ISO/TR 26762:2008

TECHNICAL ISO/TR
REPORT 26762
First edition
2008-07-15
Natural gas — Upstream area —
Allocation of gas and condensate
Gaz naturel — Zone amont — Allocation du gaz et du condensat

Reference number
©
ISO 2008
PDF disclaimer
This PDF file may contain embedded typefaces. In accordance with Adobe's licensing policy, this file may be printed or viewed but
shall not be edited unless the typefaces which are embedded are licensed to and installed on the computer performing the editing. In
downloading this file, parties accept therein the responsibility of not infringing Adobe's licensing policy. The ISO Central Secretariat
accepts no liability in this area.
Adobe is a trademark of Adobe Systems Incorporated.
Details of the software products used to create this PDF file can be found in the General Info relative to the file; the PDF-creation
parameters were optimized for printing. Every care has been taken to ensure that the file is suitable for use by ISO member bodies. In
the unlikely event that a problem relating to it is found, please inform the Central Secretariat at the address given below.

©  ISO 2008
All rights reserved. Unless otherwise specified, no part of this publication may be reproduced or utilized in any form or by any means,
electronic or mechanical, including photocopying and microfilm, without permission in writing from either ISO at the address below or
ISO's member body in the country of the requester.
ISO copyright office
Case postale 56 • CH-1211 Geneva 20
Tel. + 41 22 749 01 11
Fax + 41 22 749 09 47
E-mail copyright@iso.org
Web www.iso.org
Published in Switzerland
ii © ISO 2008 – All rights reserved

Contents Page
Foreword. v
Introduction . vi
1 Scope .1
2 Normative references .1
3 Economic aspects .1
3.1 Overview.1
3.2 Uncertainty and costs .3
3.3 Allocation system overview.4
4 Allocation from different viewpoints and terminology .7
4.1 Physical system.7
4.2 Gas/condensate system overview .7
4.3 Physical system terms .12
4.4 Definitions for allocation systems .14
4.5 Allocation from a commercial viewpoint.16
5 Quantity measurement for gas and condensate .21
5.1 Introduction.21
5.2 Quantity measurement by type of fluid streams .23
6 Quality measurement .33
6.1 Sampling and analysis .33
6.2 Analysis .35
6.3 Uncertainties .35
6.4 Other .36
7 Data processing.38
7.1 Calculation at the measurement point.38
7.2 Balancing and reconciliation.39
7.3 Process simulation.40
7.4 Line packing and stock change .41
8 Lift, injection and utility gas .42
8.1 General.42
8.2 Lift gas .42
8.3 Injection gas .43
8.4 Utility gas.43
8.5 Uncertainty considerations for lift, injection and utility gas.44
9 Uncertainty — General considerations .45
9.1 Economic consequences.45
9.2 Sensitivity.47
9.3 Allocation principle.48
9.4 Uncertainty determination .48
10 Validation.49
10.1 General.49
10.2 Meter validation.49
10.3 Allocation procedures and process validation.50
10.4 Data validation .50
10.5 Process-model validation .50
10.6 Allocation-process results validation.50
10.7 Software validation.50
11 Classification of allocation processes. 51
11.1 General descriptions and calculations . 51
11.2 Allocation systems layout. 60
12 Mis-measurements — Measurement-correction and estimations . 65
Annex A (informative) Adjust for impurities . 66
Annex B (informative) Adjustments for fuel/utility/vent/flare gas . 67
Annex C (informative) Wet gas. 68
Annex D (informative) Codes, abbreviations and acronyms . 71
Annex E (informative) Conversion of molar percent to mass percent. 73
Annex F (informative) Conversion of mole percent to per cent of the calorific value. 74
Annex G (informative) Conversion of mole per cent to volume percent . 75
Annex H (informative) Components of gas and liquid reported . 76
Bibliography . 77

iv © ISO 2008 – All rights reserved

Foreword
ISO (the International Organization for Standardization) is a worldwide federation of national standards bodies
(ISO member bodies). The work of preparing International Standards is normally carried out through ISO
technical committees. Each member body interested in a subject for which a technical committee has been
established has the right to be represented on that committee. International organizations, governmental and
non-governmental, in liaison with ISO, also take part in the work. ISO collaborates closely with the
International Electrotechnical Commission (IEC) on all matters of electrotechnical standardization.
International Standards are drafted in accordance with the rules given in the ISO/IEC Directives, Part 2.
The main task of technical committees is to prepare International Standards. Draft International Standards
adopted by the technical committees are circulated to the member bodies for voting. Publication as an
International Standard requires approval by at least 75 % of the member bodies casting a vote.
In exceptional circumstances, when a technical committee has collected data of a different kind from that
which is normally published as an International Standard (“state of the art”, for example), it may decide by a
simple majority vote of its participating members to publish a Technical Report. A Technical Report is entirely
informative in nature and does not have to be reviewed until the data it provides are considered to be no
longer valid or useful.
Attention is drawn to the possibility that some of the elements of this document may be the subject of patent
rights. ISO shall not be held responsible for identifying any or all such patent rights.
ISO/TR 26762 was prepared by Technical Committee ISO/TC 193, Natural gas.

Introduction
Hydrocarbon gas and condensate from onshore or offshore concessions is often transported by shared
pipelines to shared main treatment facilities. The concessions are often owned by or licensed to a number of
oil companies. At the main treatment facilities, the gas and condensate are processed to sales specifications.
The gas is sold to shippers in terms of standard volume (standard cubic metres) or combustion energy
(joules), and the condensate is sold in terms of standard volume (standard cubic metres) or mass (kilograms
or tonnes). All the gas and condensate sold at the main treatment facility and the associated money should be
allocated back to the individual concessions and, ultimately, to the individual reservoirs or wells, as illustrated
in Figure 1.
When gas from two or more entry sources (e.g. two or more different companies) is commingled and
processed in a common pipeline and terminal system and the sources have different ownership and/or
operate under different tax regimes, then a gas allocation system is required. It is necessary that the allocation
system provide a fair, equitable and auditable means of sharing out the products from the system to the entry
sources and to the associated partners, recognizing the specific delivery requirements of each participant.

Figure 1 — Offshore gas distributions

vi © ISO 2008 – All rights reserved

TECHNICAL REPORT ISO/TR 26762:2008(E)

Natural gas — Upstream area — Allocation of gas and
condensate
1 Scope
This Technical Report describes the production measurements, in terms of both hardware and procedures,
that can be used to allocate the gas and condensate back to the individual concessions, reservoirs and wells
in a fair and equitable way. The objective is to give an approach that is recognized to be current best practice
and that has a wide support in the oil and gas industry.
2 Normative references
ISO 5167-1, Measurement of fluid flow by means of pressure differential devices inserted in circular cross-
section conduits running full — Part 1: General principles and requirements
ISO 5168, Measurement of fluid flow — Procedures for the evaluation of uncertainties
ISO 6974 (all parts), Natural gas — Determination of composition with defined uncertainty by gas
chromatography
ISO 6975, Natural gas — Extended analysis — Gas-chromatographic method
ISO 6976:1995, Natural gas — Calculation of calorific values, density, relative density and Wobbe index from
composition
ISO 9951, Measurement of gas flow in closed conduits — Turbine meters
ISO 10715, Natural gas — Sampling guidelines
3 Economic aspects
3.1 Overview
3.1.1 General
Production measurements in the upstream area, whether single-phase or multiphase, have an economic
impact on the business. The implementation of production measurements costs money, but in return delivers
data that can be used in decision-making processes and in measuring the economic returns. Generally, it is
necessary to give the three issues described in 3.1.2 to 3.1.4 proper consideration to implement a cost-
effective measurement and allocation system.
3.1.2 Value of information
The decision-making processes that use production measurement information are those associated with
production optimization or reservoir modelling. Figure 2 indicates, schematically, the effect of measurement
accuracy on the uncertainty band of the ultimate recovery from a concession (i.e. total production over field
life). With poor accuracy in the measurements, the uncertainty band and associated risk exposure stay
relatively large. With better and more accurate measurements, the uncertainty band and associated financial
risk are reduced. The assessment of the value of information is the most difficult part of designing an
allocation system and it is probably for that reason that it is rarely done properly, if at all. As an example, the
difference between production allocation (i.e. allocation of fluids from a production facility to the individual
wells) and sales allocation (i.e. allocation of products in a common pipeline) can be mentioned. In the sales
allocation, it can be directly calculated what the relation is between uncertainties in fluid flow measurement
and risk in money flow between the companies involved. In the production allocation, often within one single
company, this is less obvious as complex reservoir modelling and petroleum economics are involved. This is
often why, in general, the requirements for sales allocation are higher than the requirements for production
allocation.
3.1.3 Hardware costs
Capital expenditures for production facilities, test separators, test lines, multiphase flow meters, etc. can all be
assessed relatively easily. It should also be noted that the higher the accuracy requirement for a particular
meter, the more expensive the meter hardware. This is the easiest part in the total cost estimate.

Figure 2 — Cost treatment of metering
2 © ISO 2008 – All rights reserved

3.1.4 Operating costs
Preparation and implementation of procedures and guidelines to keep the production measurement
equipment in good shape (maintenance, verification and calibration) and to ensure that readings are reliable
and within the original specifications require sufficient and consistent dedication during the operations phase.
These costs are often underestimated, especially with new technologies such as multiphase or wet-gas flow
metering.
3.2 Uncertainty and costs
With respect to uncertainty and costs, two extreme cases are considered.
⎯ One extreme is a production system with very high accuracy in production measurements. Due to
increased hardware costs and intensive operator involvement, the project and operating costs are higher,
but with more and better information, better reservoir management and production optimization can be
carried out. Consequently, the uncertainty band in the ultimate recovery decreases, giving a lower spread
in project and operating risks (see Figure 2). Realizing that the value of the oil in the ground is limited, we
can also conclude that at a certain cost level the development becomes economically unattractive.
⎯ The other extreme is a poor accuracy in the production measurements or production is not measured at
all. Poor reservoir management, sub-optimal production optimization and potential loss of revenue are the
result. Consequently, the uncertainty band in the ultimate recovery stays large. The development can
unwittingly become unattractive from an economic and risk point of view.
Somewhere between the above two extremes there is an optimum acceptable uncertainty, with the associated
costs for the measurement and allocation processes. This is illustrated in Figure 3, in which costs (in arbitrary
units) are plotted against acceptable uncertainty. This optimum can well be different for each individual
hydrocarbon development. It can well be the case that, for a particular development, an accuracy of 10 % in
gas flow rate is sufficient while in another development a 2 % accuracy is required.

Figure 3 — Costs related to uncertainty
3.3 Allocation system overview
It is not unusual to take between one and two years to negotiate all the terms of a gas and condensate
allocation agreement. A wide array of skills is required to understand the diverse topics in the development of
an allocation system. To successfully conclude an agreement, it is good practice to form a team with expertise
in the following:
⎯ commercial negotiation;
⎯ gas legislation;
⎯ gas marketing;
⎯ measurement and allocation;
⎯ production operation;
⎯ IT.
Besides the preparation of the commercial agreement, it is necessary to develop the business processes to
manage the day-to-day operation of the agreement. It is imperative to establish responsibilities and ownership
for the following:
⎯ hydrocarbon stream meter data;
⎯ hydrocarbon stream analysis;
⎯ production forecast information;
⎯ allocation system operation.
Development of the business processes requires a review of almost all departments within a gas production
organization to ensure that the workload associated with the operation of the allocation system can be
performed adequately and to identify whether additional personnel or external resources are required.
3.3.1 Overall scope of an allocation agreement
Figure 4 gives an overview of the major issues that feature in a gas and condensate allocation agreement.
These issues are discussed separately in the following subclauses. One party or department should be
charged with overall responsibility for producing the agreement, but the party or department may vary from
company to company. It is of utmost importance that all parties or departments involved in the agreement
ensure that the issues affecting them are properly and adequately dealt with in the agreement.
3.3.2 Reservoir performance
Reservoir performance data are required to assist in the forecasting of production to the operator of the gas
treatment facilities. Long-term forecasts issued are likely based partly on the technical view of the reservoir
potential and partly on the commercial view of possible future business. Shorter-term forecasts likely have a
more technical focus and are likely developed in conjunction with operations staff to incorporate planned
shutdowns, etc.
In addition, reservoir engineers provide an overview of the differences in composition of the fluids from the
reservoirs covered by the allocation agreement. Reservoir engineering departments are normally responsible
for the initial sampling and associated fluid analyses. Specific analytical requirements regarding gas quality
should be discussed with the reservoir engineering departments to ensure provision of the appropriate data.
4 © ISO 2008 – All rights reserved

Figure 4 — Issues that feature in a gas and condensate allocation agreement
3.3.3 Project specifications
Discussions are required with the project team to ensure that
⎯ the necessary metering devices are provided to the specified uncertainty levels,
⎯ sampling systems are installed to obtain adequately representative gas and condensate samples,
⎯ acceptable and appropriate analyses of the gas and condensate samples are performed,
⎯ the required data are captured and transferred to a central IT system and an adequate production-
measurement management system is in place (see ISO 10012).
Parties involved in these discussions include the metering and IT departments and, where appropriate, the
operator of the gas treatment facilities.
3.3.4 Operations/gas-trading and coordinating group
A review of the allocation agreement should be made with the parties involved with the agreement to ensure
that they understand and appreciate the implications of the agreement on their day-to-day duties and to
ensure they have the opportunity to feed back potential problems or conflicts with existing agreements and
associated operations.
The gas-trading group should ensure that the allocation agreement complies with gas marketing and reporting
requirements for entry to the gas distribution network from the gas treatment facilities.
3.3.5 Metering requirements
Appropriately qualified and experienced metering engineers should be responsible for specifying and selecting
the individual meters and associated equipment. When operations start, they should be responsible for the
validation of metering data.
The validated meter data should be made available to the hydrocarbon accountants to run the allocation
calculations and generate the allocation reports. It is necessary that the validation process for the metered
data be performed independently of the allocation calculations. There is a tendency to use allocation
processes as a check on the quality of the metering process. Balance factors or reconciliation factors can be
used, with care, to highlight possible metering problems. Ideally, limits to these factors should be set based on
sensitivity studies with the intrinsic uncertainties of the individual meters as input.
3.3.6 Laboratory requirements
Pressurized samples of gas and condensate are sent to a laboratory that has been selected for the shared
pipeline system. The selected laboratory should have appropriate, acceptable accreditation.
Procedures should be developed for
⎯ control and maintenance of the sample vessels,
⎯ transportation of pressurized sample vessels between the production facilities and the laboratory,
⎯ receipt and validation of the sample fluids,
⎯ conducting and reporting of the analyses.
3.3.7 Commercial issues
The commercial group should review the allocation agreement for consistency with other agreements.
3.3.8 Legal issues
In general, the allocation agreement is written by the responsible allocation personnel, with the metering
section of the agreement produced by the metering engineer and the commercial issues dealt with by the
commercial department. A review by the legal department is required to check for consistency with other
agreements and that the liability clauses are appropriate and acceptable.
3.3.9 Tax issues
In some jurisdictions, the tax and royalty implications associated with a field and/or a party can have the most
dominant impact on the revenue from an allocation system. A review is essential at the early stages of a
development to ascertain any tax implications and incorporate the appropriate mechanisms within the
allocation procedure.
Customs duties can be particularly relevant when gas and condensate from a development is produced into a
shared pipeline in one country and entitlement to blended gas and condensate is received in another country.
3.3.10 Statutory requirements
It is essential at an early stage in a development to undertake a review of the statutory requirements and seek
the necessary approvals from the appropriate governing bodies.
6 © ISO 2008 – All rights reserved

3.3.11 IT systems
The development of an IT system to perform the allocation procedure can take a significant period of time to
implement, test and hand over to the responsible department. Because of tight development deadlines, it can
be necessary to start the IT system design before the commercial agreement is finalized and strict project
management is required to control the IT vendor and minimize change requests.
The software should be developed in a structure suitable to the application, with particular attention paid to the
ability to modify/expand the system whilst maintaining the capability to revert to rerunning a pre-modification
allocation.
3.3.12 Overall metering system
The entire process of metering and allocation (the metering hardware, the algorithms used, the data
transmission and storage systems) should be covered by an adequate management process (see
ISO 10012).
4 Allocation from different viewpoints and terminology
4.1 Physical system
This Technical Report is intended for use in the measurement and allocation of natural gas and condensate in
multi-user pipeline transportation systems.
Such a system is typically comprised of production facilities, pipelines, reception facilities, processing facilities
and sales points. Each of these elements can be represented in the allocation system described in 4.2 to 4.5
(see Figure 5 for an example of a typical system).
4.2 Gas/condensate system overview
4.2.1 System diagram
The physical system can be represented as a single-line nodal diagram, representing all the (production)
sources, sinks (gas used for fuel, flare, vent, gas lift, injection gas, etc.), as well as flow paths of product. See
Figure 5.
Figure 5 — Physical system
8 © ISO 2008 – All rights reserved

Figure 6 — Allocation system diagram
A supporting table (Table 1) developed from the system diagram (see Figure 6) describes what each node in
the system represents, what the name of the producing field asset can be, the equity ownership interests, etc.
It can further describe any product processing, calculations, simulations, yield factors, etc., as well as the
allocation protocol for the node concerned.
The system description table (diagram) can look something like Table 1:
Table 1 — System description table
Node no. Process Equity Allocation — Comments
function ownership protocol/function

Other information can be provided, such as the following:
a) source: Any product feed entering a system node; this is generally a production
stream coming from one or more wells or production facilities.
b) sink: Any product feed leaving a system node; this is generally gas and condensate
sales streams but also water disposal streams, flare gas flows, blow-off gas, etc.
c) node: Any point in the system defined for the purpose of quantifying the quantity and
quality of product passing through it.
d) commingling: Combination of product streams from two or more wells or production
facilities into a common separator, pipeline or tank.
e) reconciliation: The process of dealing with any quantity imbalance between sources and
sinks; possible phase changes between the gas and condensate phase can be taken
into account as well. Reconciliation can take place at any node in the system and is
usually done at agreed periodic intervals.
4.2.2 Allocation process
This is the process by which a quantity of hydrocarbon gas and hydrocarbon condensate, measured at a sink
(e.g. sales point) is allocated to one or more contributing sources. (See Figure 7 for an example of a typical
allocation process flow chart.)
10 © ISO 2008 – All rights reserved

a
Checks here also include the sub-process of reconciliation, or system balance, i.e. what is reported as being
delivered with what has actually been received. This is usually done periodically and at agreed-upon intervals.
Figure 7 — Typical allocation process flow chart
4.3 Physical system terms
4.3.1 Fluid definitions — General
Some definitions are given below for single-phase fluid streams (e.g. gas, water and liquid streams) and
multiphase fluid streams (e.g. wet gas streams and multiphase streams). Unlike the downstream and transport
and distribution businesses, for the upstream area it is not the case that all fluid streams are properly
conditioned to a single phase or indeed stay in a single phase over a large range of pressure and
temperature. In the upstream area, the fluids are often unstable, and any pressure and temperature change
(even a ∆p in a measurement device or over a valve) can cause a phase change and change a single-phase
fluid into a multiphase fluid. Accordingly, all definitions below should be referred to the operation ranges of
temperature and pressure that occur in the system under consideration.
4.3.2 Definitions for fluids
4.3.2.1
equation of state
EoS
mathematical expression that relates the composition, pressure and temperature of a fluid
NOTE For an ideal gas, the equation of state is the ideal gas law. More complicated equations of state have been
developed to model the behaviour of actual gases over a range of pressures and temperatures, e.g. Benedict, Webb,
Rubin (BWR equation) and Soave, who modified Redlich & Kwong's equation (SRK equation).
4.3.2.2
dry gas
treated gas
clean dry gas (not necessarily only hydrocarbons but may contain other components such as CO , N , etc.)
2 2
where no liquid is present and no liquid condensation is expected over the expected normal operating
temperatures and pressures at the metering point
EXAMPLE Gas with a dew point of − 5 °C that is measured under conditions between 5 °C and 10 °C.
4.3.2.3
equilibrium gas
〈separated at dew point〉 dry gas at its dew point but without the presence of liquid condensation (typically gas
at the outlet of a properly functioning separator)
NOTE Any change in temperature or pressure can cause a change of state of the gas towards a dry gas or a wet
gas.
4.3.2.4
wet gas
〈two- or three-phase〉 any mixture of gas and up to about 10 % by volume liquid hydrocarbon and/or water
NOTE The mass ratio of gas to liquid varies significantly with pressure for a constant gas volume fraction. A
convenient parameter to indicate the wetness of the gas is the Lockhart-Martinelli parameter (see 4.3.2.15).
4.3.2.5
single-phase hydrocarbon liquid
liquid at a pressure above its equilibrium pressure (bubble point)
EXAMPLE Liquid below the level of the outlet of a separator where static head (or booster pumps) increase(s) the
pressure above the equilibrium pressure.
NOTE The hydrocarbon liquid can contain traces of water.
12 © ISO 2008 – All rights reserved

4.3.2.6
single-phase water
water with a pressure above its equilibrium pressure (bubble point)
NOTE Some traces of liquid hydrocarbons may be present.
4.3.2.7
equilibrium liquid
separated liquid at bubble point
hydrocarbon liquid at its equilibrium pressure and temperature, which does not contain any gas
NOTE However, any further pressure or temperature change can cause gas to be released. True equilibrium liquid is
very rare in gas-condensate processing as the dynamic nature of the processes does not allow sufficient time for liquids to
reach equilibrium conditions.
4.3.2.8
gassy liquid
〈two or three phases〉 any mixture of hydrocarbon liquid and water at a pressure below its equilibrium pressure
(bubble point) and where gas is present in the liquid mixture
NOTE This typically occurs inside a separator or where the liquid is exposed to a pressure reduction, e.g. cavitation.
4.3.2.9
gas-oil ratio
GOR
ratio of produced gas flow rate to the produced oil (condensate) flow rate
NOTE GOR is generally measured in standard units, e.g. cubic metres per cubic metre (standard cubic feet per
barrel).
4.3.2.10
gas-condensate ratio
GCR
ratio of produced gas flow rate to the produced condensate flow rate
NOTE The GCR is generally measured in standard units, e.g. cubic metres per cubic metre (standard cubic feet per
barrel).
4.3.2.11
gas-liquid ratio
GLR
ratio of produced gas flow rate to the produced total liquid flow rate
NOTE The GLR is generally measured in standard units, e.g. cubic metres per cubic metre (standard cubic feet per
barrel).
4.3.2.12
watercut
water-liquid ratio
WLR
volumetric fraction of water in the total liquid stream (water plus liquid hydrocarbons), with both volumes
determined at the same pressure and temperature
4.3.2.13
water fraction
volumetric fraction of water in the total fluid stream (water, liquid hydrocarbons and gas hydrocarbons), with
both volumes determined at the same pressure and temperature
NOTE Water fraction is often used in wet-gas applications.
4.3.2.14
gas volume fraction
GVF
ratio of produced gas flow rate to the produced fluid (gas plus liquid) flow rate
NOTE The GVF is generally measured under actual conditions, e.g. cubic metres per cubic metre, and expressed as
a fraction.
4.3.2.15
Lockhart-Martinelli parameter
X
dimensionless parameter, useful in the analysis of multiphase flow, that is expressed as given in Equation (1):
Q ρ
ll
X= . (1)
Q ρ
gg
where
Q is the liquid volume flow rate at line conditions, expressed in cubic metres per day;
l
Q is the gas volume flow rate at line conditions, expressed in cubic metres per day;
g
ρ is the liquid density at line conditions, expressed in kilograms per cubic metre;
l
ρ is the gas density at line conditions, expressed in kilograms per cubic metre.
g
4.3.2.16
multiphase fluid
〈oil and gas production〉 mixture of the three phases: liquid hydrocarbon, water and gas
NOTE Almost all fluids encountered in oil and gas production are multiphase fluids. There are broad categories of
multiphase fluid, e.g. wet gas (4.3.2.4) where the GVF is typically > 90 %; fluids from a wide range of oil wells where
5 % < GVF < 90 %; and the low-GVF, “gassy’ oils”. It is important to realize that “multiphase fluid” is not a well defined
substance.
4.4 Definitions for allocation systems
NOTE See Annex D for lists of letters for 3-letter abbreviations.
4.4.1 Allocation principles
4.4.1.1
mass component
total mass of a single chemical component within a stream, the total of all components being equal to the total
mass delivered by that stream
4.4.1.2
energy
〈gas/condensate allocation〉 heat energy released when the gas or condensate is subject to combustion under
specified conditions
NOTE Energy may be expressed per unit mass, per unit (standard or normal) volume or per mole, at various
reference temperatures and pressures, with or without the condensation energy of the water vapour formed during
combustion. Reference can be made to ISO 6976 for further information.
14 © ISO 2008 – All rights reserved

4.4.1.3
yield factor
expected returns of hydrocarbon liquids as a proportion of the potential liquids contained within a gas stream
4.4.1.4
delivery point
final measurement point(s) where hydrocarbons leave a single allocation stage
4.4.1.5
source point
entry of a product stream into a single allocation stage
NOTE Quantities associated with source points may be measured or derived.
4.4.1.6
allocation point
any node in an allocation system to which product is allocated
4.4.1.7
components
individual chemical compounds within a product stream
EXAMPLES CH , methane, also designated C ; C H , ethane, also designated C .
4 1 2 6 2
4.4.1.8
lift gas
gas that is pumped down a well to assist in that well’s production
NOTE For the purposes of allocation, all the gas pumped down the well is assumed to be recovered with the well
production fluids. However, the lift gas can mix with the reservoir gas and can change its composition. This can affect a
volume-based allocation.
4.4.1.9
injection gas
gas injected into the field’s reservoir to maintain reservoir pressure
NOTE The gas is not specific to any one producing well, as is the case with lift gas, and the gas might not appear
from production wells until, perhaps, years after injection has begun. The allocation of injection gas is usually different
from the allocation of lift gas.
4.4.1.10
utility gas
gas that is vented, flared or burnt as part of normal operations
NOTE Utility gas includes the following:
⎯ vent/flare gas: It is necessary for all producing fields to have a means of maintaining a positive pressure in all vent
lines from the processing facilities to atmosphere under normal operating conditions and also to have
the capability to vent large amounts of gas in case of an emergency. At present, the method to do this
is to continuously vent gas to atmosphere. Relatively small quantities of gas can be vented into the
atmosphere un-ignited from some facilities. Usually, to make the gas safe, it is ignited on leaving the
vent stack, when it is known as flare gas. This gas is waste product but it is necessary to account for it
a) in normal operation, when there are usually small quantities and b) when large amounts are vented
during an emergency. The allocation for these two scenarios is usually different.
⎯ fuel gas: Fuel gas used by the plant is usually provided from the gas extracted from the incoming fluids. The
allocation of fuel gas is usually driven by commercial or contractual considerations, so measurement
applications can be very varied. New European environmental laws require operators to calculate the
amount of CO vented to the atmosphere; hence this requires the amount of CO to be measured and
2 2
allocated. (A component-based allocation system seems to be suitable for this.)
⎯ start-up gas: Gas imported from other facilities to fill pipelines or equipment on facilities prior to start-up. Depending
on size and pressure of the system, these quantities of gas can be large [e.g. for a 300 km, 91.5 cm
(36 in) pipeline operating at 13 MPa (130 bar)] and should be taken into account in the allocation
process.
4.4.1.11
condensate-gas ratio
CGR
ratio of condensate to gas
NOTE The condensate-gas ratio can be expressed on either a mass or a volume basis.
4.4.2
attribution
process of calculating a final quantity for each allocation point based on its assigned substitution and allocated
quantities
4.4.3
substitution
process, in any system where nominations are used to target deliveries of products, whereby the difference
between target production (nomination) and allocated deliveries are reduced through exchanges between
allocation points
4.4.4
apportionment received at the allocation point
process of pro-rating an allocated/attributed quantity where the same ownership exists for all sources
4.4.5
system balance
performance indicator used to track the difference between the sum of all sources and all delivery points for
an allocation system or single allocation stage
4.4.6
node
any originating point to an allocation system or a point with two or more streams attached
4.4.7
stream
〈allocation modelling〉 line depicting the flow of product from a source node to a delivery node
4.4.8
validation
process of performing data checks
4.4.9
mis-measurement
process resulting in an erroneous quantity or quality value being recorded and entered into an allocation
system
NOTE The error in the value can be caused by faulty or incorrect equipment, incorrect configuration or correction
factors.
4.5 Allocation from a commercial viewpoint
4.5.1 General
Prior to entering into gas allocation system negotiations, it is important to understand the underlying
framework of commercial agreements (either existing or being negotiated) and the technical characteristics of
the production system, pipeline and terminal. For example, each system user’s perception of the local gas
16 © ISO 2008 – All rights reserved

market influences the importance that party places on different aspects of the allocation agreement, such as
the following:
a) security of gas supply with the aim to sell gas on a long-term contract:
⎯ allocation and attribution period set at a day,
⎯ limited re-nomination with relatively long lead times,
⎯ priority system for the attribution process,
⎯ mechanisms for notified and system substitution,
⎯ pipeline stock controlled by the pipeline system operator;
b) flexibility of gas supply in a de-regulated system with the aim to sell gas on the spot market:
⎯ allocation period set at less than a day,
⎯ relatively short re-nomination lead times,
⎯ no priority system with the allocation process,
⎯ no gas substitution,
⎯ all no
...