DEP SPECIFICATION

CUSTODY TRANSFER MEASUREMENT SYSTEMS FOR

GASES AND VAPOURS

DEP 32.32.00.12-Gen.

February 2013
ECCN EAR99

DESIGN AND ENGINEERING PRACTICE

© 2013 Shell Group of companies

All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, published or transmitted, in any form or by any means, without the prior
written permission of the copyright owner or Shell Global Solutions International BV.

This document contains information that is classified as EAR99 and, as a consequence, can neither be exported nor re-exported to any country which is under an
embargo of the U.S. government pursuant to Part 746 of the Export Administration Regulations (15 C.F.R. Part 746) nor can be made available to any national of such
country. In addition, the information in this document cannot be exported nor re-exported to an end-user or for an end-use that is prohibited by Part 744 of the Export
Administration Regulations (15 C.F.R. Part 744).
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PREFACE

DEP (Design and Engineering Practice) publications reflect the views, at the time of publication, of Shell Global Solutions
International B.V. (Shell GSI) and, in some cases, of other Shell Companies.
These views are based on the experience acquired during involvement with the design, construction, operation and
maintenance of processing units and facilities. Where deemed appropriate DEPs are based on, or reference international,
regional, national and industry standards.
The objective is to set the standard for good design and engineering practice to be applied by Shell companies in oil and
gas production, oil refining, gas handling, gasification, chemical processing, or any other such facility, and thereby to help
achieve maximum technical and economic benefit from standardization.
The information set forth in these publications is provided to Shell companies for their consideration and decision to
implement. This is of particular importance where DEPs may not cover every requirement or diversity of condition at each
locality. The system of DEPs is expected to be sufficiently flexible to allow individual Operating Units to adapt the
information set forth in DEPs to their own environment and requirements.
When Contractors or Manufacturers/Suppliers use DEPs, they shall be solely responsible for such use, including the
quality of their work and the attainment of the required design and engineering standards. In particular, for those
requirements not specifically covered, the Principal will typically expect them to follow those design and engineering
practices that will achieve at least the same level of integrity as reflected in the DEPs. If in doubt, the Contractor or
Manufacturer/Supplier shall, without detracting from his own responsibility, consult the Principal.
The right to obtain and to use DEPs is restricted, and is typically granted by Shell GSI (and in some cases by other Shell
Companies) under a Service Agreement or a License Agreement. This right is granted primarily to Shell companies and
other companies receiving technical advice and services from Shell GSI or another Shell Company. Consequently, three
categories of users of DEPs can be distinguished:
1) Operating Units having a Service Agreement with Shell GSI or another Shell Company. The use of DEPs by these
Operating Units is subject in all respects to the terms and conditions of the relevant Service Agreement.
2) Other parties who are authorised to use DEPs subject to appropriate contractual arrangements (whether as part of
a Service Agreement or otherwise).
3) Contractors/subcontractors and Manufacturers/Suppliers under a contract with users referred to under 1) or 2)
which requires that tenders for projects, materials supplied or - generally - work performed on behalf of the said
users comply with the relevant standards.
Subject to any particular terms and conditions as may be set forth in specific agreements with users, Shell GSI disclaims
any liability of whatsoever nature for any damage (including injury or death) suffered by any company or person
whomsoever as a result of or in connection with the use, application or implementation of any DEP, combination of DEPs
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Without prejudice to any specific terms in respect of confidentiality under relevant contractual arrangements, DEPs shall
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GSI may at any time require information satisfactory to them in order to ascertain how users implement this requirement.
All administrative queries should be directed to the DEP Administrator in Shell GSI.
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TABLE OF CONTENTS
1. INTRODUCTION ........................................................................................................ 5
1.1 SCOPE........................................................................................................................ 5
1.2 DISTRIBUTION, INTENDED USE AND REGULATORY CONSIDERATIONS ......... 5
1.3 DEFINITIONS ............................................................................................................. 5
1.4 CROSS-REFERENCES ............................................................................................. 7
1.5 SUMMARY OF MAIN CHANGES ............................................................................... 8
1.6 COMMENTS ON THIS DEP ....................................................................................... 8
1.7 DUAL UNITS ............................................................................................................... 8
2. COMMON SYSTEM REQUIREMENTS ..................................................................... 9
2.1 INTRODUCTION ........................................................................................................ 9
2.2 REQUIREMENT HIERARCHY ................................................................................... 9
2.3 AGREEMENTS ........................................................................................................... 9
2.4 MEASUREMENT STANDARD SELECTION.............................................................. 9
2.5 ENGINEERING UNITS ............................................................................................... 9
2.6 BASE CONDITIONS ................................................................................................. 10
2.7 RESPONSIBILITIES ................................................................................................. 10
3. SYSTEM DESIGN .................................................................................................... 11
3.1 INTRODUCTION ...................................................................................................... 11
3.2 APPROVALS ............................................................................................................ 11
3.3 MEASUREMENT UNCERTAINTY ........................................................................... 12
3.4 GENERAL DESIGN REQUIREMENTS .................................................................... 12
3.5 SYSTEM AVAILABILITY........................................................................................... 13
3.6 RANGEABILITY ........................................................................................................ 14
3.7 TRACEABILITY ........................................................................................................ 15
3.8 DEVICE VALIDATION CAPABILITY ........................................................................ 15
3.9 OPERATING ENVELOPE ........................................................................................ 16
3.10 MATERIALS .............................................................................................................. 16
3.11 ELECTRICAL ............................................................................................................ 17
3.12 ENVIRONMENTAL PROTECTION .......................................................................... 18
3.13 SKID, STRUCTURAL AND BASEPLATE................................................................. 18
3.14 PIPING AND VALVING ............................................................................................. 19
3.15 FLOW CONDITIONING ............................................................................................ 21
3.16 STRAINERS.............................................................................................................. 21
3.17 FLUID COMPOSITION DETERMINATION .............................................................. 22
3.18 COMPUTATIONAL DEVICES .................................................................................. 23
4. SPECIFIC APPLICATION REQUIREMENTS .......................................................... 23
4.1 MASS MEASUREMENT ........................................................................................... 23
4.2 VOLUMETRIC MEASUREMENT ............................................................................. 24
4.3 ENERGY MEASUREMENT ...................................................................................... 24
5. METER REQUIREMENTS ....................................................................................... 25
5.1 GENERAL REQUIREMENTS ................................................................................... 25
5.2 MULTI-PATH ULTRASONIC METERS .................................................................... 25
5.3 CORIOLIS METERS ................................................................................................. 26
5.4 ORIFICE METERS ................................................................................................... 27
5.5 TURBINE METERS .................................................................................................. 28
5.6 VENTURI METERS .................................................................................................. 28
6. SECONDARY INSTRUMENTS ................................................................................ 29
6.1 INTRODUCTION ...................................................................................................... 29
6.2 TEMPERATURE ....................................................................................................... 29
6.3 PRESSURE .............................................................................................................. 29
6.4 QUALITY MEASUREMENT INSTRUMENTS .......................................................... 30
7. COMPUTATIONAL DEVICES.................................................................................. 31
7.1 GENERAL REQUIREMENTS ................................................................................... 31
7.2 COMPUTATIONS ..................................................................................................... 31
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8. SECURITY AND SEALING ...................................................................................... 32

9. METER VALIDATION .............................................................................................. 33
9.1 GENERAL ................................................................................................................. 33
9.2 CHECK METERS ..................................................................................................... 33
9.3 MASTER METERS ................................................................................................... 33
10 SAMPLING ............................................................................................................... 34
10.1 GENERAL ................................................................................................................. 34
11. FACTORY AND FIELD INSPECTION AND TESTING ............................................ 34
11.1 GENERAL ................................................................................................................. 34
11.2 SKID .......................................................................................................................... 35
11.3 INSTRUMENTATION ............................................................................................... 35
11.4 PIPING SYSTEMS .................................................................................................... 36
11.5 ELECTRICAL ............................................................................................................ 36
11.6 CALIBRATION EQUIPMENT AND FACILITIES....................................................... 36
11.7 SITE ACCEPTANCE TEST ...................................................................................... 37
12. PRESERVATION AND PREPARATION FOR SHIPMENT ..................................... 37
13. DOCUMENTATION .................................................................................................. 38
13.1 GENERAL ................................................................................................................. 38
13.2 DOCUMENTATION REQUIRED WITH THE PROPOSAL ....................................... 39
13.3 DOCUMENTATION REQUIRED ON COMPLETION ............................................... 39
13.4 CERTIFICATES AND REPORTS ............................................................................. 40
14. REFERENCES ......................................................................................................... 41

APPENDICES
APPENDIX A BLACK AND WHITE LIST .............................................................................. 45
APPENDIX B COMMON ENGINEERING UNITS .................................................................. 50
APPENDIX C BASE CONDITIONS ....................................................................................... 51
APPENDIX D TYPICAL SINGLE METER RUN CTM GAS APPLICATION EXAMPLE ....... 52
APPENDIX E ANALYTICAL METHODS ............................................................................... 53
APPENDIX F “Z” MASTER METER CONFIGURATION EXAMPLE ................................... 54
APPENDIX G LINING UP OF DENSITOMETERS IN ORIFICE METER RUNS
(POCKET STYLE) ........................................................................................... 55
APPENDIX H THERMAL INSULATION FOR DENSITOMETERS AND
TEMPERATURE SENSORS ........................................................................... 56
APPENDIX I FLOW COMPUTATION TYPICAL EXAMPLES ............................................. 57
APPENDIX J EXAMPLE OF MEASUREMENT SYSTEM ARCHITECTURE....................... 59
APPENDIX K DATA ACQUISITION AND CONTROL ARCHITECTURE ............................. 60
APPENDIX L FLOW COMPUTER DETAILED REQUIREMENTS ....................................... 61
APPENDIX M TYPICAL MULTI METER RUN WITH MASTER METER ............................... 63
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1. INTRODUCTION

1.1 SCOPE
This DEP specifies requirements and gives recommendations for the design, fabrication,
installation and commissioning of custody transfer measurement systems. Application of
this DEP is limited to single phase homogenous fluids, which are gases or vapours at the
measurement conditions such as natural gas, steam and hydrogen.
Custody transfer measurement systems associated with pipeline receipt or delivery
applications are included in the scope of this DEP. Custody transfer measurement systems
at the retail level of trade (e.g., residential gas meters) are outside the scope of this DEP.
LNG custody transfer measurement is also outside the scope of this DEP, see
DEP 32.32.00.11-Gen.
Metering requirements associated with allocation meters upstream of the natural gas
custody transfer meters are outside the scope of this DEP, see DEP 32.00.00.12-Gen.
This DEP encompasses mass, volumetric and energy measurement.
This DEP shall be used in conjunction with requisition sheet DEP 32.32.00.95-Gen.
This is a revision of the DEP of the same number dated September 2007; see (1.5)
regarding the changes.

1.2 DISTRIBUTION, INTENDED USE AND REGULATORY CONSIDERATIONS

Unless otherwise authorised by Shell GSI, the distribution of this DEP is confined to Shell
companies and, where necessary, to Contractors and Manufacturers/Suppliers nominated
by them. Any authorised access to DEPs does not for that reason constitute an
authorisation to any documents, data or information to which the DEPs may refer.
This DEP is intended for use in facilities related to oil and gas production, gas handling, oil
refining, chemical processing, gasification, distribution and supply/marketing. This DEP
may also be applied in other similar facilities.
When DEPs are applied, a Management of Change (MOC) process shall be implemented;
this is of particular importance when existing facilities are to be modified.
If national and/or local regulations exist in which some of the requirements could be more
stringent than in this DEP, the Contractor shall determine by careful scrutiny which of the
requirements are the more stringent and which combination of requirements will be
acceptable with regards to the safety, environmental, economic and legal aspects. In all
cases, the Contractor shall inform the Principal of any deviation from the requirements of
this DEP which is considered to be necessary in order to comply with national and/or local
regulations. The Principal may then negotiate with the Authorities concerned, the objective
being to obtain agreement to follow this DEP as closely as possible.

1.3 DEFINITIONS
1.3.1 General definitions
The Contractor is the party that carries out all or part of the design, engineering,
procurement, construction, commissioning or management of a project or operation of a
facility. The Principal may undertake all or part of the duties of the Contractor.
The Manufacturer/Supplier is the party that manufactures or supplies equipment and
services to perform the duties specified by the Contractor.
The Principal is the party that initiates the project and ultimately pays for it. The Principal
may also include an agent or consultant authorised to act for, and on behalf of, the
Principal.
The word shall indicates a requirement.
The word should indicates a recommendation.
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1.3.2 Specific definitions

Term Definition
Base Standard reference, base or standard conditions; henceforth, base
Conditions conditions are the reference conditions of temperature and pressure to
which measured volumes are to be corrected for reporting purposes. See
(2.6) and (Appendix C) for details.
Custody Custody transfer measurement provides highest accuracy quantity and
Transfer quality information used for the physical and fiscal documentation of a
change in ownership and/or a change in responsibility for feed stocks, fuel,
products, etc. Synonymous with fiscal measurement, with the exclusion of
government implications such as taxation and royalties.
Fiscal Measurement pertaining to government income and revenues such as
Measurement taxation and royalties.
Validation In jurisdictions where API MPMS terminology is utilized, measurement
equipment performance assurance is denoted by the terms verification
(i.e., assessment of the as-found state of the device relative to a reference
standard) and calibration (i.e., device output adjustment to conform to
reference standard value).
In jurisdictions where OIML/ISO terminology is utilized, measurement
equipment performance assurance is denoted by the terms calibration (i.e.,
verification as defined above) and adjustment (i.e., calibration as defined
above).
In this DEP, the term “validation” shall be used to denote the process of
verification followed by calibration if required.
Meter validation is typically termed meter proving.
Master Meter A meter of comparable or lower uncertainty used to verify/calibrate a
custody transfer meter.
N+1 Number of required runs plus spare.
Pay and A redundant measurement system whereby one system produces the fiscal
Check data and the other checks the outcome of the previous.
Reference Reference conditions are a specified temperature and pressure at which
Conditions physicals properties or volumes are reported. See (2.6) and (Appendix C)
for details.

1.3.3 Abbreviations

Term Definition
AGA American Gas Association
AMS Asset Management System
API American Petroleum Institute
ATEX European Union directives describing explosive atmosphere equipment
requirements
BIPM Bureau International des Poids et Mesures
BPCS Basic Process Control System
CCR Central Control Room
CSA Canadian Standards Association
CTM Custody Transfer Measurement
D Nominal Pipe Internal Diameter
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Term Definition
DB&B Double block and bleed
FAT Factory Acceptance Test
TM
FF FOUNDATION FIELDBUS
FGS Fire and Gas System
GC Gas Chromatograph
GPA Gas Processors Association
HART® Highway Addressable Remote Transducer
HPIMS Hydrocarbon Production Information Management System
HFE Human Factors Engineering
IAPWS International Association for the Properties of Water and Steam
IPS Instrument Protective System
ISO International Organization for Standardization
IUPAC International Union of Pure and Applied Chemistry
LCR Local Control Room
MESC Materials, Equipment, Standards and Code
MID European Measuring Instruments Directive
MPMS API Manual of Petroleum Measurement Standards
NDI Non-Destructive Inspection
NIST National Institute of Standards and Technology
NMI National Metrology Institute
NPL National Physical Laboratory
NTEP National Type Evaluation Program
PEFS Process Engineering Flow Scheme (i.e., P&ID)
P&ID Piping and Instrumentation Diagram (i.e., PEFS)
QMI Quality Measurement Instrument
RTD Resistance Temperature Detector
PLC Programmable Logic Controller
SAT Site Acceptance Test
SCADA Supervisory Control and Data Acquisition
STP IUPAC Standard Temperature and Pressure
TCoO Total Cost of Ownership
UL Underwriters Laboratories Inc.

1.4 CROSS-REFERENCES
Where cross-references to other parts of this DEP are made, the referenced section
number is shown in brackets ( ). Other documents referenced by this DEP are listed in (14).
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1.5 SUMMARY OF MAIN CHANGES

This DEP is a revision of the DEP of the same number dated September 2007. The
following are the main, non-editorial changes.

Section Change
All Major DEP revision to include fluids other than natural gas and
North American measurement standards.
Document was restructured to harmonize with DEP for custody
transfer measurement of liquids.
All run and maintain activities, which are outside the scope of a
DEP Specification, were removed.

1.6 COMMENTS ON THIS DEP

Comments on this DEP may be submitted to the Administrator using one of the following
options:

Shell DEPs Online Enter the Shell DEPs Online system at

https://www.shelldeps.com
(Users with access to
Shell DEPs Online) Select a DEP and then go to the details screen for
that DEP.
Click on the “Give feedback” link, fill in the online
form and submit.

DEP Feedback System Enter comments directly in the DEP Feedback

(Users with access to System which is accessible from the Technical
Shell Wide Web) Standards Portal http://sww.shell.com/standards.
Select “Submit DEP Feedback”, fill in the online form
and submit.

DEP Standard Form Use DEP Standard Form 00.00.05.80-Gen. to record

(Other users) feedback and email the form to the Administrator at
standards@shell.com.

Feedback that has been registered in the DEP Feedback System by using one of the above
options will be reviewed by the DEP Custodian for potential improvements to the DEP.

1.7 DUAL UNITS

This DEP contains both the International System (SI) units, as well as the corresponding
US Customary (USC) units, which are given following the SI units in brackets. When
agreed by the Principal, the indicated USC values/units may be used.
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2. COMMON SYSTEM REQUIREMENTS

2.1 INTRODUCTION
Custody transfer measurement systems are designed to provide accurate, equitable and
reliable measurements. This is achieved by pre-establishing and then meeting the
regulatory, contractual and the Principal’s requirements. This mitigates the risk of breach of
contract, financial loss or non-compliance. The use of industry measurement standards lays
the foundation for appropriate custody transfer measurement system design.

2.2 REQUIREMENT HIERARCHY

Prior to system design, the uncertainty, regulatory, contractual and the Principal’s business
process requirements shall be defined. The requirement hierarchy for custody transfer
measurements is as follows:
1. Safety
2. Regulatory (i.e., local legal/metrology authorities)
3. Contractual
4. Principal’s design practices and business process (e.g., HPIMS)
The system shall be designed to meet the most stringent of these requirements. The CTM
System Datasheet, DEP 32.32.00.95-Gen., shall be used to summarize critical design
parameters including applicable regulations and Industry standards.

2.3 AGREEMENTS
The measurement sections of contracts (e.g., tariffs, connection agreements, sales and
purchase agreements) should refer to general custody transfer measurement requirements.
Measurement requirements should be expanded in an addendum (i.e., exhibit, attachment)
to the contract thus avoiding undue revision of the contract if only technical requirements
change. Measurement details such as procedures and measurement uncertainty
calculations should be addressed in a Measurement Manual. The “Black and White List”
(Appendix A) should be reviewed when preparing the contract.

2.4 MEASUREMENT STANDARD SELECTION

This DEP contains references to measurement standards typically utilized within the
Americas (e.g., API MPMS, AGA) and those utilized typically outside of the Americas
(e.g., ISO). However, subject to (2.2), there is no intent to prohibit use of API standards
outside of the Americas and vice versa. In some instances where there is overlap of
industry standards, a recommendation is made to use one standard rather than another
(e.g., more up-to-date standard available).
The Industry standards revision current at the time the agreement is executed shall apply to
the measurement system at the time of design. To avoid incurring cost without appropriate
benefits, later editions of Industry standards shall only be implemented with the consent of
the relevant parties.

2.5 ENGINEERING UNITS

All calculated and measured values (temperature, pressure, mass, volume, density
heating/calorific value, etc.) shall be expressed in units according to the International
System of units (SI). See DEP 00.00.20.10-Gen. Values in other units where required
(e.g., cubic feet) shall be derived from the SI units. Use of non-SI engineering units requires
the approval of the Principal.
The engineering units to be used for a specific facility shall be defined prior to design and
detailed in DEP 32.32.00.95-Gen.
See (Appendix B) for common SI and US customary engineering units.
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2.6 BASE CONDITIONS

For volumetric measurements where the measured quantity is to be corrected from flowing
conditions to base conditions (also called standard or normal conditions), the base
conditions and nominal site barometric pressure shall be defined prior to design and
detailed in DEP 32.32.00.95-Gen.
See (Appendix C) for a discussion of base conditions.

2.7 RESPONSIBILITIES
The Contractor’s scope of work shall include system design, equipment selection, and
documentation of the measurement system and oversight of the Supplier. The Supplier’s
scope of work shall include fabrication, inspection, testing, delivery, and the initial
calibration of the complete gas metering system.
The Contractor shall assume full system responsibility. This means that the Contractor shall
have, as a minimum, single point responsibility for the following:
a) designing the custody transfer measurement system in accordance with this DEP
and all applicable codes and standards,
b) the operability, accuracy and quality of all components including those of sub-
suppliers,
c) obtaining written approvals from the Principal, regulatory authorities and all
interested parties for the design prior to procurement and fabrication,
d) all performance based testing,
e) obtaining all permits, certifications and calibrations (e.g., meters),
f) demonstrating satisfactory system performance via a FAT, SAT and site
commissioning,
g) timely notification of upcoming shop and field testing to permit witnessing (Principal,
authorities, interested parties),
h) providing appropriate documentation,
i) fabrication, delivery and installation oversight.
The Supplier shall prepare a preliminary design with appropriate documentation (13.2) for
approval by the Principal in writing prior to equipment procurement.
Where applicable, the Supplier shall be required to liaise with the main data acquisition
system Supplier (to be advised by the Principal) to arrange the data links and protocols
necessary for monitoring and control of the metering system and the data transfer required
for accounting purposes.
The Supplier shall immediately inform the Contractor and the Principal if there is doubt
regarding the specified requirements. The Supplier shall not proceed with any aspect of the
work until the Principal gives the necessary written approval.
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3. SYSTEM DESIGN

3.1 INTRODUCTION
The measurement system shall be designed to meet all applicable agreements, codes and
standards using field proven methods and devices (i.e., no prototypes). Products shall be
technically qualified to the satisfaction of the Principal and shall be sourced from
Manufacturers acceptable to the Principal.
NOTE: For this purpose, Shell Companies may use the list of Technically Acceptable Manufacturers and
Products (i.e., TAMAP) maintained by Shell.

The total life cycle costs of ownership (TCoO) of the measurement station shall be
optimised against the requirements stated below. A method for calculating the TCoO is
given in DEP 32.31.09.31-Gen.
Prior to the design of custody transfer measurement systems, the following shall be defined
and documented (13):
a) target uncertainty for measurement system,
b) applicable codes, regulations, agreements and standards,
c) ownership of measurement equipment,
d) responsible party for measurement system,
e) measurement basis (mass, volume or energy),
f) acceptable flow meter types,
g) range of process conditions (e.g., fluid types, fluid contaminants, density,
pressures, temperatures, flow rate range, etc.),
h) acceptable validation techniques (e.g., in-situ or remote),
i) base conditions for volumetric techniques,
j) target system availability,
k) third party data transfer connection requirements,
l) engineering units,
m) fluid quality specifications.
n) rangeability factor (3.6), and,
o) measurement system operational control philosophy (consistent with the facility
operational control philosophy).
Selecting the industry measurement standards to be applied in combination with defining
what validation techniques are to be applied will largely determine the potential
measurement uncertainty (3.3).
Where applicable (2.2), the requirements of OIML R140 shall apply.

3.2 APPROVALS
Custody transfer metering installations are usually subject to approval by local authorities or
other interested parties (e.g., JV partners, other producers or refiners, pipeline companies).
These approvals typically extend from the design stage through to final installation and
eventually to the operating stage. Those authorities/interested parties shall be consulted at
the earliest possible stage and thereafter, in order to gain acceptance of the metering
philosophy, approval of the system design (where required) and to simplify final approval of
the installation.
In some cases, local authorities require that devices (e.g., meters, flow computers,
transmitters) have individual approvals (e.g., NMI, NTEP or other Notified Bodies).
ECCN EAR99 DEP 32.32.00.12-Gen.
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However, the fact that a device has such an approval does not negate the necessity to
ensure the devices’ suitability for the application under consideration.
The preliminary design shall be submitted to the Principal for approval prior to detailed
engineering (2.7).

3.3 MEASUREMENT UNCERTAINTY

The overall uncertainty and data availability of the metering station should initially be
estimated from operational experience with other facilities of similar design and purpose,
and may be quoted as target values in the contract.
At the design stage, the potential measurement uncertainty is largely determined by the
prudent selection of which Industry standards apply and the selection of the device
validation/calibration scheme to be applied. When required to demonstrate that the system
design meets the required contractual or regulatory uncertainty, ISO 5168 shall be followed.
Stated uncertainty throughout this document shall be 2 sigma values (approximately 95 %
confidence level).
Uncertainty is inherent to the measuring process and is influenced by the operating
conditions and environment. Typical uncertainty specifications from the measuring
instrument Manufacturer do not necessarily reflect the operating environment of the
instruments concerned. The uncertainty envelope under operating conditions is often
stretched beyond what is quoted by the Manufacturer.

3.4 GENERAL DESIGN REQUIREMENTS

All measurement equipment shall meet the following requirements:
a) all applicable DEPs, regulations and codes (e.g., piping class, electrical,
measurement, process isolation),
b) be suitable for the operating envelope as detailed in Instrument data sheets.
c) be suitable for the electrical area classification in which it will be utilized,
d) have the required uncertainty for the application (e.g., contract, OIML),
e) have the required discipline approvals (e.g., CSA, ATEX, NMI, materials),
f) where required be traceable to a recognized national standards body (e.g., BIPM,
NIST, NPL, NMI),
g) have wetted components suitable for the process fluid.
All designs shall meet the requirements of this DEP, applicable codes, regulations and
standards and deliver the required uncertainty and availability in a safe and cost effective
manner.
Where practical, the meter runs and verification subsystems of custody transfer metering
systems should be designed as skid mounted packages. The control and computational
devices should be located in the computing facility in the CCR, LCR or local equipment
room.
The skid package shall be suitable for the location's prevailing environmental conditions as
specified in DEP 32.32.00.95-Gen. The skid shall include all pipe work, manifolds, metering
streams, valves, electrical, instruments, fittings, etc. It shall be supplied as a fully piped,
cabled, and instrumented package.
The number of parallel meter runs shall be determined by the required flow rate rangeability
(3.6) and availability (3.5).
The maximum allowable pressure drop across the complete metering system should be
less than 200 kPa (30 psi) or as specified in DEP 32.32.00.95-Gen.
Equipment layout shall provide for safe access for device validation and maintenance.
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For meters which are to be calibrated elsewhere, provision shall be made to permit removal
of the meter run without disassembly (i.e., transport meter, upstream and downstream
straight pipe lengths including flow conditioner without unbolting).
Note: Local safety requirements regard lifting of equipment should be taken into account in the design (e.g.,
potential lifting above pressurized lines).

Where required, meter runs shall be thermally insulated in order to reduce heat transfer
from ambient via the piping to avoid hydrocarbon or water condensation and temperature
stratification at low gas flow rates. For volumetric measurements, the length of the insulated
section shall at least satisfy the straight length requirements and shall include the
temperature element and the primary device.
A typical meter run flow scheme for a custody transfer application is illustrated in
(Appendix D) while a redundant custody transfer measurement system architecture is
illustrated in (Appendix I) and (Appendix J). The examples presented in these two
appendices detail a “highly” redundant system whereas typical designs need only meet the
availability requirements detailed in (3.5).
The design shall meet the process control domain security requirements as detailed in
DEP 32.01.20.12-Gen.
3.5 SYSTEM AVAILABILITY
The required system availability and rangeability shall be defined prior to design and
specified in DEP 32.32.00.95-Gen. The design shall incorporate the degree of redundancy
to meet the defined system availability considering the documented reliability of the system
components and subsystems based on the Principal’s experience with similar devices or
Manufacturer’s reliability data. Local availability of spares and expertise to repair equipment
failures in a timely manner shall be considered a part of the availability assessment as well
as continuity of supply.
Subject to (2.2), redundancy computations shall consider any allowance for brief outages or
flow reductions in multi meter designs to accommodate the replacement of faulty
components or for the purposes of verification and/or calibration. In such circumstances,
the maximum flow rate through any of the remaining meters shall not exceed their
calibrated range.
Redundancy shall cover the following elements as a minimum:
a) the meters.
b) the power supply of the measurement system. The means of back up shall be by
UPS.
c) pressure and temperature measurements (where applicable) and for differential
producers the differential pressure measurements.
d) the flow computer and its ticket printer, the latter if installed to meet legal
requirements.
e) In some cases legislation may require a turbine meter to be equipped with a
mechanical counter.
f) on-line measurements of fluid properties or samplers. Redundancy does not require
diverse physical property measurements.
Appendices I.1 and M illustrate an all encompassing degree of redundancy including
diverse measurement techniques (e.g., density and GC analyzers). This degree of
redundancy is not normally required. However, the unavailability of a single component of
the custody gas measurement system due to failure or maintenance shall result neither in
the interruption of ongoing measurements nor in the loss or invalidation of contractually
required data.
When high (> 99 %) availability is required, the metering system shall be arranged in such
a way that a single device failure does not result in a complete loss of measurement. This
means that:
ECCN EAR99 DEP 32.32.00.12-Gen.
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a) The power supply of the measuring station up to and including the field
instrumentation shall be redundant. However, failure of the power supply in
combination with a failure of the back-up supply need not be assumed in the design.
NOTE: The autonomy time (the specified time that the battery shall be capable of supplying rated
current to the load within the specified voltage limits) of the UPS shall fulfil project
requirements. UPS is required for bridging power outages of short duration and for the safe
shutdown of the metering station in the event of a total power shut down.

b) The pressure measurement, differential pressure and temperature measurements

(where applicable) shall be redundant.
c) In a multi-meter run design, at least the flow meter with the highest range shall be
redundant. For equal range flow meters the design shall be N+1 (i.e., 2 x 100 %,
3 x 50 %, etc.).
d) Redundant flow computers shall be provided.
e) A spare analyzer or an alternative method shall be available to determine physical
properties of the fluid.
f) The change out of failed equipment shall not interrupt measurements.
Although selection of components with a high inherent availability may reduce the level of
redundancy required, such selections do not negate the requirement for redundant devices,
adequate spares or repair expertise.
The Manufacturer shall with his proposal include a description of how the target availability
is to be met (e.g., by an agreed failure analysis methodology) including consideration of
periods of outage and flow reduction as a result of meter run validation, maintenance or
equipment failure.
Redundancy at meter run level, if required, should be a system of Pay and Check, each
capable of producing independently the contractually required data. Data from Pay and
Check systems shall be continuously accrued and recorded thus creating two independent
data sets of equal parity.
Deviation alarms shall be made available for all redundant measurements in the system.
The deviation tolerance should depend on the uncertainty for each measurement and shall
be statistically supported.
Orifice carriers should be considered for mitigating unavailability due to periodic inspection
of the orifice plate or its replacement in the event of its failure.
NOTE: Local isolation practices such as requirements for double block and bleed valves shall be considered
prior to implementing such designs.

3.6 RANGEABILITY
The design capacity of the metering system is determined by the maximum flow rate that
can be measured at the required uncertainty (excluding any spare meter runs provided for
reliability purposes).
The minimum design capacity is the minimum flow rate of the smallest single meter run at
the required uncertainty.
Minimum and maximum flow rate design shall consider the limitations of all components
such as the meter, flow conditioner, filter, etc. The system design shall incorporate
sufficient parallel meter runs to:
• permit the maximum and minimum system flow rates to be measured at the specified
uncertainty,
• achieve the specified availability including validation exercises when one of the
meter runs is removed for validation.
Where required by agreement or regulation, provision shall be made to stop the flow at
rates below a preset minimum value (e.g., the lowest flow calibration point of the flow meter
as specified at the metrological certificate or where uncertainty cannot be met).
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When determining the maximum flow rate required, peak as well as average flow rates
shall be considered.
NOTE: For example, if gas flow rates vary significantly (e.g., in response to power demand), the average daily
throughput of a meter station would not represent the peak hourly meter flow rate.

3.7 TRACEABILITY
The system shall be designed in a manner to permit traceability to the required national
metrological standards. At the design stage, this requires:
• selecting equipment types that are traceable, and,
• providing appropriate means (e.g., access, process taps, sample points) for the
required field verifications and calibrations.
The equipment used for determining fluid and process properties shall be traceable to
national and international standards through a system of analytical procedures, reference
materials, sampling and calibration procedures (3.8.2).

3.8 DEVICE VALIDATION CAPABILITY

3.8.1 Introduction
Device verification procedures and frequency are outside the scope of this DEP; however,
these items shall be considered in the design of the facility.
3.8.2 General
Device validation requirements shall be considered during design, procurement and
installation. For example, the requirement for factory calibrations shall be identified on the
instrument data sheets.
Device performance validations should be conducted in-situ without instruments having to
be removed. Hence, sufficient validation facilities for each instrument shall be provided
(e.g., validation ports/manifolds, dual thermowells, manual sample valves). For meters to
be validated in-situ, master meter connections are required (excludes differential
producers).
If in-situ validation is not possible or not required, the instrument concerned shall be
scheduled for regular factory validation/recalibration, which may require a spare, calibrated
instrument to be available.
Validations using a fluid different than the process fluid are only acceptable if this is
accounted for in agreed uncertainty calculations, agreements or regulations and if approved
in writing by the Principal.
NOTE: For example, Coriolis meters are often calibrated using water. Similarly, ultrasonic meters may be
calibrated using alternate gases provided the operating pressure and Reynolds number range is
matched during calibrations.

Calibration equipment shall have a valid calibration certificate traceable to a national

metrological standard. Calibration certificates shall identify the ‘as found’ errors, the
calibration uncertainty and expiry date. Wherever practical, calibration equipment shall
have an uncertainty no greater than one third of the uncertainty of the instruments to be
calibrated under the conditions at which the tests take place. In cases where this is not
practical (e.g., fully characterized differential pressure transmitter), the written approval of
the Principal shall be obtained.
Some microprocessor based devices have the capability to perform self diagnostics.
Provision shall be made in the design to incorporate such diagnostic functions into the field
devices and to provide suitable software to utilize such functions for performance
monitoring and troubleshooting.
For the purposes of validation and troubleshooting, suitable electronic connections shall be
provided for computational devices and field devices.
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3.8.3 Meter validation

As part of the preliminary design, the flow meter validation practice shall be selected.
Specifically, an assessment shall be performed to determine which of the following meter
validation options meet the application requirements:
a) off site calibrations (availability of suitable proving facilities in terms of geographic
proximity, uncertainty and capacity)
b) on site calibration using a master meter (either permanently installed in series or
periodically brought in-line).
Such assessments shall consider the total cost of ownership of the various meter validation
options, meter performance characteristics, fluid properties and the risk associated with
increased uncertainty or loss of use associated with master meter or off site calibrations.

3.9 OPERATING ENVELOPE

The measurement system shall be capable of meeting its uncertainty, rangeability and
availability targets for the design operating envelope as follows:
a) operating modes such as start-up, shutdown, off specification, continuous/batch
operation, unidirectional or bi-directional flow and credible future operating modes.
NOTE: Deviations from the required uncertainty are permitted for operating modes such as start-up and
shutdown provided the flow continues to be measured and the required uncertainty is achieved for the
overall batch.

b) fluid properties such as composition, density, viscosity, corrosiveness, erosiveness,

toxicity and presence of solids or contaminants, mixed phase (i.e., operating at or
below hydrocarbon or water dew point), special risks such as decomposition,
fouling, plugging, depositing, and chemical reaction,
c) process limitations such as pressure, temperature, Reynolds number and flow rate,
d) allowable pressure loss,
e) operating environment including the following aspects:
• weather related exposure (e.g., winterization, intense sunlight, tropical)
• mechanical integrity (e.g., vibration, hydraulic noise, pulsating flow, radiation
from hot process equipment, earthquake, wash-down area, vicinity to corrosive
atmosphere such as cooling water towers, chlorides, seawater, etc.)
f) plant organisation regarding maintenance, manned, unmanned, data collection and
retrieval, self-diagnostic, AMS, and documenting features, expertise, installed base
and training, stock keeping, spare parts, Manufacturer’s support, etc.
g) Human Factors Engineering (HFE) aspects such as accessibility for validation and
maintenance, safety)
h) Controlled access to third parties for data exchange.
If the measurement system operating envelope changes, the MOC process shall be used to
reengage all disciplines to ensure the design is fit for purpose.
The relevant sections of this document cover specific aspects for the selection of
instruments per function (temperature, flow, validation, sampling, etc.).
All instruments shall be installed as per DEP 32.31.00.32-Gen.

3.10 MATERIALS
All pressure retaining components such as piping, valves, strainers, and meter bodies shall
comply with the piping classes specified in DEP 32.32.00.95-Gen. and with requirements of
DEP 31.38.01.11-Gen., DEP 31.38.01.12-Gen., DEP 31.38.01.15-Gen. and
DEP 39.01.10.11-Gen.
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All instruments shall comply with the materials requirements as specified in

DEP 32.32.00.95-Gen.and as specified in DEP 32.31.00.32-Gen.

3.11 ELECTRICAL
All electrical devices shall be approved (e.g., ATEX, CSA, UL) and so marked for the area
classification and jurisdiction in which they are to be installed. See DEP 32.31.00.32-Gen.,
Section 2.5 for electrical certification requirements.
3.11.1 Measurement device outputs
In addition to the primary element signals (3.11.2) and secondary instrument signals
(3.11.3), all measurement devices shall output a fault condition (3.11.4).
Where available, device diagnostics shall be provided.
With the exception of communications downstream of the flow computer, wireless shall not
be utilized in custody transfer measurement systems.
Barriers to achieve intrinsically safe designs shall not be utilized for measurement device
analog outputs.
For custody transfer measurement devices, meter wiring design shall utilize a minimum
number of connections (e.g., junction boxes). Continuous conductors shall be utilized
between field devices and the skid junction box and between the skid junction box and the
computational device. Other wiring practices are as per DEP 32.31.00.32-Gen.
3.11.2 Primary element outputs
The primary output of linear meters shall be pulses where each pulse represents a discrete
volume or mass. Specifically, analog signals (e.g., 4-20 mA) or digital communications
TM
such as FOUNDATION FIELDBUS (FF) shall not be utilized as the primary output for
linear custody transfer meters.
3.11.3 Secondary device signals
Where practical and provided compatibility has been proven through interoperability testing
between transmitter and flow computer, secondary instruments such as static pressure,
differential pressure, temperature and QMIs should utilize a digital communications such as
FF. With the exception of gas chromatographs, Modbus shall not be used for secondary
device signals. Where digital communications are not practical, analogue outputs shall be
4-20 mA.
The square root function of differential pressure meters shall be applied in the computing
device.
Temperature measurements may utilize one of the following:
• a fully characterized temperature transmitter combined with an RTD, or,
• 4 wire RTDs interfaced directly to the computing device (i.e., avoid temperature
transmitters).
3.11.4 Diagnostics/fault signals
In addition to the required measurement output, where practical measurement devices shall
output common (i.e., grouped) warning and fault status signals to the BPCS or SCADA.
Detailed diagnostic capability/screens shall be provided by equipment specific software and
need not be programmed into the BPCS or SCADA.
The fault status may be transmitted utilizing a set of dry contacts, over/under range analog
signals or via a digital protocol such as Modbus or digital communications such as FF.
Fault status via analog 4-20 mA type output signals shall comply with NAMUR NE-43
recommended values for abnormal signal levels. In such designs the computational device
inputs shall also comply with NAMUR NE-43. The field device shall not drive the signal
through the alarm condition to reach the fault condition value.
ECCN EAR99 DEP 32.32.00.12-Gen.
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Contacts used for fault status shall be normally closed, open on fault detection and shall be
self resetting.
Measurement systems shall be designed to provide the capability to connect to field and
flow computation devices digitally (e.g., Modbus over Ethernet) for the purpose of
performance validation and troubleshooting utilizing fit for purpose software.
Where asset management systems are employed, the analogue output devices (i.e.,
transmitters) shall be HART® or FF compatible to enable enhanced diagnostic data to be
collected. The associated analogue input modules shall support HART® or FF without the
need for additional hardware.
Subject to (2.2) the action upon device fault detection shall be documented (e.g., decision
matrix in measurement manual or control narrative).

3.12 ENVIRONMENTAL PROTECTION

Measurement equipment shall be capable of operating and measuring in the environment
that they are installed, inclusive of atmospheric chemistry, local temperature ranges and
humidity, EMI/RFI and vibration.
Environmental protection shall be as per Section 2.11 of DEP 32.31.00.32-Gen.
Electromagnetic Interference / Radio Frequency Interference (EMI/RFI) compatibility shall
be as per Section 2.12 of DEP 32.31.00.32-Gen.

3.13 SKID, STRUCTURAL AND BASEPLATE

The configuration of the metering skid shall meet the requirements and comply with the
dimensional constraints of DEP 32.32.00.95-Gen. The Manufacturer shall propose a design
within these constraints that combines compactness with compliance with quoted standards
and codes, and ensures equipment maintainability.
On offshore platforms, the weight of equipment is of paramount importance and equipment
shall be designed to weigh as little as possible without degrading safety, environmental
performance or efficiency. The Manufacturer shall identify equipment mass, centre of
gravity in relation to plan, and elevation for all assembled skid units.
The System shall be designed and constructed to allow service and maintenance of
measurement equipment in a safe manner.
The metering skid shall be of all-welded steel construction with a rigid base. The base plate
shall be adequately supported. Lifting facilities shall be provided as part of the skid and
these shall permit the complete assembly to be lifted without causing permanent
deformation or damage to the skid or to any of the equipment mounted on the skid. The
Manufacturer shall complete structural stress analysis of the skid base and piping supports
inline with relevant standards prior to fabrication.
Structural integrity of the skid shall not be reliant on any equipment fixed to it.
Where specified, a drip-pan shall be provided over the entire skid base, inclined so that it
drains to a single point, which shall be designated as a hazardous drain. The drain shall be
terminated in a DN 50 (NPS 2) flange with a rating suitable for the application for
connection and continuation by the Principal.
Vents and drains shall be provided at all high and low points in the piping system, with the
low point drains manifolded to the base plate edge. Visual indication shall be provided at
each drain so that liquid discharge can be observed.
For painting specifications, refer to DEP 30.48.00.31-Gen. The painting schedule shall be
as specified in DEP 32.32.00.95-Gen. Colour schemes shall be as specified in
DEP 32.32.00.95-Gen. and may be governed by local regulations and customs.
The metering system Manufacturer shall provide foundation loading drawings/calculations
for the metering skid prior to fabrication.
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3.14 PIPING AND VALVING

3.14.1 General
Piping design shall comply with DEP 31.38.01.10-Gen., DEP 80.45.10.10-Gen. and
DEP 31.38.01.11-Gen.
Piping shall be designed to minimize pulsation, dead legs and trapped volumes of fluid for
all anticipated modes of operation, including start-up and shutdown.
All in-line measurement system devices such as valves, strainers, meters, meter run
upstream and downstream flow tubes and flow conditioners shall have flanged connections
to permit removal for inspection and maintenance.
Allowable pressure loss shall be determined considering the pressure drops through
associated control valve as well the meter, strainer, flow conditioner, check valves, etc.
This system approach to pressure loss limitations/calculations improves meter selection
and sizing.
System shutdowns or product diversion to avoid mis-measurement or product
contamination shall be agreed upon with the Principal, authorities and interested parties.
Spool pieces shall be provided to replace the meters during hydro-testing as per
DEP 62.10.08.11-Gen. Where required, the spools shall be manufactured to the same
piping standard as the skid piping and be provided complete with gaskets.
Wherever practical, meters shall be installed in horizontal lines. Meter shall not be installed
at the lowest piping point where liquids are likely to collect and are hard to remove. The
configuration shall be such that the primary device shall be in a self-draining position.
For unidirectional measurement applications, check valve(s) shall be provided to prevent
back flow through meters. In single meter run applications, check valves shall be located
downstream of the meter downstream straight run piping. For applications with a control
valve, the check valve is located downstream of the control valve. For multi-meter run
single product applications, a single check valve shall be provided downstream of the
delivery header.
Meter run inlet and outlet valves shall be fitted with open and closed position switches for
remote indication. The position switches should be factory set and tamper resistant.
Parallel and redundant metering runs shall be symmetrical with, and of similar size to, the
other meter runs. Special hydraulic consideration shall be given to achieving balanced
flow. Such metering skids shall have a common inlet header and a common outlet header
to ensure uniform flow conditions. For multi-meter run applications requiring in-situ meter
validation, a validation inlet and outlet header shall be provided; see (Appendix M).
The inlet and outlet piping of parallel metering devices with common inlet and outlet
headers shall have sufficient flexibility to cope with differences in thermal expansion when
one device is not in operation and to facilitate component removal. The Manufacturer shall
complete piping stress analysis on the metering skid piping to ensure adequate strength
during the various stream online configurations, varying process conditions and external
termination point loads. Calculations shall be made available to the Principal for review and
approval prior to start of fabrication.
Verifiable isolation utilizing double block and bleed (DB&B) valves shall be provided as
required to preclude the possibility of measurement error due to unmetered fluids (i.e.,
bypass around meters), undelivered fluids (i.e., diversion downstream of meters) or meter
validation errors (i.e., inflow or outflow between meter and check or master meter ). This
requires DB&B valves as follows:
• between parallel or redundant meter runs,
• on all permanently piped drain valves downstream of the meter including those
between the meter and master meter,
• any meter station bypasses required to meet contractual fluid availability (monitored
by permits, locks, electronically).
ECCN EAR99 DEP 32.32.00.12-Gen.
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Single body, full port type rotating plug valves are preferred for DB&B service.
The bleed port of DB&B valves shall allow visual or electronic means of seal verification.
Unless required for HSSE reasons, vent valve connections through which leakage is clearly
visible do not require DB&B valves.
Facilities shall be designed to minimize hard-piped pressure relief and vent connections
through which flow would cause measurement error. If hard piped relief, vent or DB&B
bleed connections are necessary, the outlet of potential bypasses shall be continuously
monitored.
If vents, drains, and relief valves that discharge to the downstream side of the flow meter
absolutely cannot be avoided, associated discharge lines shall include a visual or electronic
means of determining leakage.
3.14.2 Thermal relief
Thermal expansion relief valves are required in liquid-full systems if the system can be
blocked in and subjected to heat input from atmosphere or process. For the application of
thermal expansion relief valves, see DEP 80.45.10.11-Gen.
In no case shall a thermal or pressure relief valve be located between the meter and the
check or master meter or between the sampling system and meter.
3.14.3 Master meter
Check or master meter valving/manifolds shall be provided for applications requiring in-situ
validations.
Master meter valving/manifolds shall be:
• sized to allow meter validation over the full operating range expected for the meter.
• be located downstream of the flow meters.
Where in-situ meter validation is required, DB&B valves shall be provided as follows:
• as the meter run validation bypass (i.e., divert) valve to divert the flow through the
master meter for a single meter run application,
• as the meter run validation bypass (i.e., divert) valve to divert the flow to the meter
validation supply header for a multi meter run application, and,
• to isolate individual meter runs from the validation supply header when validating
other meters,
• to isolate individual meter runs the validation return header when validating other
meters.
3.14.4 Flow control valves
Flow control valves shall be utilized where required to control the flow rate through a meter
to ensure the measured flow rate is within the calibrated portion of the meter range.
Flow control valves are normally not required for single meter run applications. For multi-
run flow measurement systems, one flow control valve shall be provided per meter run to
balance flow rates during operation and when performing meter validations (where
applicable).
Flow control valves associated with meter runs shall be installed outside the downstream
straight length required by a meter (i.e., typically 5D downstream).
Flow control valves shall be selected, sized and installed as per the requirements of
DEP 32.36.01.17-Gen.
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3.15 FLOW CONDITIONING

Meter types such as ultrasonic, turbine, orifice and Venturi which are sensitive to flow
profile disturbances such as those associated with bends, pipe reducers and partially open
control valves shall be provided with sufficient upstream/downstream straight run piping
(preferred where practical) or an upstream perforated flow conditioner plate (acceptable).
NOTE: Research has shown that asymmetric flow profiles may persist for more than 50 pipe diameters from
the initiation point while swirling profiles may persist for more than 200 pipe diameters from the point of
initiation.

Straight run lengths shall be as per the most stringent of the local authority or as per
Industry standard. For CTM applications for which the straight length requirements are not
defined by local authority or industry standard, the Manufacturer’s straight length
recommendations are acceptable provided the Manufacturer supplies supporting test data
to substantiate the recommendations.
Meter applications without the provision for in-situ verifications (e.g., master meters) shall
be provided with a perforated plate type flow conditioner installed according to the
Manufacturer’s recommendations. Exceptions to this requirement are orifice meters and
meters which are not sensitive to upstream piping disturbances such as Coriolis meters and
where the operating and calibration upstream piping configurations meet the minimum
straight requirements of the applicable standard.
Tube bundle style flow conditioners including those referenced in ISO 9951 or AGA 7 shall
not be utilized.
For meters sensitive to flow profile disturbances, the upstream and downstream meter runs
shall be free of protruding gaskets, weld beads, etc.
Eccentric pipe reducers shall not be utilized upstream or downstream of meters sensitive to
flow profile disturbances.
The straight length/flow conditioner requirements stated above do not apply to meters
insensitive to upstream flow disturbances (e.g., Coriolis).
For bidirectional flow applications, flow conditioning should meet these requirements
regardless of direction of flow.

3.16 STRAINERS
Strainers shall only be provided for turbine meters. Application of strainers for other types
of meters requires the approval of the Principal.
When strainers are required, they shall be selected and installed as per the strainer and
meter Manufacturer’s recommendations and as per the requirements of the applicable
standard.
The strainers shall have the following characteristics:
a) for meter protection applications, located upstream of the meter,
b) for sampler only applications, located upstream of the sampling system
c) pipeline vertical basket type with top entry
d) In the clean condition, the strainer should have a pressure drop of not more than
20 kPa (2.9 psi), and in a dirty condition the strainer internals shall be capable of
withstanding a pressure drop of at least 35 kPa (5 psi). This requirement is more
stringent than that specified by most Suppliers, but is considered necessary to
prevent the collapse of a dirty strainer.
e) Strainers should have ports to accommodate the installation of a differential pressure
indicator or transmitter across the strainer body.
f) A differential pressure transmitter with alarm should be provided where frequent
fouling of the strainer is expected.
ECCN EAR99 DEP 32.32.00.12-Gen.
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g) The strainer enclosure shall be of the quick-opening type with valved vent and drain
connections.
h) The strainer shall have replaceable stainless steel inserts.
i) The strainer screen shall be supported by a strainer basket having much larger
openings than those of the screen.
j) The mesh size for the screen shall be as recommended by the meter Manufacturer.

The following shall be taken into account:

a) the dimensions and weight of the basket and the strainer liner;
b) the means of removing the strainer (hoisting arrangements, etc.);
c) the suitability of the letdown area;
d) if the strainer and/or basket will need to be removed manually, the level of the
strainer unit relative to the position of the operator is critical;
e) depressuring, decontamination and handling considerations, and the layout of the
immediate area (noting that strainer removal can be a messy activity);
f) isolation (e.g., double block and bleed facilities, blinding), depressuring, and lock-out
tagging. The need for protective functions may have to be addressed in some
circumstances.

3.17 FLUID COMPOSITION DETERMINATION

Uncorrected variations in process pressure and temperature and fluid composition (e.g.,
water content, density, energy content) increase the system measurement uncertainty and
may create a systematic error (bias). As part of the preliminary design, an assessment of
the effect of fluid composition variations on uncertainty and financial risk (i.e., quantity and
quality) shall be performed to determine the appropriate fluid composition update scheme.
The risk identified and suitability of each option shall determine which of the following
options is suitable for the application:
• continuous on-line analysis (e.g., QMI, GC, densitometer),
• flow proportional auto sampler,
• periodic spot sampling (i.e., grab).
Analysis frequency shall meet the requirements of the contractually agreed sampling and
analysis scheme as detailed in DEP 32.32.00.95-Gen. In the absence of any regulatory or
contractual requirements, the following groups can be distinguished for the determination of
fluid properties.

Group 1 gas with a variable composition, subdivided as follows:

6 3
1a: 'large' capacity (> 10 m /d at specified conditions, for at least
3 successive years),
1b: 'medium' capacity (capacities other than as described for Groups 1a
and 1c),
1c: 'small' capacity:
≤ 50,000 m /d; or
3

between 50,000 m /d and ≤10 m /d at specified conditions for less

3 6 3

than 3 successive years).

Group 2: gas with a constant composition.

For the purposes of selecting an analysis scheme, the fluid is deemed to have a constant
composition (Group 2) if the variability in its composition contributes less than 0.5 %
ECCN EAR99 DEP 32.32.00.12-Gen.
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increased uncertainty to the parameter of interest (e.g., mass, energy, volume). In all other
cases the gas has, by definition, a variable composition (Group 1).
Composition variability shall consider the source of the gas (e.g., process, reservoir),
similar applications and the results of representative spot sampling.
For fluid properties for custody transfer gas measurements, the following methodology
should be made available:

Group 1a: Determination by on-line measurement (6.4)

Inferred from on-line compositional data (6.4), (7.2.4)
Group 1b: Inferred from compositional data obtained from flow
proportional sampling (10), (7.2.4)
Inferred from on-line compositional data (6.4), (7.2.4)
Groups 1c and 2: Inferred from compositional data obtained from spot sampling
(10), (7.2.4)

In addition to the above, the selection of analysis scheme shall consider the implementation
cost and technical feasibility of the required quality measurements. For example, moisture
content, hydrogen sulphide and fluid composition can generally be reliably determined by
on-line analyser systems provided that contaminants are absent from the fluid matrix.
Properties required to meet contractual or regulatory requirements but which are less
suitable for determination by on-line analysers should be determined via sampling and
analysis. The method selected should meet local needs and encompass all requirements,
e.g., logistics and training of local staff.
For QMI requirements, see (6.4).
For sampler requirements, see (10).
For inferred property determinations from compositional data, see (7.2.4).

3.18 COMPUTATIONAL DEVICES

Fit for purpose computational devices shall be used for custody transfer measurement
systems. Custody transfer measurement system computations shall not be made in PLCs,
the BPCS or SCADA.
Configurable devices shall be utilized. Programmable devices are not acceptable.
Subject to (2.2), mechanical counters are not required.
Chart recorders shall not be installed for new installations or upgrades of existing
installations.
Flow computers may service more than one meter run provided the redundancy
requirements are met.
Computations shall be made is accordance with the applicable Industry standards.
See (7) for detailed requirements of computational devices.

4. SPECIFIC APPLICATION REQUIREMENTS

4.1 MASS MEASUREMENT

For mass measurement applications, unless a Coriolis meter is deemed unacceptable for a
particular application (e.g., limitations or incompatibilities associated with fluid properties,
pressure, temperature, maximum pressure loss, flow rate) or precluded or preselected by
regulation or agreement, direct mass measurement using Coriolis meters shall be utilized
(5.3). Where direct mass measurement using a Coriolis meter is not practical or cost
effective, dynamic mass measurements may be made indirectly (inferred) using a
volumetric meter and either a measured or computed density.
ECCN EAR99 DEP 32.32.00.12-Gen.
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For indirect mass measurement, a densitometer should be utilized (6.4.2). Where use of a
densitometer is not practical or cost effective, a computed density (7.2.4) may be utilized
using fluid composition. In such cases, the uncertainty of the fluid composition
measurement (6.4), the density computation algorithm (7.2.4) and volumetric meter (5)
shall be considered to ensure the required uncertainty of the overall mass measurement is
achievable.
Where in-situ validations are required for mass measurements using Coriolis meters, the
means of meter validation shall be considered (9) as part of the meter type selection
process. For example, a Coriolis meter outputting mass, which requires in-situ meter
verification, requires that the meter skid design is capable of either:
• master meter proving using another Coriolis meter, or,
• master meter proving using a volumetric meter and a densitometer, or,
• master meter proving using a volumetric meter and a compositional analyzer.

4.2 VOLUMETRIC MEASUREMENT

Unless the meter type is deemed unacceptable for a particular application (e.g., limitations
or incompatibilities associated with fluid properties, pressure, temperature, maximum
pressure loss, flow rate) or precluded or preselected by regulation or agreement, meters
shall be selected for gas custody transfer metering in the following order of preference:
• for line sizes < 100 mm (4 NPS), Coriolis meters outputting mass (5.3) corrected to
base volumetric conditions using a measured fluid composition to compute base
density.
NOTE: For applications where the gas composition is relatively constant, a fixed value for base density may
be utilized provided the uncertainty requirements can be met.

• for line sizes > 100 mm (4 NPS), multi-path ultrasonic (5.2) or Coriolis meters (5.3),
• orifice (5.4)
• turbine (5.5)
Coriolis meters shall not be used for direct measurement of gas or vapours on a volumetric
at flowing condition basis.
NOTE: The uncertainty of the density measurement of a Coriolis meter relative to the flowing density is such
that it precludes using the measured flowing density to convert the measured mass to a volumetric
flow rate for gas applications.

Vortex meters are not suitable for custody transfer measurements.

4.3 ENERGY MEASUREMENT

Energy measurement requires the determination of:
• the mass or volume of a fluid, and,
• the energy content of the fluid based on fluid composition.
Dynamic mass measurements shall be made as per (4.1).
Volumetric measurements shall be made as (4.2).
Energy shall be computed as per:
• ISO 6976, or,
• AGA Report 5
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5. METER REQUIREMENTS

5.1 GENERAL REQUIREMENTS

Meters shall be selected and sized to meet the requirements detailed on their instrument
data sheets.
The Manufacturer shall review meter type selection and sizing to confirm that the meter
type and size is suitable for the application as detailed on the meters Instrument datasheet.
Particular attention shall be given to the uncertainty requirements and approvals.
Manufacturer shall provide documentation such as flow loop test reports to support
specifications (e.g., performance, reduced straight run lengths) which are less stringent that
the requirements herein or are uncertain.
At a minimum, subject to (2.2) and the individual meter requirements in (5), multipath
ultrasonic, Coriolis and turbine meters shall comply with OIML R137- Parts 1 and 2
accuracy class 0.5 or better at normal operating conditions over the specified turndown
ratio (excluding steam meters).
NOTE: In OIML R137 – Parts 1&2 the accuracy is defined as the Maximum Permissible Error (MPE). The
MPE is not equal to 2 sigma.

Where applicable (2.2), the requirements of OIML R137 – Parts 1 and 2 shall apply.
With the exception of orifice meters, all gas meters used for custody transfer shall be flow
calibrated as per (9).
All meters shall be installed so that they are well supported (i.e., adjacent piping shall not
exert any stress on the meter body).
Adequate filtering shall be provided where necessary.

5.2 MULTI-PATH ULTRASONIC METERS

Multi-path ultrasonic meters used for gas/vapour custody transfer metering shall be
selected, sized, installed, calibrated and operated to meet the requirements of:
• AGA 9 or,
• ISO 17089-1
The requirements of AGA 9 and ISO 17089-1 shall also apply to non natural gas
applications (e.g., hydrogen).
Multipath ultrasonic meters are acceptable for uni-directional and bi-directional volumetric
or inferred mass flow measurement applications.
Multipath ultrasonic meter for custody transfer applications shall utilize a minimum of four
paths.
Multipath ultrasonic meters shall have an uncertainty of ± 0.5% of reading or better
including that of the calibration facility at normal operating conditions over the specified
turndown ratio.
Multipath ultrasonic meters utilizing a single measurement path plane configuration (i.e.,
incapable of correcting for swirl) shall not be applied for custody transfer measurements
without a flow conditioning plate.
Multipath ultrasonic meters shall meet applicable straight run requirements (3.15).
Clamp on ultrasonic meters shall not be used for custody transfer measurements.
Sample points and densitometer pockets (where required) should be located between
2 pipe diameters and 5 pipe diameters downstream of the meter downstream straight
length requirement.
The meter shall not be installed in the immediate vicinity of devices that may affect the
ultrasonic signals; e.g., pressure reduction valves.
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Failure of one of the acoustic paths of an ultrasonic flow transmitter shall not invalidate its
measurement.

5.3 CORIOLIS METERS

Coriolis meters used for gas custody transfer metering shall be selected, sized, installed,
calibrated and operated to meet the requirements of:
• AGA 11 or,
• ISO 10790
Coriolis meters are acceptable for uni-directional and bi-directional mass flow measurement
applications. The density signal from a Coriolis meter shall not be used for gas applications
3
due to the significant density measurement uncertainty, typically 0.5 kg/m absolute, in
relation to the actual range of densities that apply to gas measurements. If required, the
volumetric flow under specified conditions shall be calculated from the prime mass flow
signal and either of the following options:
• On-line measurement of density (6.4.2)
• density inferred from composition (7.2.4)
The density signal from the Coriolis meter may be used as an indicative measurement, e.g.,
for the detection of entrained liquid, which may show up as a transient.
Coriolis meters shall have an uncertainty of ± 0.35 % of reading or better at normal
operating conditions over the specified turndown ratio. The design shall take into account
the effects of varying operating pressure on the calibration of the meter sensor. The
Manufacturer shall advise the level of dynamic pressure compensation that may be
required depending on the variability of the operating pressure and the targeted uncertainty
of the meter. Where required, pressure compensation shall be provided for variance
between calibration and operating pressures. The additional uncertainty associated with
the variance between the calibration temperature and the operating temperature shall be
considered in uncertainty assessments.
Meter sizing shall take into account the maximum flow rate limitation associated with the
low in relative terms of flowing density in gas applications. Manufacturer’s sizing programs
and/or documentation shall be utilized to size Coriolis meters for gas applications.
Coriolis meters are generally immune to swirling fluid or non-uniform velocity profiles.
However, the Manufacturer shall be consulted regarding upstream and downstream piping
requirements and the use of flow conditioners particularly for straight tube Coriolis meters.
In view of their inherent geometry, Coriolis meters are likely to cause a noticeable pressure
drop, which should be taken into account when designing the measurement system. This
limitation may be partially offset by slightly over sizing a meter provided uncertainty
requirements are still met.
The meter shall be checked for noise conditions in accordance with the Manufacturer’s
recommendation. Harmonics of the exciting frequency and other frequencies that have a
simple relation to the exciting frequency of the vibrating tubes will interfere with the meter
operation. These harmonics may also be flow induced; e.g., due to pulsation. High gas
velocities, valves, choked flows, shock waves, critical nozzles, liquid and solid particles
present in the fluid, etc., may generate noise.
If a Coriolis master meter is used for validation (9), care should be taken to avoid cross talk,
which could be achieved by separating the sensors over a distance of three times the lay-
length of the meter (to achieve sufficient signal attenuation). Cross talk can also be avoided
when applying meters that operate at different vibrating frequencies.
The sensor shall be mounted above the line in horizontal meter run and in the flag position
with flow down for vertical runs.
The flow sensor will be subjected to axial, bending and torsional forces during operation.
Changes in these forces, resulting from variations in process temperature and/or pressure,
ECCN EAR99 DEP 32.32.00.12-Gen.
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can affect the performance of the Coriolis meter. Care should be taken to ensure that no
forces are exerted on the meter from clamping arrangements.
Measures should also be taken to prevent excessive stresses from being exerted on the
Coriolis meter by connecting pipes. Under no circumstances should the Coriolis meter be
used to align the pipe work. Alignment of the instrument shall be in accordance with the
Manufacturer’s specification, i.e., typically within 1 % of the internal pipe diameter.
Common piping practice for the supporting of adjacent piping should be sufficient to
suspend the meter and no additional supports are generally required. Arrangements shall
be in accordance with the Manufacturer's recommendations.

5.4 ORIFICE METERS

When orifice meters are used for gas/vapour custody transfer, meters shall be selected,
sized, installed, calibrated and operated to meet the requirements of:
a) ISO 5167–1 and ISO 5167-2, or,
b) API MPMS 14.3.1 (AGA 3 Part 1) and API MPMS 14.3.2 (AGA 3 Part 2).
For natural gas applications, use of the above standards or API MPMS 14.3.3
(AGA 3 Part 3) is acceptable.
In addition to the requirements in these standards, the following shall apply:
• Square edge orifice plates with flange tappings shall be utilized.
• The beta ratio (β = d/D) shall be between 0.2 and 0.6.
• Flow conditioning shall be as per either AGA 3 Part 2 or ISO 5167-2 with the
exceptions that the straight length requirements used in Column B of Table 3 in
ISO 5267-2 shall not be utilized and tube bundle type flow conditioners shall not be
applied.
The meter shall be initially sized as follows:
• utilizing a beta ratio of 0.5,
• on a basis of a maximum differential pressure of the lesser of the value stated in
Table 2-3 of AGA 3 or 100 kPa (400 in water column) at the maximum flow rate.
• on the basis of a minimum calibrated range for a differential pressure transmitter of
6 kPa (24 in water column).
The maximum differential pressure reading shall not exceed 80 % of the differential
pressure transmitter upper range span for analog transmitters and 80 % of the upper range
limit for digital outputs.
The maximum turndown for a given meter run shall be determined considering the overall
uncertainty of the meter considering Reynolds number constraints specified in the above
standards, the differential pressure constraints detailed above and the required uncertainty.
Senior and Junior orifice fittings are acceptable provided the facility isolation procedures
permit their use.
The use of stacked differential pressure transmitters should be avoided wherever practical
and shall never exceed more than three.
Multi-variable smart transmitters shall not be used unless they are used for single-variable
measurement and are acceptable to local authorities.
The static pressure may be measured at either the upstream (preferred) or downstream
differential pressure tap consistent with site practice or (2.2).
The operating temperature of the gas shall be measured as per the standards referenced
above and (6.2).
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5.5 TURBINE METERS

In view of their vulnerability to wear and tear and considering the availability of reliable
options, turbine flow meters should be avoided.
Turbine meters should not be used where frequently interrupted and/or strongly fluctuating
flow or pressure pulsations are present.
When turbine meters are used for gas custody transfer metering, these shall be selected,
sized, installed, calibrated and operated to meet the requirements of:
• AGA 7 or,
• ISO 9951
Exceptions: Tube bundle type flow straighteners shall not be utilized.
Turbine meters are acceptable for uni-directional volumetric or inferred mass flow
measurement applications.
The risk of incurring damage from extreme operating conditions shall be minimised by
carefully selecting the location of the measurement station and by providing adequate,
additional protection if required. Typical risks are: dirt or liquid pollution during start-up,
shock waves when opening valves.
Upstream filters shall be installed. The filter elements shall be of such a type that 98 % of
particles measuring 1 µm or larger will be intercepted, or the turbine Manufacturer’s
requirements shall be followed if more stringent. See also (3.16)
The pressure tapping marked 'Pm' (or old mark: 'Pr') on the meter body shall be used as
the pressure sensing point for the operating pressure measurement.
The operating temperature of the gas shall be measured as per the standards referenced
above and (6.2).
Turbine meters shall be provided with vane failure detection.
Turbine meters shall have a linearity of ± 1 % of reading or better at normal operating
conditions over the specified turndown ratio.
The meters shall be protected against damage due to over-speeding or hydraulic shock,
(e.g., caused by the quick opening and closing of valves).
Turbine meters installations shall meet the straight run requirements (3.15).
The meter calibration factor (K-factor) for each turbine meter shall be determined initially by
tests carried out by the Manufacturer and stamped on the meter body or a permanently
affixed name plate.
Turbine meters with output adjustment based on two rotors shall not be utilized.

5.6 VENTURI METERS

When Venturi meters are used for gas/vapour custody transfer, meters shall be selected,
sized, installed, calibrated and operated to meet the requirements of ISO 5167–1 and
ISO 5167-4.
NOTE: Venturi meters by design have a single beta ratio which compared to orifice meters limits their
turndown.

Venturi meter tubes shall be individually calibrated for custody transfer applications.
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6. SECONDARY INSTRUMENTS

6.1 INTRODUCTION
Temperature, pressure and differential pressure transmitters shall be selected and installed
as per the requirements of DEP 32.31.00.32-Gen.

6.2 TEMPERATURE
Temperature measurement shall be performed using RTDs mounted in flanged
thermowells (refer to Standard Drawing S 38.113). Meter skin or meter body temperature
measurements may only be used to correct for temperature effects on the meter body but
not to compute physical properties or correct volumes.
The temperature measurement shall accurately present the gas temperature in the line.
The effects of heat transfer from the piping or thermowell attachment to ambient shall be
limited and the temperature misreading for this reason should be limited to 0.5 °C (0.9 °F)
under steady state conditions. Refer to (Appendix H) for construction details.
A pair of thermowells, one for the measurement RTD and one for validation purposes shall
be provided outside the straight length as per the applicable standards (i.e., typically from
5D to 10D from the meter outlet flange).
If redundancy is required (3.5) a dual RTD sensor may be installed in the measurement
thermowell assembly thus avoiding the need for an additional thermowell.
Test thermowells shall have a 10 mm to 13 mm (3/8 in to 1/2 in) internal bore.
The two thermowells shall be installed on different radial axes to minimise vibration fatigue
of the downstream well by vortex shedding from its upstream partner.
Insertion depth shall be middle third of pipe or 75 mm (3 in) maximum into pipe subject to
the vibration failure avoidance constraints and length requirements detailed in
DEP 32.31.00.32-Gen. For pipe sizes 100 mm (4 in) and smaller, the pipe size shall be
increased to 150 mm (6 in) to avoid flow restriction. Eccentric reducers/expanders shall not
be used for this purpose. The thermowells shall be mounted to allow filling with a heat
conductive fluid. The test thermowell shall be provided with a threaded cap and chain.
The RTD shall be a Pt 100 RTD, 100 Ω at 0 °C, alpha coefficient 0.00385 Ω/Ω/°C as
defined in IEC 60751. Tolerance class A shall be applied.
The temperature element shall be spring loaded, installed and connected so that it can be
readily disconnected and extracted for replacement.
The temperature transmitter/direct wired RTD shall have sufficient coiled cable to facilitate
removal for verifications.

6.3 PRESSURE
For volumetric meters, pressure transmitters shall be located as per the applicable
standard.
Gauge pressure transmitters are preferred to absolute pressure transmitters because of
their ease of validation. Absolute pressure transmitters should be considered for low
pressure applications (less than 700 kPag (100 psig)).
Conversion from gauge to absolute pressure may be performed by adding the nominal
barometric pressure agreed as per (2.2) to the gauge pressure reading or by adding a
measured barometric pressure value.
To facilitate calibration, a dedicated impulse line connection to the transmitter manifold
block shall be available to allow calibration of the transmitter without the transmitter being
removed from the field.
Local pressure gauges shall be applied only by exception and shall be selected and
installed according to DEP 32.31.00.32-Gen. Indicating pressure transmitters should be
used rather than permanently mounted pressure gauges.
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6.4 QUALITY MEASUREMENT INSTRUMENTS

6.4.1 General
All QMIs shall be selected and installed to meet the requirements of DEP 32.31.50.13-Gen.
and DEP 32.31.50.10-Gen.
QMIs shall be provided with warning and fault outputs to the computational device.
Validation standards shall be traceable (3.7).
Fluid properties shall be determined either in accordance with or in a manner traceable to
the analytical methods in (Appendix E).
Inferred fluid properties (i.e., those computed from compositional analysis) shall be
computed as per (7.2.4).
6.4.2 Density
Density measurements used as part of gas custody transfer measurement systems are
used for computing mass.
Where practical, for custody transfer purposes continuous density should be measured
based on vibrating mass according to ISO 15970 and the Manufacturer’s
recommendations. See (Appendix G).
NOTES: 1. Vibration type densitometers are accurate and reliable instruments though extremely sensitive to
fouling conditions. The measurement uncertainty of on-line densitometer applications is typically
rated as better than 0.15 % while that of inferred density from composition in accordance with the
detailed methods of AGA 8 and with ISO 12213-2 is typically 0.1 % to 0.6 % depending on
process conditions, gas composition and the quality of input data.
2. The density signal from a Coriolis meter shall not be used for gas custody transfer density
measurements

Where fouling of the densitometer or liquid contamination is inevitable, density should be

inferred from gas composition measured by a GC. Gas composition, operating temperature
and pressure shall be used to assess the probability for condensation.
The measured value shall represent the density at the upstream face of the orifice plate or
in the throat of a turbine meter or ultrasonic meter (reference point Pm), which should be
achieved by maintaining pressure and temperature inside the densitometer as closely as
practicable to these locations. If this is not possible the appropriate corrections shall be
made to the measured value.
NOTE: Some flow computers provide the algorithms for correcting density measured at downstream pressure.

The temperature of the densitometer shall be kept within 0.5 °C (0.9 °F) from the process
temperature, which represents an additional density error of approximately 0.15 %. With a
pocket type of densitometer, the line pocket and protruding instrument shall be placed
inside a thermally well-insulated box that surrounds the whole pipe section over a length of
approximately 1 m (40 in) and over which length the insulation shall be stripped. Sample
take-off and flow controls of the densitometer shall be located inside the same box.
Provision shall be made for obtaining a manual sample for device validation.
6.4.3 Gas composition
Compositional analysis may be used to infer via computation parameters such as density,
heating value and compressibility (7.2).
Where required, the gas composition shall be determined according to the following:
• GPA 2261, or ,
• ISO 6974 (applicable part as per (2.2)).
• The gas chromatographs shall be calibrated using a primary gas standard
(i.e., prepared by weight), in accordance with ISO 14111 and ISO 6142.
Performance evaluation of the GC analyzer shall be as per ISO 10723.
ECCN EAR99 DEP 32.32.00.12-Gen.
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7. COMPUTATIONAL DEVICES

7.1 GENERAL REQUIREMENTS

The flow computer(s) and the associated counter(s) and /or ticket printer(s) shall comply
with local legal requirements (e.g., Weights and Measures) and/or the requirements of the
contract parties.
Flow computers shall have the capability to perform the required computations as detailed
in (7.2) without the need for programming (i.e., application specific configuration only).
Integration of flow computers into the process control domain and the Principal’s
information networks including provision of third party access shall meet the requirements
of DEP 32.01.23.17-Gen.
Flow computers associated with custody transfer measurements shall have no functions
other than those associated with the flow measurement or sampling.
Flow computations shall be performed in flow computers or other fit for purpose devices.
One or more flow computers may be required to perform the required tasks (e.g., a
hierarchical system of more than one flow computer supervised by a supervisory system).
See (Appendix I) and (Appendix J) for examples. The locations where the different
computational tasks are performed shall be clearly defined and agreed by the contract
parties.
Signal transmission between the meter and secondary devices and the flow computer shall
be as per (3.12). The measurement system shall have a robust data acquisition /
transmission architecture for data transfer to business critical systems/applications.
See (Appendix L) for detailed flow computer requirements.
The system response to changes of the metering system's input signals shall not be greater
than 1 s. Parameters having longer response time, such as density and temperature, shall
not exceed a response time of 5 s.

7.2 COMPUTATIONS
7.2.1 Introduction
At a minimum the computations shall meet the requirements of the applicable standards
associated with the different meter types (5) and API MPMS 21.1 utilizing agreed upon flow
rate and physical property algorithms.
7.2.2 Flow rate computations
Mass and volumetric flow rates shall be computed as per the standards detailed in the
following table.

Applicable Flow Rate Computational Standards

(Note 1)
Meter Type Standard
Ultrasonic ISO 17089-1, AGA 9
Coriolis ISO 10790 AMD 1, AGA 11
Turbine ISO 9951, AGA 7
Venturi ISO 5167-1, ISO-5167-4
Orifice ISO-5167-1, ISO-5167-2, API MPMS 14.3.1, Parts 1 and 2 or 3
NOTE: 1) The requirements of API MPMS 21-1 apply to all meter types.

Where it is not practical to compute values for viscosity and isentropic coefficient in real
time, subject to (2.2) and uncertainty requirements, fixed values may be used for the these
parameters based on the average operating conditions.
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7.2.3 Physical properties

Measured fluid properties shall be traceable to national and international standards through
a system of analytical procedures, reference materials and calibration procedures.
The recommended algorithms for computing physical properties detailed below are not
intended to supersede the requirements of applicable agreements, local codes and
regulations and Industry standards.
Inferred properties such as density, compressibility, heating value and isentropic
co-efficient shall be computed from gas compositions utilizing the detailed composition
method wherever practical. Computations using abbreviated methods such as
ISO 12213-3, SGERG or NX-19 require the approval of the Principal.
Unless precluded by contract or regulation (2), computations shall utilize density rather than
specific gravity, relative density or Wobbe Index.
Inferred properties for common applications shall be computed as per the following table.
Computations for other applications require the approval of the principal to determine which
physical property algorithms are acceptable (e.g., Peng Robinson, Redlich-Kwong).

Composition Based Inferred Property Computation Standards

Property Computation Standard
Energy (Heating Value) ISO 6976, AGA 5
Density (Natural Gas) ISO 12213-2, AGA 8
Compressibility (Natural Gas) ISO 12213-2, AGA 8
Molar Mass ISO 6976, AGA 5
Relative Density (Natural Gas) ISO 6976, AGA 5
Wobbe Index (Natural Gas) ISO 6976, AGA 5
Isentropic Co-efficient (Natural Gas) KSLA report AMER 84.039, AGA 10
Velocity of Sound AGA 10
Viscosity (Steam) ASME Steam Tables, IAPWS-95
Molar Mass ISO 6976, AGA 5
Steam Density ASME Steam Tables, IAPWS-95
Water Dew Point ISO 18453

8. SECURITY AND SEALING

The design shall meet the process control domain security requirements as detailed in
DEP 32.01.20.12-Gen.
To reduce the risk of tampering, appropriate sealing and security shall be applied to
equipment for which (un)intentional adjustment can affect quantity or quality
determinations. The sealing/security provisions shall utilize one or more of the following:
• mechanical seals (e.g., locks, wire seals),
• passwords,
• restricted access to Company’s and/or Owner’s properties (Refer to local security
practices).
• electronic audit trails for flow computers and supervisory systems.
ECCN EAR99 DEP 32.32.00.12-Gen.
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The following equipment list identifies the minimum equipment that shall have sealing
provisions. If regulatory requirements require additional devices to be sealed, the additional
devices shall also have sealing provisions.
a) Meter covers,
b) Preamplifier housings (e.g., turbine meters),
c) Meter counter and mounting bolts,
d) Sample probe and actuator mounting connection,
e) Sample container valves and openings,
f) Measurement system field panels,
g) Electronic computational devices (i.e., flow computers),
h) Temperature and pressure probes and transmitters including write protected dip
switches for smart transmitters,
i) Any valves capable of diverting fluids around the meter,
j) Junction boxes,
k) Any valves capable of diverting fluids after the meter prior to its intended destination
l) Any valves isolating a third party from the metering skid.

9. METER VALIDATION

9.1 GENERAL
With the exception of orifice meter tubes, all meters including Venturi meters shall be
calibrated prior to shipment to site at a facility traceable to the appropriate national standard
(2.2) as per the requirements of the applicable standards in (5).
Meter system designs shall provide for subsequent verifications using a master meter,
check meter or removal to an offsite facility for calibration. Check meters are master meters
which are typically left in line. Master meters may be permanently in-line or periodically
brought in-line.
For meters subject to upstream flow disturbance effects, the design shall provide
appropriate straight lengths for check and pay meters. For meters removed for offsite
calibrations, the design and installation shall permit shipment of the upstream spool pieces
without disassembly. For bidirectional meters, shipment of upstream and downstream
spool pieces is required.

9.2 CHECK METERS

Check meters shall be of a comparable uncertainty and reliability and shall be dedicated to
a single pay meter.

9.3 MASTER METERS

Master meters shall be dedicated to verifying the performance of the target meter(s) only
(i.e., shall not be included in redundancy assessments). Hence, the master meter shall not
be permanently lined up as a “duty” meter. Master meter proving designs shall respect the
straight run requirements of the master meter and the meter under test.
The master meter shall have an uncertainty at least equal to the meter under test and, in
order to avoid common mode errors, should preferably be of a different operating principle
than that employed by the meter under test. The permissible deviation between master and
target measurement system shall not exceed the overall uncertainty of both measurement
systems, which value shall be statistically substantiated.
With the approval of the Principal, the master meter may be applied in a “Z” configuration
(Appendix F).
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10 SAMPLING

10.1 GENERAL
Manual natural gas sampling systems shall be selected, sized, installed, verified and
operated to meet the requirements of:
• API MPMS 14.1, or,
• ISO 10715.
The requirements of these standards shall apply to fluids other than natural gas (exception
steam). Steam sampling design shall meet the requirements of ASTM D 1066.
Automated sampling systems shall be selected, sized, calibrated and operated to meet the
requirements of:
• ISO 10715.
In addition to the above standards sample systems shall meet the requirements of
DEP 32.31.50.10-Gen. in terms of sample location, sample probe requirements, phase
control and sample transport and sample disposal where required.
Sample systems shall not bypass the meter.
The sample take-off probe should be located with due consideration to meter upstream and
downstream straight length piping requirements as if it was a thermowell.
All on-line QMIs shall be provided with manual sampling stations for verifications.

11. FACTORY AND FIELD INSPECTION AND TESTING

11.1 GENERAL
All measurement systems installations shall be thoroughly checked and functionally tested
prior to shipment of the packaged unit. Examinations and/or tests may be reviewed
and/or witnessed by the Principal or their authorized agent at the Manufacturer's or the
Supplier’s facility as stated in the purchase order. The appropriate authority may wish to
approve the equipment design and witness calibration tests.
The Manufacturer/Supplier shall contact the Principal at the agreed schedule, i.e., six
weeks before the package delivery date, to schedule a factory acceptance test (FAT) that
will be witnessed by the Principal. The Manufacturer/Supplier shall submit a test procedure
to the Principal for approval six weeks prior to the FAT.
For meters which require calibration at the Manufacturer’s facility or an approved
independent calibration facility, the Manufacturer/Supplier shall contact the Principal at the
agreed schedule, i.e., six weeks before the meter calibration date, to provide the
opportunity for witnessing of the meter calibration by the Principal and where required by
the local authority.
The FAT procedure should test all power distribution, grounding, wiring, instrument
installation, calibration and control/measurement system configuration, functionality and
interfaces. The procedure shall include a means of documenting the results of each step of
the test, with space for approval signatures.
The Manufacturer/Supplier shall perform the test in accordance with the procedure, and
then correct any problems that are revealed by the test prior to sending to site.
If off-skid equipment is part of the package, then it shall be temporarily wired to the junction
box on the skid for integrated testing. All connections shall be marked and tagged,
complete with installation instructions and drawings.
The Manufacturer/Supplier shall furnish all drawings, power supplies, computers, HMIs,
wiring harnesses, meters, displays and other equipment required to perform a thorough
test.
ECCN EAR99 DEP 32.32.00.12-Gen.
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FAT wet tests using the process fluid or a suitable substitute and FAT heat soak tests shall
only be required by exception and then only with the approval of the Principal. Skids
destined for off shore applications may require wet tests as part of the FAT.

11.2 SKID
The skid shall be inspected for compliance as follows:
• Layout drawing dimensional agreement,
• General quality of workmanship,
• Equipment access for maintenance and validation.

11.3 INSTRUMENTATION
11.3.1 General
All Instruments shall be inspected, tested and calibrated as per the Manufacturer’s quality
assurance process.
Although not specifically defined as part of the Process Automation Systems (PAS),
custody transfer measurement systems shall be inspected and tested in accordance with
DEP 62.10.08.11-Gen. and the requirements of this Section.
11.3.2 Meters
In addition to the Manufacturer’s standard calibrations, custody transfer meters shall be
factory or flow loop calibrated as required as per DEP 32.32.00.95-Gen. Meter calibrations
shall be witnessed by the Principal or a representative.
As part of the inspection procedure, the upstream and downstream straight run piping
lengths and quality shall be confirmed. For differential producers, internal diameters, pipe
eccentricity, etc. shall be confirmed.
11.3.3 Samplers
Except where noted in DEP 32.32.00.95-Gen., samplers generally do not require FATs.
11.3.4 QMIs
QMIs shall be factory tested at the QMI Manufacturer’s facility as per the requirements of
DEP 32.31.50.10-Gen. As part of the skid FAT, testing shall be limited to a dry test without
process fluids to confirm correct power and signal wiring, outputs, fault indicators, sample
valves, etc. The QMI system performance test shall be performed after commissioning.
11.3.5 Computational devices
Tests of computation devices shall include, but not be limited to the following:
a) Verification of proper configuration of computational devices,
b) Verification of digital communication between all devices identified in the
measurement system architecture drawing (i.e., register mapping confirmations,
watch dog timers, etc.),
c) Functional and performance check of all conversions of analogue and frequency
measured variables into digital values,
d) Confirmation of correct flow rate and where applicable energy computation and
quantity integration operations with simulated measurement inputs,
e) Confirmation of correct input/output signals to the totalisers, analogue indicators or
recorders, meter, sampler and SCADA or BPCS systems,
f) Confirmation of correct generation of operating function alarms, e.g., high flow rate,
etc.,
g) Confirmation of computer system and health monitoring alarms,
ECCN EAR99 DEP 32.32.00.12-Gen.
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h) Confirmation of event logging and reports (e.g., snapshot, tender, proving, end of
day),
i) Verification of all diagnostic software communications,
j) Demonstration of auto start-up and recovery after power failure,
k) Functional check of Manufacturer/Supplier supplied tools and test equipment with
the main equipment.
Dynamic tests utilizing fluids shall be performed as part of commissioning and start-up.
The programme shall include but not be limited to the following tests:
a) Verification that meter run and master meter selection valves operate correctly, that
the valves seal, and correctly signal the valve positions;
b) Verification that the meter stream flow control valves function correctly and that flow
balance between meter runs is achieved;
c) Verification that the measurement data presented at the operator's interface to the
microcomputer are correct and that commands given at the interface are executed
correctly.
In order to verify the flow computer software/firmware, duly tested and accepted flow and
uncertainty calculation programs, independent of the programs used in the flow computer,
that apply the standards cited above and are run on an off-line computer shall be available
to provide the necessary reference information.

11.4 PIPING SYSTEMS

All materials used in fabricating the process pressure-retaining system, e.g., pipe work,
valves, fittings, etc., shall have relevant mill certificates, casting melt certificates, etc., in
accordance with the applicable specification (e.g., MESC).
Prior to commencement of fabrication, the welder(s) for the process piping fabrication shall
be certified to the requirement of the piping design specification.
During fabrication, welds shall be inspected as defined in DEP 31.38.01.31-Gen. Records
shall be kept and witnessed as appropriate.
Hydrostatic pressure tests shall be performed in accordance with ASME B31.3,
DEP 62.10.08.11-Gen. and DEP 31.38.01.31-Gen. Specifically, following removal of the
meters (where required) and their replacement by pipe spools, the entire pipe work system
shall be maintained at maximum rated pressure for the recommended time. A certified chart
record of temperature and pressure shall be produced covering the duration of the test.
All flanges and swing elbows shall be capable of being opened without pipe spring or
malfunction. The Principal may require the Manufacturer to open joints for spot checks.

11.5 ELECTRICAL
Custody transfer measurement systems/skids intended for use outside of North America
shall be tested and inspected as per DEP 63.10.08.11-Gen. and for those systems/skids
intended for use inside North America as per DEP 63.10.08.14-Gen.

11.6 CALIBRATION EQUIPMENT AND FACILITIES

The following calibration equipment shall be inspected to verify conformation with purchase
specification:
a) Temperature baths (where required),
b) Master glass thermometers and portable electronic thermometers (PETs), and,
c) Pressure calibrator or dead-weight tester;
If a dead-weight tester is included in the calibration equipment, the calibration facility shall
determine the gravitational constant for the location of the metering station. This constant
ECCN EAR99 DEP 32.32.00.12-Gen.
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can be calculated based on a formula from the International Association of Geodesy with
data derived from satellite orbital variations (1970) and is always to within 10-3 m/s2 and
usually within 5 x 10-4 m/s2.

11.7 SITE ACCEPTANCE TEST

The site acceptance test shall be developed by the Manufacturer to demonstrate that the
completely assembled and installed metering system, including master meter, density
measurement and samplers at the metering station, operate successfully under typical
operating conditions utilizing the actual process fluid. Communication with the live
BPCS/SCADA system and third parties, where applicable, shall be verified.
With the approval of the Principal, the site acceptance may be incorporated into the facility
start-up and commissioning program thereby negating the requirement for independent wet
tests.
Where independent wet tests are deemed necessary, the Manufacturer shall assemble the
complete metering system, or sub-system such as a single stream, for a functional test.
The assembly shall include a suitable blower or compressor, a gas reservoir and additional
temporary pipe work to allow test gas (e.g., air) to be circulated through the system. The
temporary facilities shall be capable of achieving a variable flow rate up to at least twice the
capacity of a single meter run. All measurement transducers shall be installed and
connected by temporary cables to the microcomputers and all control output signals from
the microcomputers to selection valves, control valves, etc., shall be connected and
commissioned.
After satisfactory completion of the functional tests, the test gas shall be drained off and the
piping system dried, e.g., by blowing through warm dry compressed air.

12. PRESERVATION AND PREPARATION FOR SHIPMENT

The Supplier shall install all instrumentation on the skid to the maximum extent possible.
Only items that cannot be installed and tested assembled shall be shipped loose for
assembly at the integration site.
Packaged equipment preparation for shipment shall include protection for a combined
transportation and storage time of up to one full year unless a different period is agreed
with the Principal.
The Manufacturer/Supplier shall advise the Principal of equipment or spare parts (e.g.,
electro-chemical sensors, probes) that have shelf life less than one year so that special
precautions are taken to ensure their functions will not be impaired before being put into
service.
Additional protection may be required by the technical specifications or the purchase
documents. In case of conflict, or if clarification is required, the Manufacturer/Supplier shall
request a written explanation from the Principal.
If the Supplier of equipment is not the equipment Manufacturer, the Supplier shall obtain all
the necessary instructions on preparation of equipment for shipment and protection of
equipment during storage.
In certain cases, specific requirements may be overly restrictive when applied to equipment
or materials having a high corrosion resistance. In such cases, the Manufacturer/Supplier
may provide alternate packing and preservation methods for review by the Principal. The
use of alternate methods requires the approval of the Principal on a case-by-case basis.
The Manufacturer/Supplier shall pack all items with the presumption that materials and
equipment will be stored outdoors in an unsheltered area prior to use. Exception to this
requirement are instruments, controls, office equipment, control panels and electrical
equipment intended for installation indoors or any other items that are particularly specified
by the Manufacturer/Supplier to require special handling or storage. These items shall be
stored in an enclosed sheltered area, which will be provided with a controlled environment if
necessary.
ECCN EAR99 DEP 32.32.00.12-Gen.
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Prior to shipment, all high-accuracy or vibration sensitive skid-mounted instruments shall be

removed, packed separately, and shipped with the skid.
If specially-fabricated handling tools or lifting strongbacks/spreader bars are required for
movement of finished equipment in the field, the Manufacturer/Supplier shall assure that
these same items accompany the shipment in order to safely handle the equipment.
Precautions shall be taken, when handling and moving equipment, to prevent damage,
distortion or exposure to potentially damaging conditions.
Care shall be taken in handling small items, principally electrical devices and instruments.
All equipment and materials subject to moisture damage including rotating equipment,
electrical equipment, and instrumentation shall be packaged with a moisture barrier to
prevent the ingress of moisture during shipment and storage at jobsite or fabrication yard.
Each instrument item shall be kept in a clean dry storage room of uniform temperature
while being prepared for shipment.
Loose or moveable parts of the skid/devices shall be fitted with shipping blocks and shims
for bracing against movement or vibration during transportation. Shipping blocks and shims
shall be clearly and prominently labelled for removal after installation.

Individual pieces of equipment (e.g., meters, valves) and skid packages shall be
prepared for shipment by the Manufacturer/Supplier as follows:
a) Package shall be de-pressurized, drained or blown dry of any hazardous material
and/or water prior to shipment.
b) All connection points shall be appropriately tagged.
c) Any vent lines that are capped and/or sealed for shipping shall be flagged for
removal prior to service.
d) Threaded and tube openings shall be sealed and plugged with suitable protectors to
prevent damage to threads or tubing and prevent the ingress of dirt or packing
material.
e) Flange faces, where applicable, shall be coated with a suitable rust preventative and
shall be protected with wood or plastic flange covers, securely bolted to the flange.
f) Panel and shelter exhaust vents and air intakes shall be covered with appropriately
secured plastic.
g) Fragile or sensitive pieces of equipment shall be removed and packaged separately.
h) Ancillary devices shall be crated or boxed, at the Supplier’s discretion, unless
specified on the data sheets, in such a fashion to preclude, within reason, damage in
transit.
i) Documents, tags or instructions necessary for proper unpacking and protection after
unpacking shall be enclosed and their location marked on the outer covering.

13. DOCUMENTATION

13.1 GENERAL
All drawings, manuals, datasheets shall be provided, as a minimum, in native electronic
format as specified by the Principal. Other formats and the quantity of electronic and
hardcopy copies shall be defined by the Principal for each project.
Approval of drawings by the Principal does not release the Contractor, Manufacturer or
Supplier from the responsibility for proper design, fabrication and functioning of the
equipment and systems provided.
All preliminary drawings and data sheets shall be as built (i.e., updated to reflect as
supplied condition).
ECCN EAR99 DEP 32.32.00.12-Gen.
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Instrument data sheets shall utilize the Principal’s format or a format approval by the
Principal.

13.2 DOCUMENTATION REQUIRED WITH THE PROPOSAL

The following documentation shall be provided with the proposal:
a) System architecture drawing (e.g., meters, transmitters, samplers, flow computers,
work stations, remote access points and parties),
b) P&ID (PEFS),
c) Preliminary skid layout and general arrangement drawing,
d) Manufacturers and model numbers for verification with the approved Supplier list for
all devices such as meters, secondary instruments including QMIs, flow computation
devices, valves (isolation, control, pressure relief, check), specialty piping
components (e.g., flow conditioners, static mixers), samplers, communication
equipment (e.g., routers, switches), software, etc.
e) List of instrumentation and controls not mentioned in the mechanical equipment
specification; but, in the Contractor/Manufacturer/Supplier’s opinion, are required for
efficient and safe operation.
f) Catalogue data, descriptive bulletins and (where applicable) general outline drawings
showing principal dimensions for all instruments, control devices, and control panels
furnished shall be included in the proposal.
g) An individually priced recommended spare parts list.
h) A list of software, special tools and/or equipment for installation, calibration, check-
out, maintenance and servicing of instruments and control systems, individually
priced.
i) If the Manufacturer/Supplier requires that they furnish the services of a field engineer
to check out and verify the satisfactory installation and operation of the instruments
and control equipment furnished to warrant the specified performance of the
mechanical equipment, the Manufacturer/Supplier shall state this in the proposal and
include rates.
j) Preliminary FAT procedure.
k) Recommended training for specialty equipment (e.g., meters, flow computers).
l) Uncertainty computations according to (3.3).
m) A list of outstanding issues or clarifications required.

13.3 DOCUMENTATION REQUIRED ON COMPLETION

Based on the purchase specification and the schedule of delivery for documentation, the
Manufacturer/Supplier shall provide the following information as a minimum. Any additional
documentation required (not covered in the list below) shall be defined by the Principal.
During the manufacture, testing, installation and final commissioning, a system dossier
shall be assembled contained in binders and appropriate electronic media, as a minimum,
the items listed below:
a) System architecture drawing (flow computers, work stations, remote access points
and parties),
b) A narrative description of the metering system including its design philosophy,
operating envelope, traceability, uncertainty, applicable standards, flow
computations, required approvals, data transfer, methods and criteria for
measurement corrections in case of dispute, recommended calibration frequency,
etc.,
c) P&ID (PEFS),
ECCN EAR99 DEP 32.32.00.12-Gen.
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d) A listing of all electrical, instrument and control equipment supplied (by tag number),
e) An Instrument data sheet for each device (e.g., meter, transmitter, QMI, valve,
sampler, speciality piping item, flow computer) in the format approved by the
Principal,
f) Catalogue data, descriptive bulletins and installation and operating manuals for each
piece of equipment.
g) Instrument Sizing Calculation reports (e.g., valves, meters),
h) Thermowell vibration, pipe stress and pressure drop computations,
i) Configuration files in native format and paper listing for all programmable and
configurable devices (e.g., PLC programs, flow computers, transmitters, meters,
routers, switches, etc.),
j) An individually priced recommended spare parts list,
k) A list of software, special tools and/or equipment for installation, calibration, check-
out, maintenance and servicing of instruments and control systems, individually
priced,
l) FAT procedure,
m) Certified dimensional drawings for skids, shelters, major pieces of equipment,
n) Electrical power wiring diagrams,
o) Electrical signal wiring (i.e., loop) drawings,
p) Communications wiring diagrams including ports and pin-outs where applicable,
q) Piping schematics,
r) Electrical and instrument location plans,
s) Instrument installation detail,
t) Calibration certificates and test reports (13.4),
u) Instrument I/O list complete with addresses (e.g., Modbus and FF addresses),
v) I/O list for Interface with BPCS, FGS and IPS complete with addresses,
w) Alarm List (operational and diagnostic),
x) Cause and Effects,
y) Alarm and Trip Settings,
z) Spare parts list as defined in DEP 70.10.90.11-Gen.

13.4 CERTIFICATES AND REPORTS

a) Electrical equipment certification for hazardous areas,
b) Calibration certificates (e.g., meter, transmitters),
c) Calibration certificates for the validation and test equipment,
d) Measurement equipment approvals as required to meet local authority requirements,
e) Materials test (e.g., Non-Destructive Inspection [NDI]), inspection reports (e.g., mill
reports) and certificates,
f) Hydrotest report,
g) SAT/FAT report,
h) Uncertainty computation report.
ECCN EAR99 DEP 32.32.00.12-Gen.
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14. REFERENCES
In this DEP, reference is made to the following publications:
NOTES: 1. Unless specifically designated by date, the latest edition of each publication shall be used,
together with any amendments/supplements/revisions thereto.
2. The DEPs and most referenced external standards are available to Shell staff on the SWW (Shell
Wide Web) at http://sww.shell.com/standards/.

SHELL STANDARDS
DEP feedback form DEP 00.00.05.80-Gen.
Standard drawings index DEP 00.00.06.06-Gen.
The use of SI quantities and units (endorsement of ISO/IEC 80000) DEP 00.00.20.10-Gen.
Protective coatings for onshore facilities DEP 30.48.00.31-Gen.
Piping classes - Basis of design DEP 31.38.01.10-Gen.
Piping - General requirements DEP 31.38.01.11-Gen.
Piping classes – Refining and chemicals DEP 31.38.01.12-Gen.
Piping classes – Exploration and production DEP 31.38.01.15-Gen.
Shop and field fabrication of piping DEP 31.38.01.31-Gen.
Fiscal and sales allocation models for upstream production systems DEP 32.00.00.12-Gen.
Process control domain – Enterprise industrial automation DEP 32.01.20.12-Gen.
information technology and security
Process control domain - Security requirements for suppliers DEP 32.01.23.17-Gen.
Instruments for measurement and control DEP 32.31.00.32-Gen.
Instrumentation for equipment packages DEP 32.31.09.31-Gen.
On-line process analysers DEP 32.31.50.10-Gen.
Analyser housing DEP 32.31.50.13-Gen.
Custody transfer measurement systems for liquids DEP 32.32.00.11-Gen.
Gas custody transfer metering system for gases and vapours DEP 32.32.00.95-Gen.
(requisition sheet)
Control valves - Selection, sizing, and specification DEP 32.36.01.17-Gen.
Static DC uninterruptible power supply (DC UPS) units DEP 33.65.50.31-Gen.
Static A.C. uninterruptible power supply unit (static A.C. UPS unit) DEP 33.65.50.32-Gen.
Selection of materials for life cycle performance (Upstream facilities) - DEP 39.01.10.11-Gen.
Materials selection process
Inspection and functional testing of instruments DEP 62.10.08.11-Gen.
Field commissioning of electrical installations and equipment DEP 63.10.08.11-Gen.
Field commissioning and testing of electrical installations and DEP 63.10.08.14-Gen.
equipment for North American application
Spare parts DEP 70.10.90.11-Gen.
Design of pressure relief, flare and vent systems DEP 80.45.10.10-Gen.
Overpressure and underpressure – Prevention and protection DEP 80.45.10.11-Gen.
ECCN EAR99 DEP 32.32.00.12-Gen.
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STANDARD DRAWINGS
Flanged thermowell DN 40 (NPS 1-1/2), ASME classes up to S 38.113
1500 incl.

AMERICAN STANDARDS
Orifice Metering of Natural Gas and Other Related Hydrocarbon AGA Report 3-1
Fluids - Concentric, Square-edged Orifice Meters Part 1: General
Equations and Uncertainty Guidelines - Fourth Edition
Orifice Metering of Natural Gas and Other Related Hydrocarbon AGA Report 3-2
Fluids Part 2 Specification and Installation Requirements - Fourth
Edition;
Orifice Metering of Natural Gas and Other Related Hydrocarbon AGA Report 3-3
Fluids Part 3 Natural Gas Applications - Third Edition;
Natural Gas Energy Measurement AGA Report No. 5
Measurement of Natural Gas by Turbine Meters (2006) AGA Report No. 7
Compressibility Factors of Natural Gas and Other Related AGA Report No. 8
Hydrocarbon Gases
Measurement of Gas by Multipath Ultrasonic Meters AGA Report No. 9
Speed of Sound in Natural Gas and Other Related Hydrocarbon AGA Report No. 10
Gases
Measurement of natural gas by Coriolis meter AGA Report No. 11
Orifice metering of natural gas and other related hydrocarbon fluids, AGA Report No. 3, Part 2
Part 2 - Specification and installation requirements
Manual of Petroleum Measurement Standards Chapter 14—Natural API MPMS 14.1
Gas Fluids Measurement, Section 1—Collecting and Handling of
Natural Gas Samples for Custody Transfer
Manual of petroleum measurement standards, Chapter 14 - Natural API MPMS 14.3.1
gas fluids measurement, Section 3 - Concentric, square-edged orifice
meters, Part 1-General equations and uncertainty guidelines
Manual of Petroleum Measurement Standards, Chapter 14 - Natural API MPMS 14.3.2
Gas Fluids Measurement, Section 3 - Concentric, Square-Edged
Orifice Meters, Part 2-Specification and Installation Requirements
Manual of petroleum measurement standards, Chapter 14 - Natural API MPMS 14.3.3
gas fluids measurement, Section 3 - Concentric, square-edged orifice
meters, Part 3-Natural gas applications
Manual of petroleum measurement standards, Chapter 21 - Flow API MPMS 21.1
measurement using electronic metering systems, Section 1 -
Electronic gas measurement
Natural gas fluids measurement - Concentric, square-edged orifice API MPMS Chapter 14.3
meters, Part 2 – Specification and installation requirements Part 2
Properties of Saturated and Superheated Steam in U.S. Customary ASME Steam Tables
and SI Units from the IAPWS-IF97 International Standard for
Industrial Use
Malleable iron threaded fittings classes 150 and 300 ASME B16.3
Process piping ASME B31.3
Standard practice for sampling steam ASTM D 1066
ECCN EAR99 DEP 32.32.00.12-Gen.
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Standard test method for determination of total volatile sulfur in ASTM D 6667
gaseous hydrocarbons and liquefied petroleum gases by ultraviolet
fluorescence
Analysis for natural gas and similar gaseous mixtures by gas GPA 2261
chromatography
Issued by:
Gas Processors Association

GERMAN STANDARDS
Standardization of the signal level for the failure information of digital NAMUR NE-43
transmitters
Issued by:
NAMUR Geschäftsstelle

INTERNATIONAL STANDARDS
IAPWS Formulation 1995 for the Thermodynamic Properties of IAPWS-95
Ordinary Water Substance for General and Scientific Use
Issued by:
International Association for the Properties of Water and Steam (IAPWS)

Industrial platinum resistance thermometer sensors and platinum IEC 60751

temperature sensors
Measurement of fluid flow by means of pressure differential devices ISO 5167-1
inserted in circular cross-section conduits running full, Part 1 -
General principles and requirements
Measurement of fluid flow by means of pressure differential devices ISO 5167-2
inserted in circular-cross section conduits running full, Part 2 - Orifice
plates
Measurement of Fluid Flow by Means of Pressure Differential ISO 5167-4
Devices Inserted in Circular Cross-Section Conduits Running Full -
Part 4: Venturi Tubes
Measurement of fluid flow – Procedures for the evaluation of ISO 5168
uncertainties
Pulps- Determination of drainability- Part 2: Canadian standard ISO 5267-2
"Freeness Method"
Gas Analysis - Preparation of calibration gas mixtures - Gravimetric ISO 6142
method
Natural gas — Determination of sulfur compounds ISO 6326
Natural Gas - Determination of Potential Hydrocarbon Liquid Content ISO 6570
- Gravimetric Methods
Natural gas - Determination of composition with defined uncertainty ISO 6974-1
by gas chromatography, Part 1: General guidelines and calculation of
composition
Natural Gas - Determination of Composition with Defined Uncertainty ISO 6974 3
by Gas Chromatography - Part 3: Determination of Hydrogen,
Helium, Oxygen, Nitrogen, Carbon Dioxide and Hydrocarbons up to
C8 Using Two Packed Columns
Natural gas - Calculation of calorific values, density, relative density ISO 6976
and Wobbe index from composition
Natural Gas - Determination of Mercury - Part 1: Sampling of mercury ISO 6978
by chemisorption on iodine
ECCN EAR99 DEP 32.32.00.12-Gen.
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Measurement of Gas Flow in Closed Conduits - Turbine Meters ISO 9951

Natural Gas - Determination of Water by the Karl Fischer Method ISO 10101
Natural Gas - Sampling Guidelines ISO 10715
Natural gas - Performance evaluation for on-line analytical systems ISO 10723
Measurement of fluid flow in closed conduits — Guidance to the ISO 10790 AMD 1
selection, installation and use of Coriolis meters (mass flow, density
and volume flow measurements) AMENDMENT 1: Guidelines for gas
measurement
Natural gas Calculation of compression factor Part 2: Calculation ISO 12213-2
using molar-composition analysis
Natural gas — Calculation of compression factor — Part 3: ISO 12213-3
Calculation using physical properties
Natural Gas - Standard Reference Conditions ISO 13443
Natural gas - Guidelines to traceability in analysis ISO 14111
Natural gas — Measurement of properties — Volumetric properties: ISO 15970
density, pressure, temperature and compression factor
Measurement of fluid flow in closed conduits — Ultrasonic meters for ISO 17089-1
gas — Part 1: Meters for custody transfer and allocation
measurement
Natural gas Correlation between water content and water dew point ISO 18453
Natural gas Determination of sulfur compounds using gas ISO 19739
chromatography
Gas Meters – Part 1 - Metrological and technical requirements OIML R 137-1
Gas Meters – Part 2 - Metrological controls and performance tests OIML R 137-2
Measuring systems for gaseous fuel OIML R 140
Issued by:
International Organization of Legal Metrology (OILM)
ECCN EAR99 DEP 32.32.00.12-Gen.
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APPENDIX A BLACK AND WHITE LIST

Below is a black and white list as an example of a contract appendix, which is in common
use for gas custody transfer measurements. Considering the variety of potential
applications, it will be necessary to modify the text to reflect the specifics of a given
application (e.g., reference conditions, engineering units, industry standards, local;
authorities, etc.).
The terms Seller and Buyer are used to denote the two parties but in many applications
these terms would be Shipper to denote the party delivering the fluid into the connecting
system and Carrier to denote the party operating the pipeline system which transports the
product.

A.1 WHITE LIST

A.1.1 All methods, procedures and international standards, unless stated otherwise, shall be in
accordance with the latest editions. In the case of any newly published or revised standard,
Seller(s) and Buyer shall mutually agree on adopting such a new standard. Parties may
agree on other methods than those stated in this Agreement if such would be more
appropriate in view of all the circumstances then prevailing.
A.1.2 The units of quantity shall be mass, energy or volume (select as required).
A.1.3 The units of volumetric quantity shall be in accordance with ISO 13443 standard reference
conditions. Specify other conditions if different, such as US customary units (60 °F, 0 psig).
(Not required for mass measurement.)
All calculated and measured values (temperature, pressure, mass, volume, density
heating/calorific value, etc.) shall be expressed in units according to the International
System of units (SI). (Specify other engineering units as required.).
A.1.4 Compressibility shall be computed based on gas composition according to ISO 12212-2 or
AGA 8 (select one).
A.1.5 The gross heating value shall be computed based on gas composition according to
ISO 6976 or AGA 5 (select one).
A.1.6 The gross heating value shall be measured according to (state method or device).
A.1.7 Compositions shall be determined on-line utilizing a process gas chromatograph or by
analyzing a monthly composite sample. (select one).
A.1.8 Product quality specifications shall be as per Table A (to be included as part of the
contract).
A.1.9 If regular samples or spot samples are taken for determination by laboratory analysis of the
composition and physical properties of the natural gas, the following methods will be used:
a) The total sulphur content, the hydrogen sulphide content, the carbonyl sulphide and the
alkylthiol content (mercaptans) shall be determined according to ISO 6326.
b) The water dew point shall be determined by measuring the water content according to
ISO 10101 and converting this value to water dew point using ISO 18453.
c) The hydrocarbon liquid content shall be determined according to ISO 6570.
d) The oxygen content shall be determined according to ISO standards or by a method
mutually agreed between Sellers and Buyer.
e) The natural gas composition, including carbon dioxide, benzene and toluene contents,
shall be determined by a gas chromatographic method in accordance with ISO 6974.
NOTE: Composition and physical properties as defined under a, b and c shall be determined by a laboratory
mutually agreed upon by Sellers and Buyer.

A.1.10 The system of all measurements, the type of instruments used, the use of derived
measurement values instead of direct measurements, the procedures for maintenance and
calibration, the methods and criteria by which measurement corrections will be made and
ECCN EAR99 DEP 32.32.00.12-Gen.
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other items relevant to the measurement of the (insert fluid name(s)) at the Delivery Point
shall be mutually agreed upon between Sellers and Buyer and shall be specified in a
Measurement Manual.
A.1.11 A draft of the Measurement Manual shall be prepared prior to start-up. Within a period of
3 months after start-up of the measuring station at the Delivery Point, the Measurement
Manual shall be finalized, reviewed and approved by appropriate parties. This Manual shall
specify the detailed methods and instruments for measuring and/or calculating the quantity,
composition and physical properties of the (fluid) delivered, the calibration and maintenance
procedures and the inaccuracies of the instruments.
A.1.12 The Measurement Manual is subject to Buyer's approval.
A.1.13 This manual shall give a detailed description of the flow measurement system(s) and
methodology followed to achieve the required results. The following information shall be
specified in detail:
a) Complete description of measurement system including operating principles of
instrumentation and the methodology of determining mass, volume and energy flow.
b) Change control procedures concerning custody transfer measurement systems.
c) Methodology and quality assurance of results obtained.
d) Uncertainty analysis including the overall uncertainty of custody transfer
measurement system(s) and the documentation of permissible errors.
e) Rules of handling measurement deviations. Maintenance intervention should be
specified.
f) Handling and communication of acknowledged measurement deviations exceeding
permissible error limits, with special attention to notification of contract parties and
the regulatory authority.
g) Methods and criteria for measurement corrections.
h) Measurement values inferred instead of directly measured, in the event of failing
input.
i) Logging of information in support of the qualitative and quantitative operation of the
measurement station including date stamped information concerning:
1) calibration results/reports of instruments and calibration equipment;
2) parameter list of flow computer;
3) maintenance activities;
4) operational activities, e.g., when meter run was changed over.
j) Detailed instructions for the operation, calibration, adjustment, maintenance and
documentation of the custody transfer measurement system(s).
k) Review of validation intervals.
l) Competence of maintenance staff.
A.1.14 In the laboratory determinations of the composition and physical properties of the (fluid), the
quality and quantity measurements specified in this Article, the appropriate tolerances of
the standard methods specified in (A.1.9) shall be applied.
If a measurement tolerance is not covered by a standard, Buyer and Sellers shall mutually
agree upon such a value, which will be specified in the Measurement Manual. Buyer and
Sellers may mutually agree values other than the tolerances specified in the standards.
A.1.15 The accuracy of metering facilities shall be validated by the Party operating the metering
facilities at the frequency specified in regulations, or as reasonably required by the
Operator whichever is more frequent. The cost of such validations shall be borne by the
Operator. Metering facilities shall be open for witnessing of calibration or inspection by the
ECCN EAR99 DEP 32.32.00.12-Gen.
February 2013
Page 47

other Party at all reasonable times. The Party performing the calibration or inspection will
provide the other Party with at least forty-eight (48) hours prior notice.
A.1.16 In case any question arises as to the accuracy of measurement, any metering facilities shall
be tested upon demand of either Party and, if found to be correct or to be in error of not
more than x percent (x.x %) with respect to equilibrium liquid measurement, or x cent
(0.x %) with respect to gas measurement (referred to as the “Relevant Percentage”), the
expense of such testing shall be borne by the Party requesting the test. If the accuracy of
measurement is found to be incorrect by more than the Relevant Percentage, the expense
of such testing shall be borne by the owner of those metering facilities.
A.1.17 If, upon any test, the metering facilities are found to be in error of not more than the
Relevant Percentage, previous readings of such metering facilities shall be considered
correct in computing the volumes being metered, but such metering facilities shall be
adjusted as soon as practicable to record accurately. If, upon any test, any metering
facilities are found to be in error by any amount exceeding the Relevant Percentage, then
any previous readings of such metering facilities shall be corrected to zero error for any
previous period which is known definitely or is agreed upon. In cases where the period is
not known definitely or not agreed upon, such correction shall be for a period covering the
last half of the time lapsed since the date of the last test.
A.1.18 In the event metering facilities are out of service or require repair, such that the volume
being measured is not correctly indicated by the reading of the metering facilities, the
volumes attributable to the period shall be estimated and agreed upon on the basis of the
best data available, using the most appropriate of the following methods:
a) by using the registration of any check metering facilities, if installed and accurately
registering; or
b) by correcting the error if the percentage of error is ascertainable by calibrations,
tests or mathematical calculations; or
c) by estimating on the basis of actual volumes measured during the preceding periods
under similar conditions when the metering facilities were registering accurately.
A.1.19 The records (electronic, written or otherwise) of the meters and the flow computer shall be
the property of the Operator and shall be retained by the Operator for a period of [x] years
from date of origination. Upon the request of the Buyer, the Seller shall submit to the Buyer
such records, together with the Seller's calculations there from, for inspection, verification
and copying, subject to return by the Buyer within thirty (30) days after receipt thereof.

A.2 AT THE DELIVERY POINT

A.2.1 Sellers shall, at their own expense, build, equip, maintain, operate and monitor a measuring
station near the Delivery Point or arrange for this to be done.
Such measuring station shall be built, equipped, maintained, operated and monitored
according to the appropriate sections of DEP 32.32.00.12-Gen.
Matters not fully provided for in this DEP shall be dealt with in accordance with the relevant
local regulations, as provided for in this Sales Agreement or as mutually agreed upon by
the Parties.
A.2.2 The volume/energy/mass delivered at the Delivery Point shall be calculated on a
continuous basis from the delivered flow measured on-line determined according to the
calculation method specified in the Measurement Manual.
A.2.3 The delivered quantity of the (fluid) shall be measured and calculated in accordance with
DEP 32.32.00.12-Gen.
A.2.4 Buyer's visits to the measuring station at the Delivery Point, the calibrations and checks of
the measuring instruments and the procedures for dealing with improper measurements or
incorrect operation of the instrumentation shall all be in accordance with the Measurement
Manual.
ECCN EAR99 DEP 32.32.00.12-Gen.
February 2013
Page 48

A.2.5 Buyer is entitled at its sole risk and expense to connect a telemetering system to Seller’s
measurement system at the Delivery Point. Signals to be transferred shall be mutually
agreed.
A.2.6 At the request of Buyer, Sellers shall make available to Buyer at the Delivery Point the flow,
pressure and temperature signals measured at the Delivery Point and, at Buyer's request
the fluid density measurement signals for on-line transfer via Buyer's telemetering system.
The inclusion of any other quality factor(s) of the (fluid) other than those specified in the
contract is subject to mutual agreement between Sellers and Buyer. Buyer is allowed to
witness the calibration of any part of the measurement system that affects the
measurement signals that have been made available.
A.2.7 Sellers shall give at least forty-eight (48) hours' notice to Buyer of regular sampling referred
to in (A.1.7) of (fluid) at the Delivery Point for determination by laboratory analysis of the
composition and physical properties of the (fluid). Buyer and Sellers shall mutually agree
upon the frequency or change of frequency of regular sampling. Buyer may request, with
reasons given, spot samples of the (fluid) at the Delivery Point, and Sellers shall inform
Buyer of the time of sampling. The regular and spot samples will be collected by the
appropriate technique according to API 14.1 or ISO 10715. Parties may agree on other
methods if more appropriate in view of all prevailing circumstances.
The analysis shall include the composition and physical properties of the (fluid) as specified
in the contract, unless Buyer and Sellers agree otherwise. Sellers shall inform Buyer of all
results of all determinations by Sellers of the composition and physical properties of the
regular samples. Buyer shall have the right to be represented to witness the sampling and
to verify that the composition and physical properties are determined in accordance with the
standards specified in (A.1.5). Should Buyer, although notified, not be represented, the
sampling and determination by Sellers shall be considered valid until the following sampling
and determination.

A.3 BLACK LIST

This black list refers to the explicit wish of Buyer to be entitled to receive at the Delivery
Point measurement signals beyond the Delivery Point at the outlet of Sellers' production
location(s).
Under specific circumstances and solely at their discretion, Sellers are prepared to meet
some or all of Buyer's requests as listed below under a) to d) inclusive, subject to the
following provisos:
1. If requested by Buyer, Sellers are prepared to make available at the Delivery Point
without any further conditions the flow measurement signal at the outlet of Sellers'
production location(s);
2. If requested by Buyer, Sellers shall make available to Buyer any other already
installed measurement signal at the outlet of Sellers' production location(s), including
temperature and pressure signals, if Buyer has plausibly demonstrated to the sole
judgement of Sellers that such signal(s) are necessary for the proper operation of
Buyer's facilities and for Buyer to fulfil its obligations under the (fluid) Sales
Agreement;
3. Under no circumstances shall Sellers agree with Buyer that agreed measurement
signals from Sellers' production location(s) will be used for monitoring of contract
limits.
Signals of measurements at the outlet of Sellers' production location(s):
a) At the request of Buyer, Sellers shall make available to Buyers at the Delivery Point
the flow, temperature and pressure measurement signals at the outlet of Sellers'
production location(s) for on-line transfer via Buyer's telemetering system.
b) At the request of Buyer, Sellers shall make available to Buyer at the Delivery Point
the requested signals of installed quality measurements at the production location(s)
for on-line transfer via Buyer's telemetering system.
ECCN EAR99 DEP 32.32.00.12-Gen.
February 2013
Page 49

c) If, in Buyer's opinion, not yet installed quality measurements at Sellers' production
location(s) are necessary for the proper operation of Buyer's facilities and for Buyer
to fulfil its obligations under the Agreement, then Buyer and Sellers shall jointly
decide on the installation of any such measuring equipment. Before implementing
such additional measurements, Parties shall agree to what extent each Party shall
bear the cost of such additional measurement(s) in view of their respective
obligations under the Agreement. Sellers shall not unreasonably withhold their
concurrence with Buyer's request unreasonably.
d) Buyer shall be allowed to witness the calibration of any part of the measurement
system at the production location that affects agreed measurement signals to Buyer.
ECCN EAR99 DEP 32.32.00.12-Gen.
February 2013
Page 50

APPENDIX B COMMON ENGINEERING UNITS

Common Engineering Unit Summary

Parameter SI US Customary Other
3 3
Density kg/m lbm/ft
Length metre in mm
Mass kilogram pound_mass tonne, ton
Molecular Weight grams/mole lbm/lbmol
2
Pressure (absolute) kPa psia Atm, bar, kgf/cm
Pressure (gauge) kPag psig barg
(1)
Pressure Differential kPa in WC60 mmWC15, mbar
Temperature (relative) Celsius Fahrenheit
Temperature (absolute) Kelvin Rankine
Viscosity (dynamic) Pa.s lbm/s cP
2 2
Viscosity (kinematic) m /s ft /s cSt
Volume (Gas) cubic metre cubic foot
Energy MJ BTU kWh
NOTE: (1) Pressures expressed using heights of liquids shall be referenced to a temperature.
For example, in WC60.
ECCN EAR99 DEP 32.32.00.12-Gen.
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APPENDIX C BASE CONDITIONS

Standard reference, base or standard conditions (henceforth, base conditions) are the
conditions of temperature and pressure to which measured volumes are to be corrected.
Base conditions vary from country to country, industry, usage and contractual
requirements. Base conditions in the petroleum and chemical industry are rarely
synonymous with standard temperature and pressure (STP) as defined by IUPAC, 0°C and
100 kPa. In some jurisdictions, base conditions are equal to “Normal” reference conditions,
0°C and 101.325 kPa. Therefore, it is essential to establish the base conditions for a given
application (i.e., base temperature and pressure).
With the exception of the United States, the base conditions used for custody transfer
volumes are typically 101.325 kPa (absolute) and 15 °C. In the United States, comparable
base conditions are 14.696 psia and 60 °F.
Physical properties are also reported to a reference condition, which may be different than
base conditions. If a physical property and a quantity are combined (e.g., volume and
heating value), the reference conditions for the volume and the heating value shall be the
same.
In all cases, the base pressure is not to be confused with the atmospheric or barometric
pressure. Atmospheric pressure is a function of altitude above sea level and the weather
and is typically fixed to a nominal value for a given facility for the purposes of flow
compensation. Exceptions to this practice are low pressure applications (e.g., flare
measurement) in which case absolute pressure is measured and used. The specific
nominal value to be used for a given application or plant is often cited in agreements,
project specifications or plant practices.
Where applicable (2.2), referenced temperature and pressure conditions should be
selected in accordance with ISO 13443.
ECCN EAR99 DEP 32.32.00.12-Gen.
February 2013
Page 52
APPENDIX D TYPICAL SINGLE METER RUN CTM GAS APPLICATION EXAMPLE

FLOW COMPUTER

TT

FT PT 7 TE TW AT SP

DP

FC FE

1 2 3 4 5 6 8 9 10 11

Components: Notes:
1) Strainer (if required) with pressure loss monitor 1) Schematic is generic in nature and therefore all elements may not be required for a specific application.
2) Upstream straight length or flow conditioner (FC) For example, for a mass measurement application using a coriolis meter, the strainer, flow conditioner,
3) Meter (FT) pressure and temperature transmitters are not required.
4) Downstream straight lengths 2) Strainer only required for turbine meters.
5) Temperature element/transmitter (TE,TT) 3) Upstream and downstream meter straight length requirement varies with meter type and upstream piping
6) Validation thermowell (TW) disturbances.
7) Pressure transmitter (if required) (PT) 4) Flow transmitter (FT) may be close coupled to flow sensor (FE) or remote mounted.
8) Analyzer (e.g., water cut, densitometer) (AT) 5) Analyzers are typically gas chromatographs, densitometers or moisture analyzers.
9) Sample point (manual or on-line) (SP) 6) Pressure relief valves should be located to preclude unmeasured fluids via a leaky relief valve.
10) Flow control valve 7) Spacer plate installed downstream of meter downstream straight length requirement to be utilized to
11) Check valve facilitate disassembly of meter run.

Rev. 1
ECCN EAR99 DEP 32.32.00.12-Gen.
February 2013
Page 53

APPENDIX E ANALYTICAL METHODS

Type of Purpose Standard Remarks

determination
Fluid composition To establish various ISO 6974 (2.2) Not to be used, if
properties inferred argon is expected in
from compositional significant amounts.
data. Argon interferes with
oxygen.
Water content • Limit property ISO 10101 and
• To infer water dew pertaining sub sets
point for known gas.
Hydrocarbon Limit property ISO 6570 and
condensates pertaining sub sets
Sulphur compounds Limit property ISO 19739 H2S is considered to
and total sulphur ASTM D 6667 be the only inorganic
sulphur compound in
natural gas.
Method includes H2S,
COS and RSH.
Mercury Limit property ISO 6978
Oxygen Limit property ISO 6974-3
ECCN EAR99 DEP 32.32.00.12-Gen.
February 2013
Page 54
APPENDIX F “Z” MASTER METER CONFIGURATION EXAMPLE

FT PT TT TW

FC
FE

FC
FT PT TT TW

FE
ECCN EAR99 DEP 32.32.00.12-Gen.
February 2013
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APPENDIX G LINING UP OF DENSITOMETERS IN ORIFICE METER RUNS (POCKET STYLE)

NOTES:
1) Taps for differential pressure measurement and for driving densitometer sample loop shall not be shared.
2) Sample tubing between sample point and densitometer shall be insulated.
3) Sample loop isolation valves S1 and S4 to be full port.
4) Sample loop flow meter (Fm) and needle valve (T1) to be mounted downstream of densitometer.
5) Drawing provided by manufacturer.
ECCN EAR99 DEP 32.32.00.12-Gen.
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Page 56

APPENDIX H THERMAL INSULATION FOR DENSITOMETERS AND TEMPERATURE

SENSORS

Removable lid

No thermal insulation, so as to
allow heat-transfer !!

Center line pipe

NOTE: 1) Sample lines between process pipe and densitometer to be isolated.

 ECCN EAR99 DEP 32.32.00.12-Gen.
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APPENDIX I FLOW COMPUTATION TYPICAL EXAMPLES

from staition density transmitter (referenced coditions) [kg/m3]

(for data validation only)

from stream density transmitter [kg/m3]

(for data validation only)

functionality in
flow computer
Mass [kg] to
supervisor
Totalizer
mass flow [kg/sec]

functionality in flow
dP tx

ISO 5167

computer
Note 1 Range selection [mbar]
functionality in flow
computer

dP tx

Volume [m3] to
functionality in

functionality in
flow computer

flow computer
Note 1

supervisor
Totalizer
Divider
Density Volumetric flow [m3/sec]
T tx [K] [kg/m3] at referenced conditions
or
Te

functionality in flow
Note 1

ISO 12213

computer
[bar]
P tx

Energy [MJ] to
functionality in

functionality in
flow computer

flow computer

supervisor
Multiplier

Totalizer
Note 1 Summation Energy flow
functionality in flow [MJ/sec]
computer at specified
[bar] conditions
barometric Mol for enthalpic
P tx weight correction
[kg/kmol]
Note 2
functionality in

Comp 1 [ %mol] Density [kg/m3]

functionality in
flow computer
ISO 6974

at referenced
functionality in supervisor PGC

ISO 6976

Comp i [ %mol]
PGC

coditions
PGC

system
Comp n-1 [ %mol]

specific)
(stream
PAY
Note 2 Comp n [%mol]
Data validation

Calorific value [MJ/kg]

at specified conditions
system

Chromatographic for enthalpic correction

data

SYSTEM
CHECK

(stream
speific)
Calorific value [MJ/kg]
functionality in
functionality in

flow computer

Comp 1 [%mol]
at specified conditions
ISO 6976
ISO 6974

Comp i [%mol] for enthalpic correction

PGC

PGC Comp n-1 [%mol]

Note 2 Comp n [%mol]

Density [kg/m3]
at referenced
coditions (for
Mol data validation
[bar]

functionality in
only)

flow computer
weight
functionality in
flow computer

P tx

Mass [kg] to
supervisor
[kg/kmol]
Multiplier

Totalizer
Energy flow
Summation
functionality in flow

Note 1 [MJ/sec]
functionality in flow at specified
computer
ISO 12213

conditions
computer

for enthalpic
[bar] correction
from station barometric
pressure Tx
Note 3
Volume [m3] to
functionality in
functionality in

flow computer
flow computer

T tx
supervisor
Totalizer
Divider

or Density [kg/m3]
Volumetric flow [m3/sec]
Te (for data validation
at referenced conditions
Note 1 only)
functionality in flow

dP tx
ISO 5167

computer

Note 1 Range selection [mbar]

functionality in flow
Energy [MJ] to
functionality in
flow computer

computer
supervisor
Totalizer

mass flow [kg/sec]

dP tx
Note 1

Density Density [kg/m3]

tx
Note 1

Density Density [kg/m3] at

tx referenced coditions

Figure I.1 Function diagram for orifice flow meter for gas with variable
composition - diverse redundancy

NOTES:
1) Stream specific
2) Station specific, facility at common inlet header or outlet header
3) Station specific
4) If no diverse redundancy is required, both density analysers can be eliminated. Density ex ISO 12213 and
density ex ISO 6976, both in the check system, become firm in that case.
ECCN EAR99 DEP 32.32.00.12-Gen.
February 2013
Page 58

Geometric
Linearization Flow [m3/sec]
Ultrasonic correction
meter functionality in
functionality in
USM
USM

at referenced conditions
Volume [m3]
T tx
or [K]
Te

functionality in
flow computer
Totalizer
P tx [bar]

functionality in flow

Volumetric flow [m3/sec]

at referenced conditions
Summation

ISO 12213
functionality in flow

computer
Density

Spervisory system
computer [kg/m3]
baro [bar]
Note 3
P tx

Multiplier/Divider
functionality in
flow computer
Energy flow

[kg/kmol]
weight
[MJ/sec]

Energy [MJ]
Mol
Chromatographic

Density at at specified

functionality in
functionality in

flow computer
flow computer
referenced conditions

Multiplier

Totalizer
for enthalpic
data

conditions
functionality in GC

correction

flow computer or
functionality in [kg/m3]
Component 1 [ %mol]
ISO 6976
ISO 6974

Note 3
Component i [ %mol]
GC
PGC Component n-1 [ %mol] Calorific value [MJ/kg]
at specified conditions for
Component n [ %mol] enthalpic correction

Figure I.2 Function diagram for ultrasonic flow meter for gas with variable
composition
NOTES:
1) General - GC not required in case of constant composition. Subject to updating as per (3.17), Group 1c, calorific
value and volume at base conditions to be calculated from fixed entry for gas composition and heating value in
flow computer.
2) Alternatively density and density at referenced conditions may be replaced by compressibility factor under
operating conditions and under referenced conditions respectively.
3) General - No redundancy shown.

Energy flow
[MJ/sec]
at specified
functionality in

functionality in
flow computer

Flow Pressure correction only conditions flow computer

[kg/sec] Flow [kg/sec] for enthalpic
Multiplier

Coriolis
Totalizer

for pressure effects on

sensor (i.e., no pressure correction
meter
correction on fluid).

Supervisory system
Pressure [bar]
P tx Calorific value
[MJ/kg]
at Base conditions

at specified
Volume [m3]

conditions for
enthalpic
functionality in GC

flow computer or

correction
functionality in

Component 1 [ %mol] Volumetric

ISO 6976

Chromatographic flow [m3/sec]

ISO 6974

functionality in

functionality in
flow computer

flow computer

data Component i [ %mol] Density at at base

GC

Totalizer
Divider

GC Component n-1 [ %mol] referenced conditions

conditions
Component n [ %mol] [kg/m3]

Figure I.3 Function diagram for Coriolis mass flow meter for gas with variable
composition
Notes:
1) General - GC not required in case of constant composition. Subject to updating as per (3.17), Group 1c, calorific
value and volume at base conditions to be calculated from fixed entry for gas composition and heating value in
flow computer.
2) Requirement for Coriolis meter sensor pressure compensation is determined assessing Coriolis meter sensor
pressure sensitivity relative to variability and magnitude of process pressure (e.g., dynamic sensor pressure
compensation is not required if station pressure is regulated.
3) Dynamic pressure compensation is to be applied in Coriolis meter electronics.
4) No redundancy shown.
ECCN EAR99 DEP 32.32.00.12-Gen.
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Page 59

APPENDIX J EXAMPLE OF MEASUREMENT SYSTEM ARCHITECTURE

LEGEND
L3 TCP/IP Ethernet
4 - 20 mA signal &
HART capability
Process Control Network RS-232

RS-485 Modbus

Alarm/Event Printer *1 Report Printer *1

FIT Differential pressure

Supervisory A Supervisory B Hxx transmitter high range

FIT Differential pressure

L2 TCP/IP Ethernet Lxx transmitter low range

PIT
Pressure transmitter
Moxa A Moxa B
Fiscal Measurement Network x

(proprietary) TIT Temperature transmitter

x

QT
Density transmitter
x

FC FC FC FC
Run 1A Run 1B Run 2A Run 2B

RS485/RS232
Convertor
Printer Printer
Switch Switch

FIT FIT
H1 H3

Chromatograph

Chromatograph
FIT Ticket FIT Ticket
H2 Printer H4 Printer

Gas

Gas
1

2
FIT FIT
PIT TIT PIT TIT
L1 L3
2 2 4 4
FIT PIT TIT QT FIT PIT TIT QT
L2 1 1 1 L4 3 3 2

Run 1 Run 2

Common header

Figure J.1 Dual run orifice metering station with full redundancy
ECCN EAR99 DEP 32.32.00.12-Gen.
February 2013
Page 60
APPENDIX K DATA ACQUISITION AND CONTROL ARCHITECTURE

EXTERNA
L
VENDORS
BUSINESS
INTERNET
USERS
Domain
Office

INTERNAL BUSINESS
TPA
HISTORIAN USERS &
SERVER
APPLICATIONS
L4 Office Network
TCP/IP Ethernet

Mirror image
Process Control
Access Domain

PCDP Note:
HISTORIAN PCAD
Process Control Domain
Portal

CCR

L3 Process Control Network

TCP/IP Ethernet

DCS
Process Control
Domain

Control bus (proprietary)

L2 TCP/IP Ethernet

Alarm/Event Printer *1 Report Printer *1

I/O
Supervisory A Supervisory B
L2
TCP/IP Ethernet

Moxa A Moxa B Measurement Network (proprietary)

NOTE: 1) For continuation of measurement network, see Figure J.1.

ECCN EAR99 DEP 32.32.00.12-Gen.
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Page 61

APPENDIX L FLOW COMPUTER DETAILED REQUIREMENTS

At a minimum, flow computers utilized for custody transfer measurements shall meet the
requirements of API MPMS 21.1.
Algorithms used for computations shall be performed as per the requirements of the
applicable measurement standards (4), (5)
In addition to these requirements, the flow computer shall be provided with non-settable
totalizers and be capable of archiving all custody transfer quantities in non-volatile memory
for the period of time specified on the custody transfer measurement data sheet.
The flow computer configuration shall be password protected.
All changes to the flow computer configuration shall be captured in an event log which is
date/time stamped and which details the ‘as found’ and ‘as left’ values.
The flow computer shall have a date/time stamped alarm log.
The flow computer shall have a configuration program for making changes to the flow
computer configuration. This software shall be capable of uploading a revised configuration
to the flow computer, downloading an existing configuration from the flow computer, making
on-line changes to the configuration and performing diagnostic functions and
troubleshooting. This software shall provide context sensitive “Help” screens.
The flow computer shall continuously monitor its health and provide warning and fault
alarms when problems are detected including loss of power.
The flow computer shall also monitor the values of secondary instruments and computer
values and provide a warning or alarm when these values fall outside of a predefined
range.
Flow integrators shall have sufficient digits so that rollover does not occur more frequently
than every 2000 hours at maximum flow.
Custody transfer flow data shall be automatically accumulated and stored for an agreed
period of time.
NOTE: The read-out of the flow computer is generally considered the last custody transfer element in the
custody transfer measurement chain. Data accrued from here is not usually subject to scrutiny by the
regulatory authorities.

The resolution of values presented on the visual display shall be sufficient to verify the
calculation accuracy.
It shall be possible to read the digital signal from the A/D converter as an
unscaled/uncompensated value, presented in a binary, hexadecimal or decimal form.
It shall be possible to read the pulses received from a meter directly (pulse transmission
check).
Flow computers shall accept the fault status of input devices but need not duplicate the
diagnostic functions of fit-for-purpose software associated with these devices.
Full documentation of the flow computer software shall be available providing the functional
design and the implementation of the package (e.g., for audit purposes).
The total error of the analogue to digital converter of the flow computer, including
resolution, linearity, repeatability and other random errors, shall not exceed ± 0.02 %.
Algorithm and unintentional rounding-off errors for computations of custody transfer
quantities in the flow computer shall be less than ± 0.001 %.
The flow computer shall be housed in accordance with the Manufacturer's
recommendations with respect to environmental conditions (temperature, vibration, etc.).
The flow computer firmware shall be subject to a regime of version control and be
identifiable by a unique version number.
The serial data transmission links shall be continuously monitored and an alarm generated
if faults are detected. The supervisory computer should be equipped with watchdog
ECCN EAR99 DEP 32.32.00.12-Gen.
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functionality to monitor the performance of data transfer between flow computer and
supervisory computer.
The custody transfer computing system shall have sufficient communication capability for
recording devices and alarm printers where required by legislation.
The flow computer shall provide ample recording and logging functions through a secure
communication facility to other systems (e.g., transmission of hourly or daily reports). The
following functions shall be provided by the flow computer system (if applicable):
a) storage of accumulated custody transfer quantities for each metering run and the
total metering system and an option to print these quantities;
b) alarm reports;
c) change logs,
d) monthly storage of measured parameters and accumulated quantities for each
metering run. An option to print-out such data;
e) communication facilities via VDU, printer and terminal.
The custody transfer supervisory computer shall, for each meter run, automatically log and
store at intervals of 1 h and 24 h: cumulative applicable quantities of mass, volume and
energy, and average values of pressure, temperature and density.
The retention time for storing these data shall comply with local regulations or the contract,
whichever is the longer.
The metering system shall be powered by an uninterruptible power supply (UPS); refer to
DEP 33.65.50.31-Gen. and DEP 33.65.50.32-Gen. Failure of the normal power supply and
UPS fault status shall be monitored and alarmed by the flow computer.
Additional back-up facilities in each computer shall ensure that custody transfer data are
not lost under any circumstances.
The flow computer response to changes of the metering system's secondary input signals
shall not be greater than 1 s.
The custody transfer measurement system shall be connected to the Process Control
Network (PCN) via the supervisory computer. There shall be no other connections between
the Custody Transfer Measurement Network and the Process Control Network.
The Supervisory computer shall include the capability (e.g., an OPC (OLE for Process
Control) server) to send the data to and from the data historian. The data historian shall be
the only location where users can get access to the custody transfer data.
Internal business users and applications shall not be able to directly access the supervisory
or custody transfer flow computers.
External business users, e.g., contract partners, shall only be able to access metering data
as remote users under a Third Party Access (TPA) agreement.
Manufacturers/Suppliers shall be able to access the Custody Transfer Measurement
Network for diagnostics and repairs only via a thin client in the Process Control Domain.
No modems shall be connected to the metering hardware and instrumentation.
Control and automation (C&A) maintainers shall be allowed access to the Custody Transfer
Measurement Network and hardware. The use of laptops and portable media shall be in
strict compliance with general PCD security requirements as per DEP 32.01.20.12-Gen.
ECCN EAR99 DEP 32.32.00.12-Gen.
February 2013
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APPENDIX M TYPICAL MULTI METER RUN WITH MASTER METER

FC FC FC

FE FT FE FT FE FT

PT PT PT

TT TT TT

TW TW TW

Master
Meter

SP AT