To HQ 02 027 00 PhilosophyforFlowMeteringSystems Onshore

OMV Exploration & Production

Philosophy for Flow Metering Systems Onshore

Document Number

TO-HQ-02-027-00

00

Final Issue

AKO

31/5/05

JEA

31/5/05

A2

Client Comments Incorporated

AKO

24/3/05

HCG

04/02/05

A1

Issued for Comment / Approval

AKO

Dec 04

GS

17/12/04

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Issue or Revision Description

PZ

03/6/05

MF

03/6/05

Appd By

Date

Auth By

Date


Revision

Description of revision

A1

Issued for Comment / Approval

A2

Client Comments Incorporated

00

Final Issue

Philosophy for Flow Metering Systems

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Contents 1.0 PREFACE .......................................................................................................................4 2.0 DEFINITIONS .................................................................................................................4 3.0 ABBREVIATIONS...........................................................................................................4 4.0 INTRODUCTION.............................................................................................................4 5.0 APPLICABLE CODES, STANDARDS AND REGULATIONS........................................5 5.1

Codes and Standards List ........................................................................................................ 6

6.0 GAS FLOW MEASUREMENT FOR CUSTODY TRANSFER.........................................7 7.0 LIQUID FLOW MEASUREMENT FOR CUSTODY TRANSFER ....................................8 8.0 GAS FLOW MEASUREMENT FOR GENERAL PURPOSES ........................................9 8.1 8.2

Separator Gas Measurement .................................................................................................. 10 Wet Gas Measurement ............................................................................................................ 10

9.0 OIL FLOW MEASUREMENT FOR GENERAL PURPOSES........................................10 10.0 MULTIPHASE MEASUREMENT ..................................................................................11 11.0 WATER FLOW MEASUREMENT.................................................................................11 12.0 FLOW COMPUTERS....................................................................................................12


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1.0

PREFACE This Philosophy defines the OMV Exploration & Production GmbH corporate policy on the design of Flow Metering Systems for onshore hydrocarbon production and processing facilities. The document specifies basic requirements and criteria, defines the appropriate codes and standards, and assists in the standardisation of facilities’ design across all onshore operations. The design process needs to consider project specific factors such as the location, production composition, production rates and pressures, the process selected and the size of the plant. This philosophy aims to address a wide range of the above variables, however it is recognised that not all circumstances can be covered. In situations where project specific considerations may justify deviation from this philosophy, a document supporting the request for deviation shall be submitted to OMV E&P for approval. Reference should be made to the parent of this philosophy, document number TO-HQ-02-001 for information on deviation procedures and Technical Authorities, general requirements and definitions and abbreviations not specific to this document.

2.0

DEFINITIONS The following definition is relevant to this document. Flow Measurement for Non Fiscal Purposes

3.0

This is defined as any flow measurement not used for taxation purposes.

ABBREVIATIONS The following abbreviations are relevant to this document.

4.0

AGA

American Gas Association

GPA

Gas Producers Association

INTRODUCTION This Philosophy identifies the minimum requirements for the design of Liquid and Gas Flow Metering Systems. The intention is to define and simplify the purchasing requirements leading to a uniform approach across all onshore assets.


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Flow is the most common variable that is measured in industry today. All flow meters are influenced by the nature of the fluid they are measuring and the way that the fluid flows in piping. Therefore the type of meter selected, the piping arrangement around the meter, the location and environment surrounding the meter can all affect the accuracy and reliability of the installation. The selected measurement technology should be suitable for the application, and only finalised when details of the sales agreement (if applicable), the fluid and location are known.

5.0

•

What is the fluid to be measured? Dry gas, wet gas, dry liquid, gaseous liquid, wet liquid or a mixture of gas, oil, water and solids, all have differing metering requirements.

•

What is the flow regime? Laminar flow, swirling flow, pulsating flow or even slugging flow.

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Are there any contaminants or corrosive elements in the fluid?

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How many meter runs are needed? Consideration should be given to the flow profile over the expected life of the installation. Changes of metering installations during their lifetime are expensive.

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The piping arrangement before and after the meter should be considered, not only with respect to straight lengths upstream and down stream, though they are important.

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Meter locations should be capable of being accessed safely and not be susceptible to severe or rapid changes in ambient conditions.

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Instrument reliability should be considered. It is often cheaper in the long run to spend more on the initial purchase of a high reliability instrument than buy a cheaper version, which will need more intensive maintenance and possible replacement within the lifespan of the more expensive device.

•

The specific conditions set out in the product sales agreement including meter types, accuracy and special measurements such as density, along with proving requirements

APPLICABLE CODES, STANDARDS AND REGULATIONS Codes, standards and regulations referred to in this philosophy shall be of the latest edition and shall be applied in the following order of precedence: •

Local Regulations,

•

The provision of this document,

•

International standards (e.g. ISO, IEC etc),


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•

National standards.

Design of the metering systems shall comply with the standards listed within this philosophy, however, for instances where local standards are more onerous local standards shall apply. 5.1

Codes and Standards List ISO (International Organisation for Standardisation) ISO 2714

Liquid Hydrocarbons – Volumetric measurement by displacement meter systems other than dispensing pumps.

ISO 2715

Liquid Hydrocarbons – Volumetric measurement by Turbine Meters.

ISO 3170

Petroleum Liquids – Manual Sampling

ISO 3171

Petroleum Liquids – Automatic Pipeline Sampling

ISO 3675

Crude Petroleum and Liquid Petroleum Products – Laboratory determination of density or relative density Hydrometer method

ISO 4006

Measurement of Fluid Flow in Closed Conduits – Vocabulary and Symbols

ISO 4124

Liquid Hydrocarbons – Dynamic Measurement; Statistical control of volumetric metering systems

ISO 5024

Specification for Standard Reference Conditions for Measurement of Petroleum Liquids and Gases

ISO 5167-1 Measurement of Fluid Flow by Pressure Differential Devices; Orifice Plates, Nozzles and Venturi Tubes Inserted in Circular Cross-section Conduits Running Full ISO 5168

Methods of Measurement of Fluid Flow: Estimation of Uncertainty of a flow rate measurement

ISO 6551

Petroleum Liquids and Gases – Fidelity and security of dynamic measurement cabled transmission of electric and/or electronic pulsed data

ISO 6817

Measurement of conductive fluid flowrate in closed conduits – method using electromagnetic flowmeters

ISO 6976

Natural Gas – Calculation of calorific values, density, relative density and Wobbe index from composition

ISO 7278

Liquid Hydrocarbons – Dynamic Measurement; Proving systems for volumetric meters

ISO 9951

Natural Gas – Turbine meters used for the measurement of gas flow in closed circuits

ISO 10723 Natural Gas – Performance evaluation for on-line analytical systems Philosophy for Flow Metering Systems

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ISO 10790 Measurement of Fluid Flow in Closed Conduits – Guidance to the selection, installation and use of Coriolis Meters (mass flow, density and volume flow measurements) ISO 12213 Natural Gas – Calculation of compression factor ISO 13443 Natural Gas – Standard reference conditions GUM 1

Guide to the expression of uncertainty measurement

TR 12765

Measurement of fluid flow in closed conduits – methods using transit-time ultrasonic flow meters

TR 15377

Measurement of fluid flow by pressure-differential devices – Guidelines to the effect of departure from the specifications and operating conditions given in ISO-5167-1

TR 3313

Measurement of fluid flow in closed conduits – Guidelines on the effect of flow pulsations on flow measurement instruments

BSI (British Standards Institute) BS 7405

Guide to the selection and application of flowmeters for measurement of fluid flow in closed conduits.

BS 7965

The selection, installation, operation and calibration of diagonal path transit time ultrasonic flow meters for industrial gas measurement

AGA (American Gas Association) AGA 3

Orifice Metering of Natural Gas

AGA 8

Compressibility and supercompressibility for natural gas and other hydrocarbon gases

AGA 9

Measurement of Gas by Multipath Ultrasonic Meters

AGA 10

Speed of Sound in Natural Gas and Other Related Hydrocarbon Gases

GPA (Gas Processors Association) GPA 2165 Standard for analysis of natural gas liquids mixtures by gas chromatography 6.0

GAS FLOW MEASUREMENT FOR CUSTODY TRANSFER The design aim is for the method of measurement, uncertainty and the operating and maintenance procedures to be suitable for the gas during the lifetime of the metering requirement. Consideration should be given to the possible changes in flow rate and fluid properties over the system lifetime.


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Sales gas flow measurement is usually specified by industry as a mass flow measurement with an overall uncertainty of ±1% or better. The overall uncertainty is derived from a statistical combination of the measurement system component uncertainties. In order to achieve this level of uncertainty the gas will have to be single phase with no possibility of liquid (either water or hydrocarbon carryover to, or condensation in, the meter) as this will have a significant effect on the uncertainty of the measurement. The accuracy of individual components is to be defined. The primary measurement device is the most critical element of the metering system. The primary devices most commonly used in sales applications are orifice plates and multi-path ultrasonic meters. Though coriolis meters are beginning to be accepted for this application there is relatively little experience in this area. Secondary instrumentation is required to measure and record line pressure, line temperature, flowing density, gas composition, dewpoint and CO2 and H2S fractions. Consideration should be given to both the quality and location of the instruments to ensure a representative measurement is obtained. The use of backup instruments should be assessed to ensure continuity of measurement following an instrument failure. The provision of instrumentation test and calibration facilities at the meter site should also be investigated. This is an online calibration and measurement, orifice inspection and sparing philosophy are to be investigated. Also number of transmitters, especially for low and high range to be investigated. Gas flow measurement systems of fiscal quality should be supplied with a sampling system for the periodic measurement of average density and laboratory analysis. If an orifice plate is to be employed as the primary flow element installation and operation will normally be expected to comply with ISO 5167 or AGA 3. If a multipath ultrasonic meter is to be used installation and operation will normally be expected to comply with ISO TR 12765, BS 7965 and AGA 9, plus any specific recommendations of the manufacturer. Sufficient meter tubes should be supplied to allow one tube to be taken out of service to examine the orifice plate for damage and calibrate the differential pressure transmitters, or send the multi-path ultrasonic meter to a recognised test facility for recalibration, without compromising the ability to measure the maximum expected flow. 7.0

LIQUID FLOW MEASUREMENT FOR CUSTODY TRANSFER The design aim is for the method of measurement, uncertainty and the operating and maintenance procedures to be suitable for the liquid during the lifetime of the metering requirement. Consideration should be given to the possible changes in flow rate and fluid properties over the system lifetime.


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Sales liquid flow measurement is often defined by industry consensus as a dry mass flow measurement with an overall uncertainty of ±0.25% or better. The overall uncertainty is derived from a statistical combination of the measurement system component uncertainties. In order to achieve this level of uncertainty the liquid will have to be single phase with no possibility of either a water cut of over 3% or gas breakout in the meter as this will have a significant effect on the uncertainty of the measurement. The primary measurement device is the most critical element of the metering system. The primary devices most commonly used in sales applications are turbine meters, normally with a facility for in-situ verification. Coriolis meters are also used for sales measurement, both as primary devices and master meters. They are particularly suited to measurement of LPG and condensate. In line spool-type multi-path ultrasonic meters are also used for fiscal measurement. Secondary instrumentation is usually required to measure and record line pressure and line temperature, flowing density and water cut. Consideration should be given to both the quality and location of the instruments to ensure a representative measurement is obtained. The use of backup instruments should be assessed to ensure continuity of measurement following an instrument failure. The provision of instrumentation test and calibration facilities at the meter site should also be investigated. Liquid flow measurement systems of sales quality are often supplied with an automatic flow proportional sampling system for the measurement of average water content, average density and laboratory analysis. Sampling systems should be generally in accordance with ISO 3171. The sampling system is a critical part of the fiscal metering system. Means of verification of the meter should be considered during the design stage, if there is sufficient space for a dedicated meter prover this is the optimum solution as it provides meter calibration at flowing conditions. Other alternatives are the use of a master meter of a different technology or removing a meter and returning it to a recognised meter calibration facility. Facilities for the calibration of the prover or master meter should also be provided. The prover should be calibrated in accordance with the requirements of the purchaser; the master meter can be calibrated at a recognised meter calibration facility. These calibrations should be witnessed by, and be carried out at the frequency as stated in the sales agreement. 8.0

GAS FLOW MEASUREMENT FOR GENERAL PURPOSES Examples of non-sales metering which require unique solutions for the specific conditions include separator gas, wet gas, fuel gas and flare gas measurement. The design aim is for the method of measurement, uncertainty and the operating and maintenance procedures to be suitable for the gas during the lifetime of the


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metering requirement. Consideration should be given to the possible changes in flow rate and fluid properties over the system lifetime. The primary measurement device is the most critical element of the metering system. The primary device should be selected on the basis of the fluid conditions and the purpose of the measurement to be adequate for the service and lifetime of the requirement. 8.1

Separator Gas Measurement Separator gas flow measurement can be treated as wet gas flow measurement and all the methods used for this type of measurement are also applicable.

8.2

Wet Gas Measurement Wet gas flow in pipes is characterised by the liquid to gas ratio and the gas velocity, if there is a small amount of liquid or a high gas flow the liquid is carried as a mist or droplets suspended in the gas stream. As the liquid volume fraction increases or the gas velocity decreases the liquid droplets will tend to coalesce on the pipe wall producing annular flow with the gas flowing in the centre of the pipe and the liquid flowing around the pipe wall. Further increasing liquid or decrease in gas velocity results in stratified flow with the liquid flowing along the bottom of the pipe and the gas in the top. Wet gas flow is normally defined as two phase flow with a liquid volume fraction of 10% or less. Any fraction above 10% is considered to be multiphase flow. Primary measurement devices that can be used to measure wet gas flow are orifice plates, venturi meters and v-cone meters. In wet gas applications orifice plates with drain holes should always be used to avoid the damming effect of the plate on the liquid flow. The use of orifice plates fitted with drain holes is covered by ISO TR 15377. The drain hole should be at the bottom of the orifice plate.

9.0

OIL FLOW MEASUREMENT FOR GENERAL PURPOSES All fiscal oil flow measurement is on pipeline feeds out of the processing plant and is measuring stabilised dry oil; non-fiscal measurement is applicable to all other oil flow measurements. These other measurements can be split into two main groups, allocation metering and separator oil measurement, though both normally involve the measurement of oil flow from a separator. The design aim is for the method of measurement, uncertainty and the operating and maintenance procedures to be suitable for the gas during the lifetime of the metering requirement. Consideration should be given to the possible changes in flow rate and fluid properties over the system lifetime.


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The primary measurement device is the most critical element of the metering system. The primary device should be selected on the basis of the fluid conditions and the purpose of the measurement to be adequate for the service and lifetime of the requirement. Separator oil measurement can be used for allocation purposes, where a dedicated separator is used to measure the oil, gas and water production from a particular field; for internal accounting purposes, to measure the oil, gas and water production from an individual separator in a multi stream or multi stage system; or for a well test system, where a test separator is used to measure the oil, gas and water flow from an individual well. Oil allocation flow measurement is defined by industry consensus as a mass flow measurement with an overall uncertainty of between 0.5 and 5% or better. The overall uncertainty is derived from a statistical combination of the measurement system component uncertainties. 10.0

MULTIPHASE MEASUREMENT At the moment no independent standards for multiphase flow measurement exist making selection of one of the many available systems more difficult. The existing systems are made up of a number of sensors providing different information about the flow, which when combined and operated on using various correction factors will give an indication of the individual flow rates of the constituent parts, usually oil, water and gas.

11.0

WATER FLOW MEASUREMENT There are two distinct water flow measurements applicable to this industry, produced water and injection water, each requiring different techniques. Produced water measurement is normally taken at the water outlet of a separator to record the proportion of water in the overall well fluid. The normal separator outlet problems exist, in that the fluid will be at bubble point and gas breakout will occur as a result of pressure drop in the pipework or measurement device and there may be oil and or sand present suspended in the flow. Traditionally either turbine meters or magnetic flow meters have been used for this service. Turbines will measure the total flow whereas magnetic flow meters will only measure the water flow. Ultrasonic meters are being used more, however care should be taken to avoid gas breakout, and minimise droplet or particulate in the flow stream as either will cause measurement problems. One of the main advantages of the magnetic flow measurement is the lack of requirement for straight meter runs allowing installation in the restricted area underneath the separators.


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Water injection flow measurement presents different criteria, the water is usually clean and always at high pressure. Ultrasonic measurement is ideally suited to this service. 12.0

FLOW COMPUTERS The flow computer is used to calculate, record and display the fluid flow to the operator. It can only operate with the base information being supplied, no reduction in uncertainty of the measurement can be obtained by the use of a highly specified flow computer. The most important element of any flow measurement system is the primary measurement device. The meter display should allow the verification of all calculation constants to the appropriate resolution, and programmes should require authorised action before revision can take place. All changes to the programme including changes to constants used in the flow calculation should be automatically recorded. The use of manually entered fallback data should be logged. The majority of commercially available dedicated flow computers have these facilities included by default. The flow computer should automatically record the major parameters of the flow measurement on a regular basis, normally as a minimum every 4 hours, with daily totals recorded on a fixed 24 hour interval. The major parameters are flow rates, line pressure and temperature and flowing density. Other parameters such as liquid water cut and gas composition can also be recorded if available. All alarms, including fault alarms, and error reports generated by the flow computer should be recorded.


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To HQ 02 027 00 PhilosophyforFlowMeteringSystems Onshore

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