one LNG facility to another.
Different plants will have access to a varying number of flow meters, composition analysis equipment
and level meters available.
Operators shall develop a GHG quantification plan to map out how all emission sources can best be
identified in the facility, with a preference to obtain primary data for all major emission sources. The
measurement plan shall also include an assessment of data accuracy and impact on the total GHG
emissions calculation. This assessment will then allow the operator to assess if there is a need to
further improve the amount or accuracy of instruments available for the total assessment. Guidance on
this assessment is detailed in ISO 14064-1:2018, Annex C.
A list of activity data shall be defined based on reliability as primary and secondary data:
— Primary data: quantified value of a process or an activity obtained from a direct measurement or a
calculation based on direct measurements
— Secondary data: data obtained from sources other than primary data
There is always a preference to use primary data. Only in the absence of primary data, secondary data
may be used, that could include estimated quantities and industry average emission factors.
Typically, primary data is recorded to enable GHG quantification contributing >5 % of the site’s total
GHG emissions. For smaller individual sources a calculated approach is acceptable.
The following subclauses describe sources to consider and typical quantification approach for the main
emissions sources.
6.1.2 Emissions from fuel combustion
The quantification approaches for emissions from fuel combustion are described in Table 2.
Table 2 — Emissions from fuel combustion at LNG liquefaction facilities
Source Examples Quantification approach
Gas turbine driv- Primary liquefaction drivers, power Typically, primary data is recorded to enable
ers generation drivers, other refrigeration GHG quantification. As a minimum, fuel gas
drivers (e.g. fractionation), CO sequestra- consumption and composition are required.
tion compressor drivers (Noting that fuel composition at an LNG plant
can vary widely depending on operating mode)
Diesel drivers Firewater pumps, power generation, boil- Operator may report typical annual diesel
er feed water pumps consumption and include resulting annual
emissions as a nominal allowance in the GHG
calculation
Boilers Steam for turbine drivers, steam for pro- Typically, primary data is recorded to enable
cess heating GHG quantification for major fuel consumers
(contributing >5 % of the total GHG emissions.)
As a minimum, fuel gas consumption and com-
position shall be measured
Fired heaters Regeneration gas heater, heating medium If fuel measurements are available, operator
heater, direct fired reboilers should record total fuel gas consumption and
composition. If direct fuel measurements are
not available, a calculation based on operating
duty and efficiency is acceptable
Incinerators Acid gas vent incinerator, thermal oxidiz- As above
ers, catalytic oxidizers, waste disposal
Unburned hydrocarbons shall be taken into account in all sections. If fuel measurements are available, operator should
record total fuel gas consumption combined with combustion efficiency data for the fired equipment used. Ideally,
combustion efficiency should be validated with measured emission data.
6.1.3 Emissions from flaring and venting
The quantification approaches for emissions from flaring and venting are described in Table 3.
Table 3 — Emissions from flaring and venting at LNG liquefaction facilities
Source Examples Quantification approach
Atmospheric Acid gas vent, sulphur plant tail gas Typically, primary data is recorded to enable
waste disposal GHG quantification from venting contribut-
from treating ing >5 % of the site’s total GHG emissions. For
units smaller individual sources a calculated ap-
proach based on heat and material balance data
is acceptable. As a minimum, fuel gas consump-
tion and composition are required
Atmospheric vent- Feed gas pipeline blowdown, storage tank Typically, primary data is recorded for signif-
ing of unburned venting and pressure protection, loading icant venting events, such as pipeline blow-
hydrocarbon arm blowdown, compressor blowdown, down. A calculated approach is acceptable
flare operation with failed ignition for venting events contributing <5 % of total
annual emissions
Flares Process plant pressure protection, depres- Typically, primary data is recorded to enable
suring, storage tank pressure protection, GHG quantification from flaring contributing
boil-off gas management, refrigerant com- >5 % of the site’s total GHG emissions. For
position management, purge gas and pilots smaller individual sources a calculated ap-
proach is acceptable.
Nitrogen vents Nitrogen vents from nitrogen rejection If primary data not available, a calculated
from NRU units can contain methane, and are gener- allowance using licensor composition data may
ally routed to atmosphere be used.
Unburned hydrocarbons shall be taken into account in all sections. Operator should record total flare gas, combined
with combustion efficiency data for the flare tip used. Ideally, combustion efficiency should be validated with measured
emission data.
6.1.4 Fugitive emissions
The quantification approaches for fugitive emissions are described in Table 4.
Table 4 — Fugitive emissions at LNG liquefaction facilities
Source Examples Quantification approach
Permeation Emissions through porous materials Can be calculated with emissions factors for
different materials.
Gas leaks Leaks from pipes and fittings, rotating Typically done via calculation using equipment
equipment seals, storage tank seals count and standard leakage factors. Measured
leakage data from atmospheric monitoring may
be used to adjust the leakage factors applied.
6.1.5 Emissions associated with imported energy, utilities, and consumables
Emissions associated with imports require data from the exporter. Contractual relationship with the
exporter should include a requirement to provide emissions data. In the absence of reliable GHG data
for imports, the calculation shall account for the complete supply chain for the imported commodity.
The cut-off criteria for reporting shall be defined in accordance with ISO 14044.
The quantification approaches for emissions associated with imported energy, utilities and consumables
are described in Table 5.
Table 5 — Emissions associated with imported energy, utilities, and consumables
Source Examples Quantification approach
Electric power Power from third party fossil fuel combus- Primary data is recorded for total power con-
tion, power from grid sumed. GHG quantification requires intensity
data from the supplier. In case of supply from a
grid, the average intensity from all suppliers to
the grid is required
Heat or steam Steam or heating medium from third party Primary data is recorded for total imported
heating utility. GHG quantification requires
intensity data from the supplier. In case of heat
generated from waste heat, emissions from pri-
mary fuel use may be excluded, but supplemen-
tal emissions such as pumping power, or back
up fired heaters or boilers must be included.
Other utilities Cooling, air, nitrogen, water Primary data is recorded for total imported
utility. GHG quantification requires intensity
data from the supplier. Secondary data is ac-
ceptable if primary data is not available.
Imported con- Refrigerant not produced on site Primary data is recorded for quantities con-
sumables sumed. GHG quantification from consumables
requires intensity data from the supplier.
Secondary data is acceptable if primary data is
not available.
6.2 Calculation of GHG emissions
6.2.1 Requirements and guidance
The following paragraphs in this subclause provide requirements and guidance regarding the evaluation
of activity data and emission factors required to convert emission source data to GHG emissions. In
some cases, emissions are measured directly (e.g. in case of venting), but most commonly a calculation
is required to convert measured data to reported emissions (e.g. in case of fuel combustion).
Emission calculations shall be performed in accordance with API (American Petroleum Institute)
Consistent Methodology for Estimating Greenhouse Gas Emissions from Liquefied Natural Gas (LNG)
Operations.
The key input data required to derive an emission factor are flowrate, composition, and combustion
efficiency.
For flowrate, the preferred approach is to use measured data. However, in the absence or failure of
measurement instrumentation, calculated approaches may be used, e.g. based on heat and material
balances, or other data such as pressure drop which may be used to estimate a flowrate.
For composition, the preferred approach is also to use measured data. However, in the absence of
measured data, calculated and estimated approaches may be used, e.g. based on periodic sampling or
calculation from the heat and material balance. For sources with predictable composition (e.g. diesel
fuel) standard emission factors may be used. See API GHG Compendium for emissions standards and
approach.
For combustion efficiency, the preferred approach is also to use measured data. However, in the absence
of directly measured data, the equipment vendor can supply efficiency data based on factory testing of
their equipment or refer to API GHG Compendium for typical values.
Each time a GHG emission evaluation is reported, the calculation approach shall also be stated,
recognising that the quality of data available for this calculation impacts the accuracy of the results.
LNG Plant GHG emissions would be estimated using a combination of methodologies Elements of the
method consists of:
— direct measurements including mass balance approaches;
— emission factors including those provided by equipment manufacturers;
— engineering calculations that are based on process knowledge.
6.2.2 GHG inventory
6.2.2.1 General
A GHG emissions inventory is comprised of measured, calculated and estimated emissions from
individual emission sources that are aggregated to produce the inventory, in accordance with the
following steps;
— Define the purpose and content of the GHG Inventory, GHG emissions sources and assessment
boundary and the reference base year;
— Select activity data and emission factors: provide sector-specific good practice guidance and
references for emission factors (see Clause 6);
— Select measuring technologies or Calculation methods: describe different quantification methods
depending on the availability of site-specific activity data and emission factors;
— Define the Data recording and reporting criteria, and related documentation.
GHG Inventory methodology and process shall include the following elements:
— Base year;
— GHG emission sources;
— Activity data inputs;
— GHG emission factors;
— Global warming potentials.
Plant owner shall define requirements for the GHG Inventory records, reports and documentation and
archive it in a consistent manner.
6.2.2.2 Base year definition
A meaningful and consistent comparison of emissions over time requires that companies set a
performance datum with which to compare current emissions. This performance datum is referred
to as the base year emissions. It describes an activity or a set of activities that result in GHG emissions
against which current activity emissions can be compared for the purpose of quantifying GHG
reductions.
The selection of base year shall represent and be consistent to the following criteria:
— Same boundary of activities
— Same technologies or practices
— Same plant configuration, deployment, implementation, operation,
— Same type, quality, and similar quantity of product(s) or service(s) as the current year.
For consistent tracking of emissions overtime, the past base year emissions shall be recalculated,
according to the new reporting boundary, when significant structural changes occur for any of the
above criteria during the year of reporting.
6.2.2.3 GHG emission sources
Plant owner shall define a GHG assessment boundary through the following steps:
— identify the Plant activities that comprise the GHG project;
— identifying the primary (major sources) and secondary (minor sources) effects associated with each
plant activity listed in 6.1;
— thoroughly analysing the secondary effects to determine which are significant for the purpose of
estimating and quantifying GHG reductions.
For complete, accurate and transparent quantification of GHG reductions, the GHG assessment
boundary shall be clearly defined and reported. The GHG assessment boundary shall include the
primary and significant secondary effects of all operational activities. Specific exclusions or inclusions
shall be clearly identified and justified/explained and exclusions shall not exceed 5 % of the aggregate
GHG emissions in scope 1 and scope 2.
6.2.2.4 GHG Emission Factors
Different types of emission factors are used to convert activity data and upstream/downstream data
into GHG emissions data:
a) Material emission factors
1) Life cycle materials emission factors, which include emissions that occur at every stage of a
material/product’s life, from raw material acquisition or generation of natural resource to end
of life
2) Cradle-to-gate (“upstream”) emission factors, which include all emissions that occur in the life
cycle of a material/product up to the point of sale by the producer.
b) Energy emission factors
1) Life cycle fuel emission factors, which include not only the emissions that occur from
combusting the fuel (Combustion emissions factors) but all other emissions that occur in the
life cycle of the fuel such as emissions from extraction, processing, and transportation of fuels
(Well-to-tank emission factors).
2) Combustion emission factors, which include only the emissions that occur from combusting
the fuel.
c) Upstream & Downstream transportation factors often included in specific international models
such as the GHG Protocol.
Company shall define emission factors used to convert activity data and upstream/downstream data
into GHG emissions data, record and archive it in a consistent manner.
6.2.2.5 GHG global warming potentials
Each GHG has a unique atmospheric lifetime and heat-trapping potential. To express emissions based
on their global warming potential, the mass of emissions of each GHG is multiplied by its corresponding
GWP. The result is referred to as the CO2-equivalent (CO2-eq) emissions. Because the GWP of CO2 is
always 1, the mass emissions of CO2 and the CO2-eq emissions are identical. Global warming potentials
are calculated over different time periods, typically ranging from 20 years to 500 years. The most
common time period for expressing GWPs is 100 years.
The reporting entity shall define GWP reference used to convert GHG data into GHG equivalent and
record and archive it in a consistent manner.
6.2.3 GHG quantification methods for fuel combustion
One of the features of LNG operations is that the carbon content of the fuel gas can vary throughout the
operations chain and can also vary in different operating modes. During liquefaction, the fuel gas used
typically has lower carbon content than the feed stream used for producing the LNG, since it consists
mostly of lower molecular weight boil-off gas and most of the inlet gas stream’s inert nitrogen.
6.2.4 GHG quantification methods for flaring and venting
6.2.4.1 General
GHG quantification shall follow the requirements and should follow the guidance in 6.2.1. Additional
considerations are given in the following clauses.
6.2.4.2 Flaring
The flare system at LNG facilities operates as an emergency facility. It is a critical part of the safety
system and is designed to prevent escalation of accidents and dangerous situations. It is mainly used
to eliminate any discharge from the pressure relief system. Any waste gas sent to the flare (i.e. gas
from the process which is not recovered, such as dehydrator vents or compressor seal gas) is usually
insignificant compared with other industrial processes such as petrochemical or refining.
In principal, operators should avoid operational flaring, however there might be small quantities of
planned releases into the flare system, including fuel for pilots and purging, and exceptional operational
releases such as for defrosting or refrigerant composition management. In these cases, the source gas
entering the flare system should be known, and emissions factors may be derived.
In case of emergency flaring, an incident investigation should identify the source of a release, and this
information may be used to derive an emission factor to apply to the event.
Measurement-based methane destruction efficiency, destruction efficiency determined through the
application of correlations based on representative sampling, or in some cases process simulation and/
or engineering calculations may be used for emissions quantification at the flare. These emissions
quantifications must be validated against relevant field data.
Measured combustion efficiency factors may also be used, recognizing they will provide a conservative
reported value compared to destruction efficiency. More
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