Procedure Guides for the Measurement of Quantity & Quality of Gas at Gas Plants, Refineries Copy

8/18/2019 Procedure Guides for the Measurement of Quantity & Quality of Gas at Gas Plants, Refineries Copy

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PROCEDURE GUIDES FOR THE MEASUREMENT OF QUANTITY AND QUALITY OF

GAS AT GAS PLANT, REFINERIES ETC.

INTRODUCTION.

This guide is issued pursuant to the provisions of section 7 (1) (a) of the Petroleum Act of 1960 and

Regulation 51 of the Petroleum (Drilling and Production) Regulations 1969.It specifies requirement and gives recommendation for the selection design installation, validationand maintenance of fiscal flow measurement station for gas.

PREFACE:This guide applies to the fiscal measurements of gas, which are executed in the petroleum industry

and provides for the DPR supervision of the activities described in this guide.

This guideline is not itself legally binding and it shall not constitute an obstacle to choosing othertechnical and operational solutions than those suggested in the guideline, provided documentation

are produced to show that the chosen solution fulfils the requirements of the procedure guide for the

system total uncertainty level.

When the guidelines refer to specific international standards, other standards with similar or more

stringent requirements for equipment or systems are not specifically mentioned, any mutually

agreed international standard might be used.

PURPOSE.

Fiscal gas metering systems are required for the purpose of achieving a consistent and cost effectiveapproach in gas fiscal metering or allocation and realising contractually agreed availability and

accuracy levels.

SECTIONThe procedure guide is divided into Two Parts, Part one enumerates the general operational

requirements expected of a gas metering systems in the Nigerian Petroleum Industry while Part

Two enumerates the technical requirements for the design of the metering systems.


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PART ONE.

CONTENT

1.0 SCOPE

2.0 DEFINITIONS

3.0 ABBREVIATIONS

4.0 CLASSES OF MEASUREMENT.

5.0 GENERAL REQUIREMENTS

6.0 COMPUTER PART

7.0 SAMPLING EQUIPMENT

8.0 OPERATING RANGE OF THE METERING SYSTEM.

9.0 UNIT OF MEASUREMENT

10.0 UNCERTAINTY

11.0 CALIBRATION

12.0 BY PASSING THE METERING SYSTEM.

16.0 GAS SAMPLER SYSTEMS

17.0 GAS CHROMATOGRAPH


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1.0 SCOPE

This procedure guide describes the operational/functional requirements for gas measurement

systems. Furthermore, the standard provides criteria for selection of such systems or maincomponents thereof, to ensure that allocation method, metering equipment and measurement

methods provide adequate accuracy and reliability at all times.

3.0 ABBREVIATIONS

NSI American National Standards Institute

GA American Gas Association

PI American Petroleum Institute

STM American Society for Testing and Materials

PM International Bureau of Weight and Measure

PR Department of Petroleum Resources.

AT Factory Acceptance Test

C Gas Chromatograph, (A device, which separates the components in a gas mixture

and measure them individually with a detector.)

C International Electro-technical Commission

Institute of Petroleum

PMM Institute of Petroleum, Petroleum Measurement Manual

O International Organisation for Standardisation

LC Multi Level Calibration. Calibration using several WGMs to either determine theuncertainty due to linearity of the GC for all components within actual range or to

determine the response curves of the detector of each component. MLC may only be

performed before installation or during commissioning.

PMS Manual of Petroleum Measurement Standard

GC On-line Gas Chromatograph, GC fed continuously and automatically with processgas.

PC Single Point Calibration. Calibration using only one WGM with concentration as

close as possible to the process gas or as close as necessary found by multi-level

calibration.

CD Thermal Conductivity Detector, most commonly used detector to measure the main

components in natural gas.

DU Visual Display Unit

GM Working Gas Mixture also called calibration gas, used for regular calibration of the

OGC. Normally prepared by gravimetric method and supplied with a certificate

listing the concentrations of all component and the uncertainty of the

concentrations.

3.0 DEFINITIONS

arrier gas Gas used to transport sample through the columns, normally Helium, Hydrogen ormixture of Helium and Hydrogen.

olumn Tubes inside the temperature controlled oven of the OGC packed with materialssuitable for separating the components of natural gas when flowing the sample using


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carrier gas.

scal quantity Measured quantity of hydrocarbons used for sale, custody transfer, ownership

allocation or calculation of royalty or tax.

GC Calibration Determination of the response of the detector for a given component with known

concentration given on the certificate of the calibration gas or comparing the reading

from OGC with values given on the certificate of the WGM.uantity Measure of the hydrocarbon medium, by volume, mass or energy.

4.0 CLASSES OF MEASUREMENTS.This describes categories of measurement on the basis of the meter location and the type of gas it

measures.

4.1 CLASS A MEASUREMENT.

The metering stations used for the delivery of gas to offshore customers and where sales contracts

are applicable. The DPR officer(s) shall witness and monitor the systems operations as applicable in

the oil terminals for the purpose of tax or royalty. The required overall measurement uncertainty

should be less than 1% on a volume basis or as specified in the contract.

4.2 CLASS B MEASUREMENT.

This is metering station for the delivery of gas in commonly used pipeline systems and where

allocation procedures or joint operating contracts apply. The DPR shall be notified on a weekly

basis the daily measurement record of the meter for the purpose of accountability. The DPR officerinvolvement in the system operations shall be intermittent, at least weekly. The required overall

measurement uncertainty should be less than 1.8% on a volume basis or as specified in the contract.

4.3 CLASS C MEASUREMENT.

This is metering stations for the delivery of fuel gas within the operator’s operating facilities or to

third party facilities. The uncertainty limit should not be greater than ± 2 % of standard volume. TheDPR involvement should be monthly i.e. the measurement records should be available to DPR on a

monthly basis.

4.4 CLASS D MEASUREMENT.

The Metering station for flare gas measurement and the uncertainty limit should be less than 5% ofstandard volume. If the flare gas releases is due to the operational upset, blowdown, purging, or

ESD operation the meter readings so recorded shall be forwarded within 24hours to the nearestoffice of DPR with a detailed report on the scenarios of the releases. This report shall form the basisof zero charges on the flare gas releases while charges shall be sustained if the flare releases are

operational philosophy.

Note: Any other uncertainty limit may be applicable for fiscal measurement systems if validated bya cost-benefit analysis performed and accepted by the DPR.


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5.0 GENERAL REQUIREMENTS

The measurement systems shall have a computer parts and a sampling system and the measurement

system, which fulfils the functional and technical requirements and has the lowest life cycle costshall be selected.

Measurement systems for hydrocarbon gas shall include all systems for:

Sales and allocation measurement of gas.

Measurement of fuel and flare gas.

Sampling and Measuring Gas component.

5.1 COMPUTER PART The computer part shall consist of a computer performing the functions specified below, a VDU, a printer for reporting, and a communication system for transferring signals to other systems.

Facilities shall be included to enable user verification of functions, parameters and accuracy

for input, calculated and output values. During the operational phase, the parameters relevant to verify the condition of the meter

shall be checked. If an alarm mode so indicates, the necessary verification and corrections

shall be done.

The computer shall raise and log alarms if any comparison checks exceed operator selected

limits, if any measured value is outside predetermined limits, and in case of indications ofinstrument failure or computer failure.

The computer shall report daily totals.

The computer part shall be capable of registering separately and independently of measured

quantities during calibration. Facilities to ease the calibration shall be included in the system

or offered as an option.

Algorithm and truncation/rounding errors for computations in the computer part shall be less

than ± 0.01 %.

6.0 GAS SAMPLER SYSTEMS.Automatic sampling equipment shall be installed. However, for dry gas, on-line gas chromatograph

should be used if they are found to be more cost-effective than automatic sampling and subsequentlaboratory analysis, and if required by any agreement.

Manual sampling point shall also be installed as a backup.

The system shall collect and store a representative gas sample at line conditions, allowing it to betransported to the laboratory for analysis. The system shall be mounted as close as possible to the

pipeline to collect samples over a sample period, unattended. The system shall be in accordance

with ISO 10715. The distance to the nearest upstream disturbance, shall be at least 20 ID.

The measurement system shall control an automatic gas sampler system, i.e.

Provide a flow proportional by mass pacing signal (and a fall back signal)

Monitor the sample volume collected and status of the sampling system.


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In addition, there shall be a manual sample point, where the manual sampling probe shall be

installed such that a representative sample of the gas can be collected. The distance to the nearest

upstream disturbance, shall be at least 20 ID. However, if an auto-sampler or OGC sampling probeis included in the measurement system the manual sampling may be taken from the same probe.

6.1 Equipment/Schematic The system consists of a probe, a by-pass loop, two separating devices (sample collection pumps),an instrumentation supply system, a timing system and two sample receivers (collection cylinders)

for sample transportation.

The sample equipment shall be contained in a cabinet with exception for:

The probe,

Tubing to/from the mainline and

The back-pressure system.

The manual sample point shall be equipped with flushing facilities and a cabinet/enclosure with

required valves and quick connectors in addition to an arrangement where the sample cylinder can

be placed during spot sampling.

6.2 PerformanceISO 10715 describes the performance requirements for a fiscal sampling system.

6.3 Operational Requirements The control function shall be done from a dedicated controller, SAS or a measurement system.

There shall be monitoring of maximum filling with adjustable alarm setting. In addition the

measurement system shall provide a flow proportional pacing signal and monitor the samplevolume collected and status of the sampling system.

6.4 Isolating and Sectioning It shall be possible to isolate the system from the main process.

6.5 Layout Requirements ISO 10715 describes the layout requirements for a fiscal sampling system.

6.6 Technical requirements The sample point shall be chosen to provide a representative sample of the flowing gas in the pipe.The sampling point shall be installed at least 20 diameters downstream of the nearest bend or

restriction on a horizontal pipe. The probe shall be installed in a 10 - 2 o'clock position.

6.7 Probe design The probe shall be a pilot tube type extending into the centre one-third of the pipeline diameter. In

addition, the sampling probe should be possible to retract under operating pressure by method

accepted by the operator.

6.8 Sample collection pump There shall be two parallel sample collection pumps, which shall be self-purging and can operate

under line conditions. The grab size volume shall be adjustable in the range 0.5 – 1.5 ml.


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The sample collection pumps shall be located above and as close to the probe as is practically and

possible. Filters, drip pots, screens, regulators and such conditioning equipment shall not be placed

between the probe and the sampler.

6.9 Sample Receiver.

Heat tracing and insulation shall be provided to keep the temperature minimum 10 ° C abovethe condensation temperature.

The receivers shall be of the floating piston type with back-pressure of an inert gas.

The receivers shall be equipped with a local piston position indicator and a limit switch for

maximum filling.

6.10 Tubing and valves.

The temperature in all parts of the sample lines/tubing and sample receivers shall be kept ata temperature minimum 10 ° C above the hydrocarbon dew point temperature.

The valves for the sampling system shall be of type full-bore ball valves.

The sample tubing from/to the main pipe should have a slope of at least 1:12 to avoid liquidtraps.

6.11 Back-pressure system There shall be a back-pressure system with inert gas (argon or helium). This shall include a booster

facility. The back-pressure volume shall be at least five times larger than the receiver volume and ofa size so that the pressure increase caused by 100% sample filling is less than 10 bar.

7.0 GAS CHROMATOGRAPH The purpose of an on-line gas chromatograph (OGC) is to give continuous quantitative composition

analysis of gas from a process stream. The ranges shall be restricted to the operational needs for

each project.The OGC shall quantify the concentrations of the main components in the gas composition, for the

purpose of gas accounting, calculation of calorific value and reference density in fiscal applications.

The gas composition shall also be used for check of gas quality conformity with gas quality

specifications defined by commercial gas agreements.

The sampling system shall ensure that the sample to the OGC is representative for the process

stream and suitable for the OGC. Recommendations as specified in this document, by the analyzersupplier and in the ISO 10715 "Natural gas - Sampling guidelines" shall be followed.

The shortest practical sampling route between sampling point and analyzer should be taken.

Calculation of the transport time from sample point to the gas chromatograph shall be presented.

The effect that the sum of the transport time and the analysis cycle time could have on daily averageanalysis shall be evaluated.

7.1 Analytical unitThe analytical unit shall separate all components sufficiently from each other so all components

present in the process gas are detected with sufficient accuracy. Special care shall be taken to check

that the separation between nitrogen / carbon dioxide and methane and between hexane and n- pentane are handled by the gas chromatograph.


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7.2 Computer unit

The computer unit shall control the chromatograph. Program software, interfaces and protocolshould be robust with special consideration concerning automatic regeneration of all control and

communicational functions after the event of a general power failure.

Criteria for accepting the results from the calibration sequence shall be implemented.The computer unit shall have the option of selecting an automatic calibration performed between acertain numbers of analyses, or executed at selected calendar dates or weekdays, or at a specified

time during the day.

The computer system shall be capable of calculating the following figures based on thecompositional data normalized values Xi in accordance with ISO 6976.

Compressibility factor at reference condition.

Gross calorific value.

Wobbe-index.

Relative density (real / ideal)

Density at reference condition.

Algorithm and truncated/rounding errors for computations in the computer unit shall be less than

± 0.001 %.

7.3 Calibration equipment.

The calibrated gas shall be permanently connected to the analytical unit. The system shall have avalve arrangement that provides the possibility of automatically selecting gas samples from the

WGMs. Selection of WGMs shall be possible from the central control unit.

Each of the components in the calibrated gases (WGM) used for either acceptance tests,

commissioning or during operation shall have the following documented uncertainty limits

(extended uncertainty with a coverage factor k=2):

Component range (mole %) Uncertainty (%)

0.1 – 0.25 5.00

0.25 – 1 1.00

1 – 10 0.5

10 – 100 0.2


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7.4 PerformanceThe repeatability of the OGC shall be within the following limits:

Component range (mole %) Standard deviation (mole %)

0

25

-

-

25

100

0.02

0.05

The linearity of each component, tested in accordance with Annex B 2.3.4, shall be so that themaximum deviation from values of any WGM when performing a MLC after adjustment of the

OGC to correct reading after a SPC shall be so low that the resulting uncertainty in gross calorific

value, UHs, is less than 0.15 % of the gross calorific value, Hs, when applying the following

equation:

UHs = [ (Hs - Hsi)2× (UXi)

2]1/2

Where Hsi is the gross calorific value for each component found in the ISO 6976.

7.5 Availability and reliability

The system shall be designed for continuous operation and for low downtime in case ofmaintenance, repair etc.

To increase the reliability of the results it should be possible to check the results from the OGC by

other independent means. Such means may be another OGC installed in parallel, analytical

equipment installed at other locations with which it is possible to compare the results, equipmentmeasuring properties, which are dependent on the gas composition.

7.6 Process/Ambient conditions The OGC should be kept under sufficient controlled environment, i.e. providing necessary

protection against heat, rain, wind etc.

Line pressure variations shall not affect the sample flow rate and pressure of the sample gas to the

analyser.

7.7 Analytical unit The time required for a full analysis cycle shall be less than 15 minutes.The oven temperature shall be controlled with sufficient stability and accuracy to obtain required

stability and accuracy of the analysis.

The chromatograph shall use carrier gas in accordance with requirement given by the application.

Pressure and flow rate of carrier gas shall be controlled with sufficient accuracy. Necessaryequipment for safe operation in case of failure in carrier gas supply shall be installed if applicable.

7.8 Computer unit Communications between the analytical unit and the computer unit should be according to the

vendor's standard protocol.


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The following functions shall all be available for the operator and should also be available from the

supervisory computer:

Start and stop the analysis cycle

Change the alarm limits.

Acknowledge alarms. Define and / or read component table, retention time, RT tolerance, response factor and

valve switching.

Sequence calibration frequency and WGM concentration.

Password protected program modifications.

Define and / or read time, peak height, peak area, peak start time, peak end time (for each

component) and total area.

Select override analysis.

A main report for printouts and electronic transmission to the main network shall contain names of

components, normalised mole % of each component rounded to the nearest 0.001%.

A quality control report for printouts and electronic transmission should contain information aboutretention time, peak height, peak width, peak area, response factor, and mole % before and after

normalisation.

A control function in the software should give alarm if one or more components are missing from

the report or that the sum of non-normalised values is outside pre-set limits. This alarm shall inhibit

the transmission of potential erroneous results onto the main computer network.

The following requirements for displaying items should be considered:

Alarm status

Historical analysis data for a single component in chart form

Historical analysis data in report format, average, maximum and minimum values for each

component and calculated values

The last measured concentration value for each component and calculated values

Real time chromatogram and valve status.

8.0 BY PASSING THE METERING SYSTEM.By passing of the metering system is not permitted. The design and construction of by-pass line

shall be in place but shall never be issued without the DPR written approval.

If operating conditions or problems make it necessary to by-pass the metering station, the licenseeshall apply for permission for such an operation.

When loading LPG in small batches, it is mandatory due to variations in loading rates to install a by

pass loop for re-circulation.


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9.0 SALES AND ALLOCATION MEASUREMENT The measurement system shall measure gas flow rates and accumulated quantities. Where

applicable approval by the DPR is required for the measurement systems and shall monitor thesystems’ operations as applicable to crude oil measurement systems in the oil ter minals.

9.1 Performance.The measurement system shall be capable of measuring the full range of planned quantities of

hydrocarbon gas through the measurement systems. The flow rate in each meter run shall not

exceed limit. Note: One spare meter run shall be required for a multi-run metering station.

9.2 Process/Ambient Conditions Refer to process data sheet (Project specific).

9.3 UNIT OF MEASUREMENT

All systems shall give readings and reporting in SI-units according to ISO 1000, except for pressure

and differential pressure where the units bar and mbar shall be used respectively.

The normal reference condition is defined as 0 °C, 1.01325 bar absolute.

For calculation of Gross Calorific value and Wobbe Index [MJ/Nm3] the normal reference

condition shall be used in addition to combustion temperature of 25 °C and metering temperature of

0 °C.

For system concepts with no system specific requirements in this procedure guide, the design shall

to the greatest possible extent, be based on (in order of priority):

International standards, preferably ISO.

The manufacturer's recommendations.9.4 UNCERTAINTYThe uncertainty is given in standard volume, but other units may be requested (project specific) e.g.

mass energy etc.

Any other uncertainty limit may be applicable for fiscal measurement systems if validated by acost-benefit analysis performed and accepted by the operator/DPR.

9.5 CALIBRATION All parts of the metering system, including shut off valves for the hydrocarbon flow to the system,

shall be easily accessible such that checks or calibrations can be carried out without difficulty.

Locations where checks and calibration take place shall be protected in some way against

environment influences and vibrations such that the requirements stipulated in these guides can befulfilled.

An accredited laboratory to International/National Standards shall traceably calibrate all instruments

and field variables used for fiscal calculations or comparison with fiscal figures.

If it is impossible to calibrate the meter at the relevant process conditions, the meter shall at least be

calibrated for the specified flow velocity range.


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In calibration mode, the flow time shall be registered and displayed by the flow computer/computer

system.

10.0 OPERATIONAL REQUIREMENTS.The measurement system shall be operated from the computer part. The measurement system shall

also be operable from Safety and Automation System (SAS.)It shall be possible to measure the gas flow and accumulate even if the supervisory computer fails

completely. It shall be possible to operate all valves locally.

Continuity is required in measurement of the gas flow, during regular calibration of the fieldinstruments and whenever a field instrument of any type fails.

10.1 Measurement systems with multiple meter runs. In automatic mode, the measurement system shall control open or close meter runs that are inservice mode, as required by the amount of gas flow being measured.

The meter runs inlet valves shall be manually operated (i.e. shall not be part of the automatic

operation). Optionally these valves may only be locally operated (project specific). The closing of

the last open meter run shall only be possible in manual mode.

11.0 MAINTENANCE REQUIREMENTS. The field instrumentation should be chosen to ensure long maintenance and calibration intervals. In

addition, it should be easy to retrofit the instruments and flow elements for maintenance.

It shall be possible to calibrate all instruments and separate components in the electronic loop eitherwithout moving them from their permanent installations and without disconnecting any cables, or

by using transmitters fitted with quick connectors (for removal for calibration/ maintenance). An

exception to this will be a flow meter that requires off-line calibration.

There shall be easy access to any part that required regular calibration and maintenance.It shall be possible to maintain the mechanical part of the system without dismantling the manifolds

(or similar).

The software shall provide means of calling up live transducer values (one at a time) onto the

operator workstation for purpose of calibration. The input shall be displayed in engineering units.Input shall be displayed on VDU with the same time period as read by the input/output system i.e.

no average.

11.0 TECHNICAL REQUIREMENTS

11.1 Interface Requirements Computer part shall interfaces with:

If dedicated computer: SAS.

Sampling system and/or On-line gas chromatograph.

Production database and allocation systems.

The remaining interfaces, if any, are application specific, (e.g. Water dew point, Hydrocarbon dew

point, and Hydrogen sulphide (H2S).


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The requirements below are only relevant if the specified component is part of the measurement

concept.

11.2 Sizing

The measurement system shall be designed to measure any expected flow rate with the metersoperating within 80% of their standard range (not extended).

11.3 Meter runs pressure setting/equalizing.

Each meter run shall have:

A connection to flare for depressurising the meter run,

A connection for nitrogen purging and

A small bore by-pass across the inlet or outlet valve for pressure setting/equalising the meter

run.

11.4 Block valves

The meter runs inlet and outlet valve shall be of double block and bleed type. The valve balls shall be mounted, and independent up and downstream seals and firesafe. The valve shall be equipped

with a body vent and the leakage control shall be by automatic or manual monitoring.Outlet On/Off valves at multiple meter runs shall be equipped with automatically operated actuators

with failsafe "stay in position". Flow direction shall be clearly stated on valve bodies.

11.5 Vent systems

The system shall have vent system with single connection at system limit. Double block and bleed

valve arrangement in the vent lines.

11.6 Location of sensors

Pressure and temperature shall be measured in each of the meter runs. Density shall be measured byat least two densitometers in the metering station. The density measurement device shall be installed

so that representative measurements are achieved. Pressure and temperature measurement shall be

measured as close as possible to the density measurement.

11.7 Instrument panel and supplies

The electrical supply for field instrumentation used for fiscal measurement systems shall be

powered from instrument panels. The instrument panels shall be supplied from UPS. All flow passing a fiscal measurement system shall be measured. The power supplies to the measurement

system shall be designed for this operation philosophy.

11.8 Signal TypesFor measurement systems instrument field bus/digital communication shall be entirely implemented

i.e. so it can be utilised for diagnostic purposes. All transmitters shall be of smart type where

available.


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11.9 Stability for smart transmittersFor smart pressure and smart differential pressure transmitters the stability shall be equal or better

than ± 0.1% of upper range limit for 12 months. For smart temperature transmitters the stability

shall be equal or better than ± 0.1oC for 24 months.

11.10 Temperature loop

For fiscal measurement applications the smart temperature transmitter and Pt-100 element should be

two separate devices where the temperature transmitter shall be installed in an instrument enclosureconnected to the Pt-100 element via a 4-wire system. Alternatively, the Pt-100 element and

temperature transmitter may be installed as one unit where the temperature transmitter is head

mounted onto the Pt-100 element (4- or 3-wire system).

11.11 Direct density measurement.Continuous measurement of density is required. The gas shall at the density measurement point be

in a measurable form i.e. well above the hydrocarbon dew point. The density shall be measured by

the vibrating element technique. Density calculation and calibration shall be in accordance withcompany practice. The density shall be corrected to the conditions at the fiscal measurement point.

There shall be direct transmission of transducer pulses/frequency signal to the computer part or viasmart communication. If the density is of the by-pass type temperature compensation shall be

applied.

The uncertainty (expanded uncertainty with a coverage factor k=2) of the complete density circuit,

including drift between calibrations shall not exceed ± 0.30% of measured value.

11.12 Calculated density.

Calculated density shall be by AGA 8, detailed characterization method or ISO 12213-2. When an

OGC is a part of the fiscal measurement system, composition data from this unit shall automatically

be used in the standard and line/operating density calculation. However, if the OGC is not a part ofthe fiscal measurement system, operator entered composition data shall be used.

11.12 Differential pressure transmitter.

Smart differential pressure transmitters for orifice measurement systems shall be installed in parallel

for mutual surveillance i.e. if the duty transmitter fail the host stand-by shall be used automaticallyuntil the duty transmitter is repaired.

11.13 Local indicators.

Where local indicators are required, local indicators on the smart transmitters can be used as

alternative to local gauges.

11.14 Local pressure indication.For meter tubes/runs, which require pressure or depressurisation system for maintenance purposes,

a local indication of pressure shall be installed on the high-pressure side.


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11.15 Instrument ball valves. For fiscal measurement applications, ball valve manifold block or an assembly of discrete

components ball valves shall be applied. Final valve arrangement shall be installed in instrumentenclosure and be service friendly. In general, the valves shall not be less than 9 mm full bore,

however the equalizer valves and test valve may be 4 mm bore. The test port shall be equipped with

quick connector.

11.16 Instrument tubing.For fiscal measurement systems the instrument impulse tubing shall not be less than 9 mm ID. The

tubing length should be kept as short as possible.The slope of the impulse lines should be no less than 1:12. All instrument tubing shall be installed

so that "liquid traps" are avoided.

Instrument tubing for differential pressure transmitters should be kept symmetrical with respect to

pipe/instrument interface, where tubing diameter changes and isolation valves are installed.

11.17 Computer design.

The software for calculation of fiscal quantities shall be stored in a secure and resident manner.Reference is made to ISO 9000-3.

Version number shall identify the present software program version(s). Change of version number

shall be implemented every time permanent program data is altered. It shall be possible to

determine the present program version directly from VDU and/or printouts.The update time shall be less than 2 seconds for the VDU update and the resolution shall be

sufficient to verify the requirement for calculation accuracy.

Change of fiscal day will be project specific e.g. 00:00 or 06:00 each day.

12.0 PROCESS OPERATOR INTERFACE.The process operator interface shall, as a minimum comprises:

Graphic user interface.

Meter run control.

Security control of operator entered parameters.

The graphic user interface shall include a simplified P&ID with process variables and valve status.

It shall be possible to operate all valves from the graphics.

12.1 Computer system interface.The computer system (supervisory) interface shall as a minimum comprise:

Graphic user interface.

Meter run control. Security control of operator entered parameters.

System monitoring.

Trouble shooting.

Software updates.

Tape drive and / or CD-ROM.


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The graphic user interface shall include a simplified P&ID with process variables and valve status.

It shall be possible to operate all valves from the graphics.

13.0 CALCULATIONS.The computer shall calculate flow rates and accumulated quantities for

i) Actual volume flow,ii) Standard volume flow,

iii) Mass flow and

iv) Energy flow (application specific).

All calculations shall be performed to full computer accuracy. (No additional truncation or

rounding.)

The interval between each cycle for computation of instantaneous flow shall be less than 10seconds.

Where the interval between the calculations extends over several updates of input data, the mean

value of input data shall be used in the computations.

The mean values for density and differential pressure shall be calculated from square roots of thefield values.

The iteration procedure shall ensure that a new iteration of flow coefficient is carried out if the

difference between the two last flow coefficient computations exceeds ten to the power of minusfive (0.00001).

Algorithm and truncation/rounding errors for computations in the computer part shall be less than

+ 0.001%. This requirement shall be verifiable.The computer part shall include electronic means for storing accumulated fiscal quantities for each

meter run and the total measurement system. These figures shall also be stored in back up files. The

figures shall be stored for the time period that is regarded as necessary. The files shall be secured in

such a way that they cannot be zeroed or altered unless a special security method is followed.

Calculation of Gross Calorific value (superior) and Wobbe index shall be done according to ISO6976 with a combustion temperature of 25 ° C and metering temperature of 0 ° C.

Calculation of all required values for reports and VDU shall be implemented:

Hourly and daily totals and maintenance mode totals,

Average flow rates,

Average K-factors and process values all average values shall be flow-weighted by mass.

The resolution on the VDU shall be sufficient to verify the requirements for calculation accuracy.

14.0 CHECK.

Comparisons shall be implemented between duplicated instruments measuring the same processvalue. Comparisons shall also be implemented between instruments measuring the same process

value in different meter runs. Comparisons shall be based on values averaged over a moving time

window to be operator selectable between wide intervals (that is from 1 second to 10 minutes).Facilities shall be included to enable user verification of functions, parameters and accuracy for

input values, calculated values and output values.


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14.1 AlarmsThe alarm system shall raise alarms, print out alarms and/or save alarms to external file, if any

comparison check exceeds operator selected limits or if any measured value is outside predetermined limits or in case of indication of instrument failure, computer failure or failure in

valve operation.

The alarm system shall be designed in a flexible way, fulfilling as a minimum the followingrequirements:

For all alarms it shall be possible, under password/key-switch protection,

- to suppress or enable the alarm and

- apply time delay for filtering purposes.

A list of all suppressed alarms shall be available on screen and printer and external file.

Grouping of alarms shall be considered in order to reduce the number of alarms to aminimum.

Hardware and software watchdog alarm shall be implemented.

14.2 Events.The system shall log all events as a result of system or operator action to external file and printer.

The events shall include manually entered parameters on the computer part that may be changed byan operator.

15.0 REPORTING OF DATA.The computer shall generate quantity reports containing as a minimum:

Current flow rates and process values,

All totals, and

Average K-factors and process values all average values shall be flow-weighted by mass.

Reports for the following intervals shall be available: current status (no average values), hourly anddaily.

The reports shall also contain gas quality parameters as measured by on-line equipment or manually

entered.

The reports above shall be printed automatically but it shall also be possible to suppress the printingof the reports. The reports shall also on request be shown on VDU. When fixed values or fallback

values are used instead of the live signals sometime during the report interval, this shall be visually

identified on the print out and on the VDU.

The reported data shall be for each meter run and with totals for the measurement system.If the reporting computer is down across change of hour or day, the quantities thus not reported for

the expected time period shall be automatically recovered and reported with the first report that isgenerated when the computer comes back in service.

15.1 Storing of data.

Hourly reports to be stored to computer file for 60 days, daily reports for 1 year.All measured and calculated values averaged over the moving time windows shall be stored in

computer file for 60 days.

Alarm and event reports to be stored to computer file for 30 days.


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15.2 Availability.

The computer shall have fault tolerant design to maintain fiscal measurement, calculations and filestorage during error conditions.

The computer part shall be capable of operating in such a way that maximum gas flow can be

measured even if failures occur within any level of the computer part.The availability of the fiscal computer system shall be documented and better then 99.7%availability.

16.0 NETWORK PROTECTION/SECURITY.If the flow computers or supervisory computer(s) are connected to a network appropriate security

and protection shall be applied, i.e. only dedicated computers shall have access to the measurement

computers. Network communication shall utilize a protocol where protection and security is a part

of the protocol. Recognized standards are ISO IEC 3309.The algorithms and fixed parameters important for accurate computation of fiscal quantities shall be

secured in a way that makes direct access impossible, unless an established security routine is

followed. There shall be protection against un-authorized data entry by password or key switch.

16.1 Expandability.

For future computer expandability a maximum limit at maximum load to the following computer

parts shall be:

The software, including programs and data shall not occupy for more than a maximum 50%of the computer memory, at any time.

No more than 50% of the computer disk capacity shall be utilised.

The system, application and communication software shall require less than 50% of the CPU

capacity.

Input data from the field must be equipped to handle 25% extra points. The system must be able to handle 25% extra flow per station or flow computers.

16.2 Automatic restart.The system must be capable of an orderly shutdown in the event of a total power failure or major

transient. Restart after power failure shall be automatic and shall include restart for all features,devices and programs, including correct time from a radio clock, or a battery backed up calendar

clock.

16.3 Background Compilation and Execute Capability.The system shall have the capability for program compilation and execution in a background mode

without disturbing the continuous functions operating in the foreground. It must be possible to build, replace, and initiate foreground tasks without interrupting other system functions.

17.0 FUEL GAS MEASUREMENT. For single meter run configuration, it shall be possible to route the gas stream through a by pass linefor inspection and maintenance of the fuel meter run. When the system is in this bypass mode, flow

calculations shall continue based on average flow rate in a user selectable time periods (that is from

one minute to one hour) prior to opening to by pass.


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Orifice meter should be preferred to gas turbine meter unless the cost of long upstream meter run

lengths for the orifice meter outweighs the cost of annual flow calibrations at operating conditionsof the gas turbine meter, and the cost of one spare gas turbine meter (in stores).

Also, a gas turbine meter should be preferred if the flow range of the fuel stream requires frequent

changes of orifice plates during regular operation.For every small fuel gas streams, in particular non-fuel streams withdrawn from the fuel distributionsystem downstream of the main fuel metering system, the following methods should be considered:

For gas streams withdrawn manually at intervals: No meter, just estimation.

For continuous streams smaller than specified by ISO 5167 and AGA 7, one of the

following methods shall be used:- Small, full bore, gas turbine meters, designed to manufacturer’s standard (minimum 6

mm).

- Integral orifice meters (smaller than 12 mm).

- Other suitable type of small flow meter with equivalent accuracy.

18.0 FLARE GAS MEASUREMENT.

The system shall measure flow rate and accumulate quantities of flare gas, in accordance with the

following guides. The calculation can either be done in a dedicated flow computer or in SAS.If the flare gas releases is due to the operational upset, blow-down, purging, or ESD operation the

meter readings so recorded shall be forwarded within 24hours to the DPR nearest office with a

detailed report on the scenarios of releases. This report shall form the basis of no charge on the flaregas releases. If the flare releases are operational philosophy the meter reading shall comply with

fuel gas measurement systems and all the conditions attached thereof.


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PART TWO

1.0 SCOPE

2.0 DEFINITIONS

3.0 METER SELECTION CRITERIA

4.0 APPLICATION FOR LICENCES, DOCUMENTATION AND

INFORMATION.

5.0 MANAGEMENT SYSTEM

6.0 UNCERTAINTY ANALYSIS.

7.0 CALIBRATION

8.0 REFERENCE CONDITIONS.

9.0 DESIGN OF THE MECHANICAL PART OF THE METERING SYSTEM.

10.0 REQUIREMENTS FOR THE ISOLATION VALVES.

11.0 REQUIREMENTS FOR THE FLOW METER

12.0 REQUIREMENT FOR THE FLOW PROFILE

13.0 LOCATION OF SENSORS

14.0 DESIGN OF THE INSRUMENT PART OF THE METERING SYSTEM.

15.0 GENERAL REQUIREMENTS FOR THE INSTRUMENT LOOPS.

16.0 INSTALLATION OF MONITORING INSTRUMENTS.

17.0 SAMPLING EQUIPMENT.

18.0 DESIGN OF THE COMPUTER PART OF THE METERING SYSTEM.

19.0 SECURITY AGAINST ERRORS AND LOST OF DATA.

20.0 PRINT OUT AND AUTOMATIC LOGGING.

21.0 POWER SUPPLY TO THE METERING SYSTEM


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(B) TESTING, CALIBRATION AND COMMISSIONING OF THE METERING SYSTEM

PRIOR TO START-UP.

1.0 GENERAL

2.0 TESTING OF THE COMPUTER PART

3.0 CALIBRATION OF THE TURBINE METER

4.0 CALIBRATION OF THE TRANSDUCERS

5.0 INSPECTION OF THE SIGNAL TRANSMISSION FROM THE TRANSDUCERS TO

THE COMPUTER.

(C) TESTING AND COMMISSIONING

1.0 NECESSARY TESTS

2.0 TEST OF INDIVIDUAL COMPONENTS

1.0 SCOPE

The guide is applicable to planning, design and construction and maintenance of metering stations

for measurement of produced/sold quantities of gas by quantity determination for tariff purposes,and to allocation system based on figures from fiscal metering stations.

2.0 DEFINITIONSFor the purpose of this guide, the following definitions shall apply.

Recognised standard:

Guidelines, Standards or similar documents, which within a technical field are nationallyinternational recognised. Also, Acts or Regulations, which are not directly applicable but which,

regulate corresponding or neighbouring areas of activity.

Area of application:Any installation, a Subsea installation or a terminal owned by oil operator or Gas consumers whereGas metering system is in operation.

Place of Manufacture:

Factory or a workshop where one or more of the measurement system’s main parts are fabricated orconstructed.

Datafile:Groups of data, stored in an electronic unit.

Computer part:


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The part of the measurement system, which comprises of digital computers and receives digital

metering signals from A/D converters or from digital instrument loops.

Computer for administrative routines:Computer connected to one or more flow calculation computers. Information from the flow

calculation computers may be further processed for reporting purposes. Information may betransferred from the administrative computer to the flow calculation device. The administrative unitmay include long and short-term data storage facilities.

Flow computer:A computer performing flow calculations connected to one or more instruments and/or devices for

collecting and distribution of signals. The storage unit (memory), which is providing long and short-

term retention of data is regarded as an integral part of the flow computer.

The devices and equipment error:Quantifiable amount incorrectly measured, due to the fact that the accepted procedures for operation

or calibration are not followed.

Fiscal metering station: Assembly of metering equipment dedicated to the determination of fiscal quantities.

Gas:Hydrocarbons in gaseous state at measurement conditions.

Sensing element:

A device, which acts directly on the condition it, shall measure and produces a signal proportional

to a physical condition.

Instrument part:

The part of the metering system which is located between the mechanical part and the computer parti.e. from sensing element to digital input of the computer part inclusive.

Calibration:

Establish relationship between the input and output signal for a device.

Calibration factor:

Relationship between measure value coming from a flow meter and the measured value from areference measurement system.

Calibration mode:

selectable condition within the flow computer where routine checks and calibrations can be carriedout, whilst the associated meter tubes are closed.

LinearityA relation between conditions where a change in one causes a proportional change for the other.

Mechanical part:


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Meter tube, turbine meter, meter prover and all mechanical devices that are included in gas metering

system.

Metering tubeStraight pipe sections where a flow meter is installed.

Instrument Loop: The assembly of all devices and data links from the sensing element to the visual indication in thecomputer part of the metering system.

Metering system: Includes mechanical part, instrument part and computer part.

Transmitter:

Technical device, which change the nature of the measured signal.

Resolution:

The least variation in signal level, which produces a noticeable change in the displayed value.

Flow meter:

Equipment located in or clamped to a pipe and its signal transformer, to provide a primary signal

proportional to the amount of flow through the pipe.

Thermowell:

A well in the meter tube for installation of a thermometer.

Calibration factor for turbine meter:

A number that indicates the ratio between the readings of the turbine meter and the volume

throughput. The term is used to cover both the terms “meter factor” and the “K -factor”.

Uncertainty in measurement:

An estimate characterising the range within which the measured value will be found. In these guidethis is at 95 percent confidence level, K= 2.

Positive displacement.Meters with well defined measurement compartments that alternately fill and empty as the meter

rotates. Knowing the volume displaced in each meter revolution and by applying the proper gear

ratio, the meter will read directly.

Inferential metersAre meters with no measurement compartments to trap and then release the gas. These meters are

categorised as inferential meters in that the volume passed through them is “inferred” by something

else observed or measured.

Therefore the following subjects should be agreed in the contract:

1. The quantity delivered to be specified as mass, volume or energy and the reference


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conditions for such quantities.

2. The measurement concept including redundancy aspects. Avoid measurement conceptsusing moving/rotating parts, which are vulnerable to process upsets and resulting

liquid/solid breakthrough.

3. Witnessing of the commissioning, verification and calibration of the measurementinstallation by buyers and, where relevant, other parties.

4. Approach to recovery of measurement deviations and interruptions (e.g. estimating thedelivered amount of gas by averaging over time between last valid value before

interruption and first valid value after repair). To be detailed in the measurement

manual.

5. Information about the calculation of delivered quantities, and the verification, recovery

procedures, calibration and maintenance of the measuring station.

6. The application of a “black and white” list per project regarding the determination of the gas

quality. Normally two kinds of properties are distinguished: fiscal properties and limit properties.

The list provides the (white) properties that can be measured or determined via agreed proven and

(internationally) standardised methods and the (black) properties for which measurement ordetermination, and any new issues, have to be agreed on a case-by-case basis.

7. Possible exchange of (real time) process values (pressure, flow rate, quality etc.) between parties.

8. The (international) standards applicable. Newly published standards or revisions of

existing standards shall only be adopted when mutually agreed.

TURBINE METERS.

Meters that use gas velocity to spin a turbine wheel and the higher the rate of flow, the faster thespin, therefore registering higher volume on the index over a given period of time. Gas moving

through the meter impinges on a bladed rotor resulting in a rotational speed that is proportional to

the flow rate. The volume is determined by counting the number of meter rotations. The volume ofgas passed through the meter, at the operating pressure and temperature, is indicated on a counter in

units of volume.

Gas flow measurement for custody transfer by means of turbine meters shall be inaccordance with ISO 9951. Turbine meters should not be used where frequently interrupted and/or

strongly fluctuating flow or pressure pulsations are present.

For each turbine meter a (weights and measures) certificate of the calibration at a high(line) pressure shall be available. The calibration data stated in the certificate shall include the error

of the meter for at least 6 points over the whole range of the meter according to ISO 9951.

The contractual availability of gas flow may require a station by-pass which, shall be


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The temperature of the gas shall be measured downstream of the primary element, to avoid flow

profile distortion. The thermowell or pocket shall take up as little space as possible.The thermowell shall be situated minimally 5D and maximally 15D downstream of the

primary element and in accordance with the values given in ISO 5167-1 if the pocket is

located upstream. The temperature measurement shall not be influenced by heat transferfrom the piping or thermowell attachment.It may generally be assumed that the downstream and upstream temperatures of the fluid

at the differential pressure tappings are the same within the limits of application of ISO

5167-1. However, if the highest accuracy is required and there is a large pressure loss between the upstream pressure tapping and the temperature location downstream of the

primary device, then it is necessary to calculate the upstream temperature from the

downstream temperature (measured at the above distance from the primary device),

assuming an isenthalpic expansion between the two points.

2.5.4 On-line computation of the flow rate

The flow rate shall be calculated according to ISO 5167-1, using equipment approved bythe parties and by the local authorities (e.g. weights and measures). For the on-line

computation of the flow rate, fixed values may be used for the kinematic viscosity ( ) and the

isentropic exponent ( ), based on the average operating conditions. The calculation of the Reynolds

number (Re) shall be based on the actual flow rate.The energy flow is determined from the product of the volume flow or mass flow and the

corresponding Gross Heating Value, both expressed at the same reference conditions.

ULTRANSONIC GAS FLOW METERS. A meter with at least two independent acoustic paths used to measure transient time difference of

sound travelling upstream and downstream. A meter that has a numerical data values for minimum,

maximum and transition flow rates of which the maximum value is at least ten times greater thanthe transition flow rates.

13.4.5 Layout Requirements Sufficient upstream and downstream length of pipe shall be installed.

Ultrasonic flow meters shall not be installed in the vicinity of pressure reduction systems (valves

etc.), which may affect the signals.

A meter of maximum allowable error of +/- 0.7% for large meters and +/- 1.0% for small meters

and repeatability of +/- 0.2% for the higher velocity range and is doubled for the lower.

Refer to ISO/TR 12765 and AGA-9.

General

Measurement of gas flow for custody transfer by means of multi-path ultrasonic flow meters shall

be subject to approval by the contract parties and/or authorities for each individual application.Exemption by authorities (e.g. weights and measures) is often required for the use of ultrasonic flow

meters.

The ultrasonic flow meter shall have a locally approved certificate of calibration in


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accordance with the Manufacturer's procedures. A certificate of the calibration of the

ultrasonic flow meter at operating pressure shall only be produced if required by parties

involved. The calibration data provided in the certificate shall include the error of the meter for atleast 6 points over the whole range of the meter according to ISO 9951. The

monitoring facilities available in modern ultrasonic meters shall be used for health checking

(transducer performance/malfunctioning, meter pollution), to enable early detection of imminentmalfunction of the meter.

2.4.2 Design capacity

The design capacity of the flow measuring station (with one or more meter runs) is the

maximum flow rate that can be measured. This is the sum of the flow rates of the non-spare meterruns, provided that one ultrasonic meter indicates the maximum continuous flow rate at which its

uncertainty (2 sigma) remains within design specifications, or the gas velocity has reached its

maximum allowed safety level.

The minimum flow of the flow measuring station is the flow rate of the smallest meter run,

provided that one ultrasonic meter indicates the minimum continuous flow rate at which its

uncertainty (2 sigma) remains within design specifications. If an ultrasonic meter indicates a flowrate below its specified minimum flow rate value, an alarm signal shall be initiated.

Provisions shall be available to stop the flow measurement at flow rates below a presetvalue, i.e. flow rate output is forced to 0 m3 /d. This value shall be set for positive and

negative flows and is to be determined for each individual meter run. Non-equal distribution of flow

between the meter runs shall be taken into account. This is particularly critical with low differential

pressure across the meter runs.

2.4.3 Design

The number of meter runs shall be based on the design capacity, the allowable maximumand minimum gas velocity the required minimum flow rate and the availability

requirements of the flow measuring station and the designated flow range of the ultrasonic meter(s).

Any unavailability of the flow measuring station shall only make a small contribution

towards the specified unavailability of the production facility, as defined in the field

development plan. Depending on the availability requirements of the flow

measuring station the meters shall be equipped with full-bore double-block-and-bleedvalves to allow the transducers to be accessed or exchanged at line pressure. As a

minimum one set (2 pcs) of spare transducers of each transducer type (if applicable) shall

be available and properly stored. If dry calibration is not (yet) accepted one spare meter

shall be available either as 'not installed' (and properly stored) or as 'installed' (in a sparemeter run). If a high availability is required, the design of the flow measuring station may have to

be verified.


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NOTE: Depending on the size and requirements (availability, in-situ calibration, etc.) of the

measuring station, important instruments and/or measuring systems should be duplicated by

instrumentation working independently. This shall be agreed between parties.

The contractual availability of gas flow may require a station by-pass, which shall be

normally closed and controlled by permits or locks.The internal diameter of the pipe work shall be designed for gas velocities not exceeding20 m/s.

2.4.4 InstallationMulti-path transit-time ultrasonic flow meters shall be installed and operated in accordance with

ISO/TR 12765, AGA-9 and Manufacturer's recommended installation practices and applicable

regulations.

The ultrasonic flow meter shall operate within the specified operating conditions to satisfy its

uncertainty constraints. Swirl and non-uniform velocity profile effects should be reduced to an

insignificant level by proper installation of the meter. Swirl-free conditions can be taken to existwhen the swirl angle at all points across the pipe cross-section is less than 2°. Straight length

requirements, inlet and outlet connections and/or the type and location of a low pressure-loss flow

conditioner should be in accordance with Manufacturer's specifications. It is recommended to

include the upstream and downstream straight length piping in the scope of delivery of the meteringstation, thereby allowing for meter calibration.

In general, recommended straight length requirements for one-directional flowmeasurement are minimal 10D upstream and 3D downstream, whereas for two-directional

measurement the upstream and downstream sections should be 10D each.

If necessary, flow straighteners of standardised design (ref. ISO 5167) or of agreed proven designmay be installed. The flow straightener may form part of the 10D upstream length.

Meter runs shall be thermally insulated in order to eliminate heat transfer from the piping orinstrument well attachments and to meet any limiting value for the accuracy of flow

measurement required. The length of the insulated section shall at least cover the straight

length requirements and shall include the temperature element.

The centre line of the ultrasonic flow meter shall be within ± 1% of the pipe centre line.

The upstream and downstream straight lengths shall be straight and their cross-sectioncircular over their entire length.

The root pass of any circumferential weld in the upstream pipe section shall be ground flush with

the inside pipe wall. Inspection of the inside of the pipe shall be possible. Seam-welded pipe may beused provided that the internal weld bead is parallel to the pipe axis throughout the entire required

straight length. The seam shall not be within any sector of ±30º centered on any pressure tapping

used in conjunction with the primary element. Any weld bead shall be restricted in height to the permitted step in diameter.


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Gaskets shall be fabricated and installed in such a way that they do not protrude at any

point inside the meter tube assembly.

The bores of the upstream straight length section (10D) and the downstream straight length section

(3D) shall equal the inlet and outlet bores of the meter, respectively.

The location of the pressure tapping to be used as the pressure sensing point for the pressure measurement shall be in accordance with the Manufacturer's recommendations(often the Pr point on the body of the meter).

The temperature sensor for the temperature measurement, for one-directional flowmeasurement, shall be located between 2D and 5D downstream of the meter. For two-directional

flow measurement this location shall be between 3D and 5D upstream or

downstream of the meter. The temperature measurement shall not be influenced by heat

transfer from the piping or thermowell attachment.

The condition of the gas for density measurement at operating conditions shall represent

the conditions at the position of the flow measurement (the Pr point on the meter body ifavailable). The densitometer pocket shall be located according to (2.4.4.6).

Meter run isolation valves shall be of the cylindrical full-bore type, presenting

minimal restriction in fully-open position and conveniently located to allow any leakage to bedetected.

The position of the primary element shall enable its easy removal or replacement but shall not belocated so that dirt or liquid may be collected in the meter.

The meter shall not be installed in the immediate vicinity of pressure reduction valves which may

affect the ultrasonic signals. Some in-line noise reduction could be accomplished by tees or short-radius bends.

The design shall cover at least:- area classification and electrical safety requirements;

- room heating and (natural) ventilation;

- utilities and calibration facilities;- sufficient space for the application of calibration equipment.

2.4.5 On-line computation of the flow rate

The flow rate (both negative and positive) shall be calculated according to ISO 12765.The energy flow is determined from the product of the volume flow and the Gross Heating Value,

both expressed at the same reference conditions.

In order for the ultrasonic meter to be accepted and considered to be of good enough quality the

maximum deviation from the reference during flow calibration shall be less than ± 1.50 %. The

linearity shall be better than 1.0 % (band) and the repeatability shall be better than 0.50 % (band).

These requirements are applicable after application of zero flow point calibration but before


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application of any correction factors, for flow velocities above 5 % of the maximum measuring

range.

For the meter run, the minimum straight upstream length shall be 10 ID. The minimum straight

downstream length shall be 3 ID. Flow conditioner of a recognized standard shall be installed,

unless it is verified that the ultrasonic meter is not influenced by the layout of the piping upstreamor downstream, in such a way that the overall uncertainty requirements are exceeded.

3.0 METER SELECTION CRITERIAThe operator shall fully understand the metering operational requirements of this procedure guide

before making decisions on the type of metering systems to use. However, the meter conceptselection shall be based on the following informative criteria and analyses.

3.1 Alternative cost/benefit analysis of metering concepts The cost of using a concept with high accuracy (concept A) may be unreasonable in relation to themonetary value of the additional measurement uncertainty of a less accurate/less expensive concept

(concept B). The selection of metering concept shall be based on one of the two alternative

cost/benefit analyses given below.

3.2 For metering systems for main fields and sales metering An analysis shall be performed to quantify:

a. The measurement uncertainty of concept A and B

b. The potential monetary loss from the additional measurement uncertainty, by using conceptB instead of concept A, during the lifetime of the installation.

c. The total cost savings, by using concept B instead of concept A, during the lifetime of the

installation.

d. The cost saving in c above minus the potential monetary loss in b above

The key parameter is this analysis for decision making, is the value in d above.All monetary values above shall be calculated as net present values of investment and operating

cost.

4.0 APPLICATION FOR LICENCES, DOCUMENTATION AND

INFORMATION.

4.1 Application for a licence.The licensee shall apply for and obtain a licence from the DPR for the following activities.

1) The design of the fiscal metering system.

2) Prior to the delivery of the fiscal metering system from the place of manufacture

3)

Prior to entering the fiscal metering system into service for fiscal purposes. The licensee shallnot commence any construction work until the licence in accordance with item 1 is obtained.

4.2 Presentation of documentation.Before or in connection with the application for a licence in accordance with the above section, the

licensee shall submit to DPR the following documentation:

(a) Gas fiscal metering specification. (Including algorithms).


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(b) Process data sheets for the metering stations.

(c) Density transducer gas. Typical hook-up drawing. (d) Gas metering skid, piping isometric.

(e) Typical block diagram

(f) Loop diagram for temperature, density, pressure and differential pressure.

(g)

Data sheets for elements and equipment utilised. (h) A/D converter, system description

(i) Computer specification, hardware and software. (j) Detail description/drawing of the 4-way valve, other valves filters and flow straighteners.

(k) General arrangement drawing and P& ID for gas skid.

(l) Data sheets and hook up drawings for the sampling equipment.

If all the required data is not available at the start of construction the licensee may by agreement

with the DPR forward the outstanding documentation within given time limits.Before the metering station is shipped from the vendor the licensee should verify that all

requirements for tests according to Chapter VII of this guide are fulfilled. The licensee should

further confirm that the metering station is designed, built and tested in accordance with theseregulations.

4.3 Authority to Exempt.

Exemptions according to this section mean that the DPR has the authority to grant exemptions fromregulatory requirements when they are applied for. Specific conditions mean situations where the

technical development makes it desirable to make exemptions from the regulations.

4.4 Information.When the fiscal metering station forms a part of an allocation system, the licensee shall inform the

DPR with details of the allocation principles as soon as they are available.

The DPR shall be notified in the event of documented measurement errors caused by the non-compliance with agreed procedures for operation or calibration of a metering station. Correction

shall be carried out if the deviation is greater than 0.020% of total volume. If errors have a lower

percentage value, correction shall be carried out when the total value of the error is considered to besignificant.

Where there is doubt concerning the time at which a measurement error arose, the correction shall

apply for half of the maximum possible time since it could have occurred.If during a routine calibration it is detected that any equipment has drifted within its range, this is

not a reason for correction. A correction should, however, not be implemented if the cost of the correction work is higher than

the value of the wrongly measured mass.

In the guidelines, reference is made to recognised standards and a description is provided of how the provisions of the guide can be met. If alternative solutions are chosen, documentation to demonstrate that such solutions also comply with the requirements of the guide shall be available. The licensee shall informthe DPR before alternative solutions are chosen.

5.0 MANAGEMENT SYSTEM

The vendor shall supply the operator with a Quality Assurance Manual for measurement,which should define;


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(a) Uncertainty limits (accumulated and by component) (b) The responsibility chain for the follow up of the quality of measurement equipment.

(c) Responsibility between different sections, borderlines etc.

For maintenance of equipment the quality manual should specify the following:

(a) Description of the equipment to be checked and the equipment to be used in the check. (b) A description of necessary preparations.

(c) A numbered step explanation on how the checks are to be performed.

(d) A description of how the derived results are handled to ensure quality.

(e) A reference to the logbook for the metering station. (f) Pre-printed form recording data. The forms should have spaces for possible remarks and for

all data necessary record as well as the relevant deviation limits.

For operation of the equipment the QA manual should specify the following:

(a) A functional description of equipment in service during normal operation. (b) A procedure on how to handle situations when any of the in-service equipment fails. (c) A summary of important information from engineering department/colleagues etc.

(d) A list of alarms that can occur procedure on how they can be cleared.

6.0 UNCERTAINTY ANALYSIS.

An uncertainty analysis shall be developed for gas metering systems within 95% confidence level in

accordance with recognised standards. The total gas metering system uncertainty shall, for theoperating flow range, be below +/- 1.0% (mass metering). If a deviation on any of the equipment

tolerances exists, it should be demonstrated that the metering system is within the limits for total

uncertainty given in this section.

For gas measurement the principles of uncertainty calculation are given in ISO/(1998)“measurement of fluid flow estimation of uncertainty of a flow rate measurement “, alternatively in

ISO (1995) Guide to the Expression on Uncertainty in Measurement.

7.0 CALIBRATIONThe term competent laboratory shall be a laboratory accredited in accordance with international

standard or a laboratory which otherwise has documented competence and is traceable tointernational/national standards. For the components mentioned in the first paragraph of this section, it should be developed as

schedule for routine calibration at a competent laboratory.

The supplier shall furnish the operator with the calibration data considered to be of adequatequality. If such is not the case, the equipment must be re-calibrated by a competent laboratory.

8.0 REFERENCE CONDITIONS.

Standard reference conditions for pressure and temperature shall be 101.32Kpa and 15oC. Metersystem design for LPG measurement could use other reference pressure in accordance with

recognised standards.


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designed and installed so that any accumulation of impurities in the form of liquid and solid

particles in the proximity of the transducers is avoided.

The meter shall either by its own design or by necessary piping arrangement always be availablefor necessary maintenance.

The meter shall be designed so that measurements of acceptable quality can be achieved when

one transducer pairs out of service.The ultrasonic flow meter shall be individually calibrated at a traceable laboratory at processconditions (velocity of flow, pressure and temperature) as similar to the operational conditions

as possible. The influence of variations in pressure and temperature shall be determined. The

zero point correction and the calibration factor shall be determined. The meter shall beindividually identified, and a certificate shall be issued.

11.3 Design Requirement for the metering tubeA recognised standard shall be used to determine the minimum lengths of the metering tubes.

The metering tubes shall be connected and mounted at the site of operation so that a part of the pipe

can be dismantled for inspection of the pipe’s inner wall upstream and downstream of the orifice plate. The inner wall of the metering tube shall be continuous without steps or offsets for a length of

at least 10 diameters upstream of the orifice plate. Upstream and downstream pressure tapings shall

be in the same axis of the meter tube.

The metering tube shall be insulated upstream and downstream for a distance sufficient to prevent

heat transfer, which may lead to temperature changes affecting instrument readings for fiscal

parameters.

When considering ultrasonic flow meters the minimum upstream length shall be 10 D. the minimum

downstream length shall be 3 D. It shall further be verified that the ultrasonic meter is not

influenced by the layout of the piping upstream or downstream in such a way that overalluncertainty requirement laid down are exceeded. If it is necessary, flow straighteners of recognised

standard can be installed.

The ultrasonic flow meter must not be installed in the immediate vicinity of pressure reductionsystems (valves etc.), which may affect the ultrasonic signals. An evaluation shall be carried out

which shows that surrounding equipment (both upstream and downstream), will not affect the

ultrasonic signals.When doing ultrasonic measurement, quality requirements for the inner quality of the metering

tubes shall be determined. The ultrasonic flow meter with associated metering tube shall be

insulated upstream and downstream in order to reduce temperature gradients.

12.0 REQUIREMENT FOR THE FLOW PROFILERecognised standard for orifice plate measurement will be: ISO 5167-1 or research results, which

are mutually accepted. The maximum Reynolds number is the highest Reynolds number for whichhistoric calibration data exists. This is today 3.3 x 107. Both for orifice plate measurement andultrasonic flow measurement, flow straighteners of recognised type may be used to improve the

flow conditions through the meter.

13.0 LOCATION OF SENSORSA typical drawing of a gas metering station including valves and instrumentation is given in fig. 1


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14.0 DESIGN OF THE INSRUMENT PART OF THE METERING SYSTEM.

Pressure and temperature shall be measured in each of the metering tubes. The ultrasonic flow

measurement requires that temperature, pressure and if applicable density measurements are to becarried out according to the same guidelines as applicable to conventional orifice measurement.

15.0 GENERAL REQUIREMENTS FOR THE INSTRUMENT LOOPS.Signals from sensors shall be transmitted so that errors are minimised. Transmission shall passthrough the least possible segregated from other types of equipment in the area of use.

Cables and other parts of the instrument loops shall be designed and installed so they will not be

affected by electromagnetic fields.Total uncertainty in the value displayed on the computer shall not exceed the requirements

stipulated in section 34-37 within the normal temperature range of the equipment cabinets.

The checks referred to in these regulations should be conducted in such a way that the measurement

signal is monitored at the computer part when a calibration is carried out. The uncertainty figure is

giving a maximum limit for the deviation between the expected and the displayed value.

15.1 PRESSURE CIRCUIT.

The uncertainty of the complete pressure circuit, including any drift over a period of one month,

shall not exceed +/- 0.30% of maximum calibrated pressure.

15.2 TEMPERATURE CIRCIUT.

The temperature measuring element shall be a platinum resistance element in accordance withrecognised standards. The uncertainty for the complete loop, including any drift over a period of

one month, shall not exceed +/- 0.300C over the temperature range of the measurements. The

uncertainty of the temperature measuring element shall not exceed +/- 20oC

15.3 DENSITY CIRCUITThe density measurements shall be in accordance with a recognised standard. The uncertainty of the

complete density circuit, including any drift over a period of one month shall not exceed +/-% ofmeasured value.

Back up density for gas shall be calculated in the computer and be activated when the online density

measurement is outside its present limits.

15.4 INSTRUMENT LOOP FOR PRIMARY SIGNALIn respect of orifice plates, the differential pressure is the primary signal. The uncertainty of the

complete differential pressure loop, including any drift over a period of one month, shall not exceed

+/- 0.30% of maximum differential pressure. The uncertainty of the differential pressuretransmitters shall not exceed 0.10% of maximum differential pressure. A minimum of two

differential pressure transmitters shall be installed to monitor each other.

With regard to ultrasonic flow meters, the signals between the acoustic transducers are the primarysignals. Critical parameters related to electronic and transducers shall be determined. It shall be possible to verify the quality of the electric signal, which represents the acoustic pulse by automatic

monitoring procedures in the instrument or by connecting external test equipment. The transducers

shall be identified by serial number or similar, location in the meter house etc. A dedicatedcertificate stating critical parameters shall be attached.


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The resolution of the analogue to digital converter shall be better than 0.010% of full scale. Total

error in analogue to digital conversion including resolution, linearity, repeatability and other

random errors shall not exceed +/- 0.020% of full scale.

16.0 INSTALLATION OF MONITORING INSTRUMENTS.

It shall be possible to connect monitoring instruments to measure the performance of all sensors,which provide input parameters to the fiscal algorithms.

17.0 SAMPLING EQUIPMENT.

The sampling equipment shall be of automatic type and be designed in accordance with recognisedstandards. In addition, equipment for manual sampling shall be provided.

The sampling probe shall be installed at least 20D downstream of the nearest bend.

Slope should be maintained along the sample line from the probe to the pressure reduction system

in order to avoid liquid traps.The sampling probe should be designed so it is possible to be retracted under operating pressure by

method accepted by the operator. Spot sampling connection shall be provided.

18.0 DESIGN OF THE COMPUTER PART OF THE METERING SYSTEM. The part of the computer performing the fiscal calculations shall be connected to the part that

collects and distributes measurement signals from the metering station in a manner such that errors

are minimised.

When two computers are duplicating each other, all functions shall at all time be available in bothcomputers. The term equipment, which has historical data available that demonstrates un-

interruptible operations. The reliability of such equipment should be documented as being better

than 99.5% availability.

19.0 SECURITY AGAINST ERRORS AND LOST OF DATA. The part of the computer, which executes fiscal calculations should be designed to have continuous

monitoring facilities for the following conditions:

a) Errors in executions of routines, (watch-dog). To be checked at least every 10s.

b) Errors in permanent stored data (check sum). To be checked at least every 10s. It should be

possible to verify this by print out.

c) Error in internal voltage reference valves.

d) The flow is outside the range of the metering system.

e) Deviations between measured values, valve status and also between paralleled metering

tubes. (These refer to the generations of illegal status alarms when flow registered from an

out of service stream and to the establishment of alarm limits between paralleled stream fordensity pressure and temperature etc.)

Documents

Procedure Guides for the Measurement of Quantity & Quality of Gas at Gas Plants, Refineries Copy