Liquid Measurement Station Design

EMERSON Process Management CONO SUR & Brazil

Fiscal Measurement

Of Oil

Mercado de Petróleo y Gas

Moléculas Gas Natural Livianos

Metano (CH4) NaturalGas C1-C4;N2;CO2

Etano (C2H6)

Dióxido de Carbono (CO2)

Nitrogeno(N2)

Moléculas Gas Natural Medianos

Propane (C3)

Butanos (C4/iC4)

Gas@25°C

Liq@25°C

Liquid Hydrocarbon Alcanos or Saturated or Parafins Light

Hexanos (C6 e isómeros) Ether C5-C6

Heptanos (C7 e isómeros)

Octanos (C8 e isómeros) Gasolina (C4-C8)

Trimethylpentane, iso-octane Gasolina 100 Octanos (CH3)3CCH2CH(CH3)2

Dodecano (C12H26 e isómeros)

Hexadecano (C16H34 e isómeros) Kerosene C12-18/Diesel C12-C23

C23-C30 Lubricants >C40 Sólido

Liquid Hydrocarbon Alcanos or Saturated or Parafins Medium and Heavy

Other Hydrocarbons no Alcanos o Saturados

CycleHexane (C6H12 Solvente) Methanol (previene hidratos)

Ethylene

Polyethilene (plástico)

Ethanol Benzene (C6H6) Zippo

Tolueno (C7H8) Thinner (mas ethanol)

Aromaticos

Alkino Acetileno C2H2 triple enlace de C

Thiohene (C4H4S) Azufre content

http://en.wikipedia.org/wiki/File:Benzene-aromatic-3D-balls.png

Combustión Gasolina iC8H18 + 12.5O2 ~> 8CO2 + 9H2O+Energy

+ ->

Gasoline + Aire(Oxigeno) = Dioxido de Carbono + Agua + Energia

+

Densidad Grados API

Gravedad API = (141,5/GE a 60 °F) - 131,5 Si GE=1 (densidad= AGUA pura @ 60F=0.998Kg/litro) =10

Gravedad Kilos Lbs por

Especifica por Litro Galon

1 1.0679 1.0658 8.8964

5 1.0366 1.0346 8.6357

10 1.0000 0.9980 8.3306

15 0.9659 0.9639 8.0462

20 0.9340 0.9321 7.7807

25 0.9042 0.9023 7.5321

30 0.8762 0.8744 7.2989

35 0.8498 0.8482 7.0797

40 0.8251 0.8234 6.8733

50 0.7796 0.7781 6.4946

60 0.7389 0.7374 6.1555

75 0.6852 0.6839 5.7083

Grados API

Petroleo y sus subproductos

Gravedad Kilos Lbs por

Especifica por Litro Galon

1 1.0679 1.0658 8.8964

5 1.0366 1.0346 8.6357

10 1.0000 0.9980 8.3306

15 0.9659 0.9639 8.0462

20 0.9340 0.9321 7.7807

25 0.9042 0.9023 7.5321

30 0.8762 0.8744 7.2989

35 0.8498 0.8482 7.0797

40 0.8251 0.8234 6.8733

50 0.7796 0.7781 6.4946

60 0.7389 0.7374 6.1555

75 0.6852 0.6839 5.7083

Grados API

Typical World oil

Typical Dinamic Viscocity

( o F) ( o C)

CentiStokes (cSt)

Seconds Saybolt

Universal (SSU)Liquid

Temperature Kinematic Viscosity

( o F) ( o C)

CentiStokes (cSt)

Seconds Saybolt

Universal (SSU)

68 20 1.52 31.7100 37.8 1.2 31.5

Beer 68 20 1.8 32-50 0.5230 0.3560 15.6 3.8 39130 54.4 1.6 31.860 15.6 9.7 55.7130 54.4 3.5 38

60 15.6 17.8 88.4130 54.4 4.9 42.3

60 15.6 23.2 110130 54.4 7.1 46.80 17.8 2.36 34

100 37.8 1.001 31

100 37.829.8 max 140 max

130 54.413.1 max 70 max

70 21.12.39-4.28 34-40

100 37.8 -2.69 32-3570 21.1 13.9 73100 37.8 7.4 50

-1.1Butane-n

Gas oils

Fuel oil 1

Diesel fuel 4D

Crude oil 48o API

Crude oil 40o API

Crude oil 35.6o API

Crude oil 32.6o API

Decane-n

Alcohol - ethyl (grain)

C2H5OH

Liquid

Temperature Kinematic Viscosity

0 -17.8 0.928100 37.8 0.5110 -17.8 0.683

100 37.8 0.401Honey 100 37.8 73.6 349

Kerosene 68 20 2.71 35Jet Fuel -30 -34.4 7.9 52

70 21.1 0.118100 37.8 0.11

Milk 68 20 1.13 31.50 -17.8 1.728

100 37.8 0.8070 -17.8 1.266

100 37.8 0.645100 37.8 43.2130 54.4 24.10 17.8 0.50880 26.7 0.34268 20 14.56140 60 7.2 cp

Water, distilled 68 20 1.0038 31

60 15.6 1.13130 54.4 0.55

Water, sea 1.15 31.568 20 0.93104 40 0.623 cpXylene-o

Water, fresh 31.5

Sulphuric acid 100% 76

Pentane-n

Nonane-n 32

Octane-n 31.7

Olive oil 200

Mercury

Hexane-n

Heptanes-n

Medición fiscal de Transferencia de Custodia Cuando un proveedor entrega

un producto a un cliente ocurre una transacción económica.

Para asegurar un intercambio justo de bienes una medición exacta es critica en la operación

El equipamiento de medición es la caja registradora de esta transacción

¿Qué es una TRANSFERENCIA FISCAL? La TRANSFERENCIA FISCAL es un acuerdo entre dos partes

1) Legal

2) Contratos

3) Contratos + Legal

Aplicaciones con Líquidos

Producción

Oleoductos

Almacenamiento y descarga de barcos

Entrada y salida de refinerías

Poliductos

Despacho a trenes y camiones

Estandards Industriales para Líquidos American Petroleum Institute ( A.P.I. )

Capítulo 4: Proving Systems Capítulo 5: Measuring Capítulo 6: Metering Assemblies Capítulo 8: Sampling Capítulo 11: Physical Properties Data Capítulo 21: Flow Measurement using Electronic ...

International Standards Organization (ISO) Regulaciones Nacionales, Provinciales y/o

Municipales sobre Pesas y Medidas

¿Qué es el A.P.I.? Son las siglas del

AMERICAN PETROLEUM INSTITUTE

– Es una organización que representa a más de 400 empresas de la Industria del Gas y el Petróleo de los Estados Unidos de Norteamérica.

– Está dividida en sectores de actividad • Upstream

• Downstream

• Actividades Marítimas

• Propietarios y Operadores de Oleoductos / Gasoductos

• Generales: Servicios, perforación, mantenimiento, etc.

American Petroleum Institute “The API Committee on Petroleum Measurement's purpose is to

provide leadership in developing and maintaining cost effective, state of the art, hydrocarbon measurement standards and programs based on sound technical principles consistent with current measurement technology, recognized business accounting and engineering practices, and industry consensus.

Los estándares del A.P.I. proveen una guía y no fuerzan el uso o dirigen al usuario a utilizar un medidor en particular.

Custody Transfer Application

F

Flowmeter

S

P DPT

PD Meter API 5.2

Coriolis Meter API 5.6

Turbine Meter API 5.3

Liquid Ultrasonic Meter API 5.8

Small Volume Prover

API Chpt 5 covers Metering

API Chpt 4 covers Proving

Flow Computer Fiscal API 21.1 y 21.2 Cálculo de propiedades físicas (API 11)

API Chpt 8 covers Sampling

Accuracy & Repeatability

Not very accurate, or repeatable


Repeatable, but not very accurate


Yes, accuracy with repeatability!

Características de un Medidor

Qmin Qmax Caudal

0

Repetibilidad

+

Linealidad

-

Rango de Caudales Qmax/Qmin=Rangeabilidad

¿Qué es una unidad L.A.C.T. ? Lease Automatic Custody Transfer

– Analiza el producto y lo acepta solo si está en especificación – El dueño es el comprador y la alquila al vendedor – Transfiere producto (camión, oleoducto, etc.) – Generalmente de pequeño tamaño – Generalmente no tiene probador – Mide el volumen y totaliza – Registra los eventos – Concepto surgido en los EE.UU. – Muestrea el producto – Opera en forma automática

Diagrama P & I

Elemento Primario Analizar

Orientar

Proteger Acondicionar

Verificar

Calificar

BPH Yearly Financial Loss (@ 90 usd per Barrel)90

1000 788,400 1,576,800 2,365,200 3,153,600 3,942,000 2000 1,576,800 3,153,600 4,730,400 6,307,200 7,884,000 4000 3,153,600 6,307,200 9,460,800 12,614,400 15,768,000 8000 6,307,200 12,614,400 18,921,600 25,228,800 31,536,000

12000 9,460,800 18,921,600 28,382,400 37,843,200 47,304,000 20000 15,768,000 31,536,000 47,304,000 63,072,000 78,840,000 40000 31,536,000 63,072,000 94,608,000 126,144,000 157,680,000 80000 63,072,000 126,144,000 189,216,000 252,288,000 315,360,000

Uncert 0.10% 0.20% 0.30% 0.40% 0.50%

Why Provers : Uncertainty versus Yearly Financial Loss

A 0.1% improvement in measurement on 12000 BPH (2725 m3/h) will realize significant revenue increase over the year

Tipos de Medidores para Líquidos

Medidor de Desplazamiento Positivo API MPM - Capítulo 5.2

Medidor de Turbina Axial API MPM - Capítulo 5.3

Medidor Coriolis API MPM - Capítulo 5.6

Medidor Placa Orificio API MPM - Capítulo 5.7

Medidor Ultrasónico API MPM - Capítulo 5.8

Características de un Medidor de

Desplazamiento Positivo

Linealidad: +/- 0.25 %

Repetibilidad: +/- 0.02 %

Rango de Caudales: 10 a 1

Positive Displacement – Mededor Oval

Medidores de Desplazamiento Positivo

Positive Displacement

Bi Rotor

Medidores de Desplazamiento Positivo


Turbina

Linealidad: +/- 0.15 %



PT Internals

UMB Housing Dual Channel Preamp

Custody Transfer Technologies 1500 Series Turbine Meters

PT Internals

UMB Housing

Dual Channel Preamp

Series 1500 - Proven Performance

Combination of the PT and UMB turbine meter technologies

Utilizes the UMB body/housing design, preamp & coils, and the PT internals

Designed to comply with PED

Proven performance Tungsten carbide bearing

design: provide extended life

Patented cone design enables rotor to float: improves hydrodynamic characteristics, reduces rotor drag and bearing wear

Dual hanger rotor design allows for bi-direction flow: reduced cost of ownership

Floating Rotor

Customer Value Dual UMB Enclosure

– Allows 100% redundancy

– Up to 4 pickoffs

– Up to 4 pulse outputs

– Multiple ‘Hot’ spares

– No shut down based on preamp or pickoff failure

Available sizes 3” to 16”

Dual Output Preamplifier

Proving - Pulse Security

The Dual UMB Differentiators Flexibility of Application

– Case 1: Normal flow measurement – 2 UMB, 1 pick-off in each (these will be 900 out of phase electrically

– Case 2: Prover accommodation – 2 UMB, 3 pick-offs, 1 used for proving

– Case 3: Shared ownership – 2 UMB, 4 pick-offs, each owner takes matched pulse outputs to their flow computers

– Case 4: Full redundancy required – 2 UMB, 4 pick-offs, total redundancy

How Do We Address Pipeline Characteristics?

Single UMB with 2 pick-offs & 1 (dual channel) preamplifier will provide pulse integrity

Dual UMB with 4 pick-offs can provide measurement redundancy

– Each UMB pick-off pair will be 900 electrically out-of-phase

– Individual power supplies will be required to allow maintenance in the field without losing total measurement

Blade and Rim type Rotors

Blade Type

Rim Type

Rim type rotor

The number of magnetic buttons that can be fitted is much higher than the number of blades. This allows for increased pulse resolution.

Series 1500 High Resolution Rotor New rotor offers 2x

the number of pulses

Meter Size K Factor (P/BBL)

6” 2000 8” 1100

10” 500 12” 400 16” 200

Why offer? Customers are increasing their line throughputs and need larger flow meters but may not want to upgrade their existing provers. The High Resolution Rotor option permits the use of smaller size provers especially for those customers who are unwilling to use pulse interpolation methods

NEW! Series 1500 Light Weight Rotor For vertical

installations or for use on light hydrocarbons such as LPG

Recomendación API para Turbinas

Medidor a Turbina para Líquido


Efecto CORIOLIS

Exactitud en caudal: +/- 0.050 %


Exactitud en densidad: +/- 0,0005 gr/cm3


Medidor de Efecto CORIOLIS Bobina Generadora

Bobinas Captoras

Sensor Temperatura

Caja

Tubo de Medición

Flecha de Dirección del flujo

Brida Conexión a proceso

Brida Conexión a proceso

Recomendación API para Coriolis

Figura 2 del API MPM Capítulo 5.6

Medidor Coriolis para Líquidos

Caracterísiticas de un Medidor Ultrasónico • Linearidad:

+/- 0.15% del valor medido sobre 40 to 4 fps range +/- 0.20% del valor medido sobre 40 to 2 fps range • Repetibilidad: ± 0.02% • Overrange: Overrange 20% del máximo • Curva de comportamiento típico:

Principio de Funcionamiento de ultrasónicos para líquidos

Ultrasónico Multipath de Líquidos

Medidor Ultrasónico

)L/x(vcLt

)L/x(vcLt

+=

−=

2

1

L Flow

X

D

Transducer 2

Transducer 1 v = L 2x

(t 1 -t 2 ) t 1 t 2

c = L 2

(t 1 +t 2 ) t 1 t 2

v=velocidad de flujo c=velocidad del sonido

t 1 =tiempo de tránsito upstream t 2 = tiempo de transito downstream

2

Q = vA

Daniel Model 3804 Flow Calculations

Se miden 4 paths

Los trasnductores actúan como emisores y transmisores

Las cuerdas se nombran de acuerdo a la posición

431

21 1382.03618.03618.01382.0 vvvvvwVn

iiaverage ⋅+⋅+⋅+⋅== ∑

Calculo de velocidad

Calculo de Flujo

AVQ average ⋅=

where: Vaverage = Average Flow velocity (= Q / A)

wi = weighting based on the Gaussian Integration technique

vi = the average flow velocity measured on path I

Q = volumetric flow rate

A = pipe cross sectional area

Ejemplo de aplicación

MPMS Chapter 5.8 This standard describes methods of obtaining custody transfer

level measurements with ultrasonic flow meters (UFM’s) used to measure liquid hydrocarbons

This document focuses on ultrasonic flow measurement using transit time technology, spool type meters with two or more paths that are affixed onto the meter

Chapter 5.8 includes:

– Application criteria

– Installation

– Operation

– Maintenance

– Proving

Design Considerations

Revised Section on Flow Conditioning

Meter Performance

Verificación de medidores de LIQUIDOS

Calibración vs Verificación El API, en su Capítulo 5, diferencia la “CALIBRATION” ó Calibración

de “PROVING” ó la Verificación en Campo:

– Calibración (Calibration): Es el proceso de utilizar un patrón de referencia para determinar un coeficiente que ajuste la salida del medidor y llevarlo a un valor que se encuentre dentro de la tolerancia de exactitud especificada un rango especificado de caudal. Este proceso normalmente es llevado a cabo por el fabricante.

– Verificación en campo (Proving): Proceso de comparación entre la cantidad indicada que atraviesa el medidor, en condiciones de operación, y una cantidad conocida tomada como referencia, con el objeto de determinar el factor del medidor (MF, meter factor). Este proceso normalmente se lleva a cabo en el campo.

-1.00

-0.80

-0.60

-0.40

-0.20

0.00

0.20

0.40

0.60

0.80

1.00

0 500 1000 1500 2000 2500 3000 3500

Flow Rate (m3/hr)

% E

rror

Naptha : 0.61 cSt : Linearity = ± 0.0735%

Oural : 6.2 cSt : Linearity = ± 0.0783%

Why Proving ?LUSM – Ball Prover

Probador de Medidores ( Prover ) Tipos:

Unidireccional Cámara de transferencia requiere mantenimiento

Bidireccional Bajo mantenimiento - Simple operación

De Pequeño Volumen ( SVP ) Gran Rangeabilidad

Requerimientos de Exactitud

% of Maximum Flow Rate

Maximum flow Rate = 11,400 Bbl/hr

275.5

275.0

274.5

274.0

273.5

273.0

272.5

272.0

271.5

271.0

270.5 0 20 40 60 80 100

} } }

Calibration data

Manufacturer’s specification

Legal limit

Customer’s desired accuracy

Government

W & M requirements

Meter Performance

As with all custody transfer flow meters, a meter factor must be determined by proving the meter at stable operating conditions

– Proving conditions shall be as close to the actual metering conditions as practical

– In-situ proving is normally preferred because it verifies the meter’s accuracy under actual operating conditions

– Laboratory proving is normally not preferred because laboratory conditions may not reflect operating conditions

(1) Prove under normal conditions The meter must be proved under the same conditions as it is normally expected to operate. (2) Adequate prover capacity The meter prover must have a capacity large enough to provide proving runs of adequate duration. (3) Sufficient number of runs A sufficient number of runs must be made to establish a valid proving. (4) Traceable results to National Institute of Standards and Technology Calibration of the meter prover must be traceable to (NIST) calibrated test measures.

Four Basic Requirements

Operating Conditions

When Proving. . . .

Flow Rate Temperature Pressure Liquid Characteristics

– API Gravity

– Viscosity

Proving Conditions Should Match the Operating Conditions

Proving Conditions

Meter Proving

How to Prove – By placing a liquid meter in series with a meter

prover, which has a known or base volume in such a way that all the liquid measured by the meter is also measured by the prover

Meter Prover

Flow from Meter

Displacer

Detectors

Calibrated length

Calibrated Volume

Pulses from Meter

START STOP

Prover

Computer

Meter Proving by Displacement

Probador Bidireccional - Funcionamiento

Características Probador Bidireccional Portátil ó Fijo Tipo de producto Tipo y características del medidor a verificar Rango de caudales Caudal continuo ó intermitente Tipo de esfera ó de pistón Operación local ó remota Operación manual ó automática Tensión de alimentación disponible Código de diseño de cañerías

Probador Bidireccional - Diseño Función del Rango de Caudales Velocidad de Desplazamiento

5,0 ft/s (1,5 m/seg) / 0,5 ft/s (0,15 m/seg)

Volumen Patrón Corresponde a un “round trip” Corresponde a mínimo 10.000 pulsos por corrida Se lo obtiene mediante el “ Water Draw “

Repetibilidad: +/- 0,02 %

Prover Volume (≥ 30 ft)

Determinación del Volumen Pre-Run Volumen calibrado debe

permitir los 10.000 pulsos Distancia entre los detectores

Detectores Mecánicos

Tipo de Probadores

PROBADOR

ES

VOLUMÉTRICOS

GRAVIMÉTRICOS

POR LOTE ( Start / Stop )

CONTÍNUO ( On the fly )

TANQUE ABIERTO

CERRADO

MEDIDOR PATRÓN ( Master Meter )

MEDIDOR PATRÓN ( Master Meter )

De CAÑERÍA ( Pipe Prover )

COMPACTO Compact Prover

Small Volume Prover

UNIDIRECCIONAL

BIDIRECCIONAL

Tanque Abierto

Tanque SERAFIN®

La operación es totalmente manual

Se requiere “humedecerlo”

Se requiere una bomba para sacar el producto

Hay que inspeccionar el tanque

Requiere recuperar vapores

Potenciales derrames

Requiere mucho tiempo cada ensayos

48” 600# Meter Prover for Crude Oil Service

Bi-Directional Ball Prover

Proving Ultrasonic Meters

Turbine Meter – Sees all of the flow – Local turbulence is

averaged by the rotor – The rotor can turn at

only one rate – Little data scatter due

to inherent inertia of the measurement element

– Uniform pulse train

Ultrasonic Meter – Samples the flow at 4

chord locations – Local turbulence is

averaged by many samples

– Short term repeatability is a function of turbulence

– Data scatter due to ability to measure minute variations in velocity ie: turbulence

– Non-uniform pulse train

Differences exist in flow dynamics between Turbine and Ultrasonic technology

Proving Liquid Ultrasonic Meters Liquid Ultrasonic Meters are “manufactured pulse”

type meters

There are two factors which can affect proving results.

– Proving accuracy can be affected by any delay in pulses due to processing speed of the transmitter

– Ultrasonic meters produce a non-uniform pulse output and has a varying frequency. This can cause difficulty in obtaining acceptable repeatability while proving

Proving run repeatability is used as an indication of whether the proving results are valid

Proving run repeatability may not fall within the typical 5 run, 0.05% span of repeatability, however proving runs shall repeat within the API Ch 4.8 guideline

Uniform pulse output – Turbine meter Frequency normally very constant

Non-uniform pulse output – Ultrasonic meter

Frequency variation due to ability to measure minute variations in velocity

How do we Prove Liquid Ultrasonic

Meters

(1) Prove under normal conditions The meter must be proved under the same conditions as it is normally expected to operate. (2) Adequate prover capacity The meter prover must have a capacity large enough to provide proving runs of adequate duration. (3) Sufficient number of runs A sufficient number of runs must be made to establish a valid proving. (4) Traceable results to regulatory standards ie: NIST, INMETRO, OIML Calibration of the meter prover must be traceable to certified test measures.

Four Basic Requirements

Setting Liquid USM Response Time

It is essential to have flow pulse signal processing respond quickly to minimize potential meter factor bias errors

It is recommended that any signal processing configuration settings in the transmitter be minimized – Sample interval – the time period between ultrasonic flow rate samples

– Number of samples – the number of ultrasonic samples processed for each flow measurement update

– Pulse output adjustment – amount of damping or filtering of the flow measurements that produce the pulse output signal

Any changes made to LUFM’s speed of response requires the Ultrasonic meter to be re-proven

Flow Rate Change During Proving

Flow velocities

15

16

17

18

19

20

21

14:42

:43

14:44

:10

14:45

:36

14:47

:02

14:48

:29

14:49

:55

Time

Flow

veloc

ities (

ft/s)

AvgFlow (ft/s)

4 way valve closing

1st detector switch

1st detector switch

2nd detector switch

2nd detector switch

ball entering launch chamber

4 way valve closing

Liquid Ultrasonic Meters

• UFM’s take snapshots of fluid velocity along one or more sample paths.

• The number of snapshots are equal in number to the sample frequency for the sample period.

• Variations in velocity along each path are random as turbulent eddies and variation in local flow that produce them are entirely random.

• As a result the output from an ultrasonic meter will produce a greater degree of data scatter due to their ability to measure minute variations in velocity.

• Turbine Meter • Sees all of the flow

• Local turbulence is averaged by the rotor

• The rotor can turn at only one rate

• Little data scatter due to inherent inertia of the measurement element

• Uniform pulse train

Ultrasonic Meter • Samples the flow at 4 chord

locations

• Local turbulence is averaged by many samples

• Short term repeatability is a function of turbulence

• Data scatter due to ability to measure minute variations in velocity ie: turbulence

• Non-uniform pulse train

• Differences exist in flow dynamics between Turbine and Ultrasonic technology

Proving Liquid Ultrasonic Meters

Proving Liquid Ultrasonic Meters

Liquid Ultrasonic Meters are “manufactured pulse” type meters

There are two factors which can affect proving results.

– Proving accuracy can be affected by any delay in pulses due to processing speed of the transmitter

– Ultrasonic meters produce a non-uniform pulse output and have a varying frequency. This can cause difficulty in obtaining acceptable repeatability while proving

Proving run repeatability is used as an indication of whether the proving results are valid

Proving run repeatability may not fall within the typical 5 run, 0.05% span of repeatability, however proving runs shall repeat within the API Ch 4.8 and Ch 5.8 guidelines

Uniform pulse output – Turbine meter Frequency normally very constant

Non-uniform pulse output – Ultrasonic meter

Frequency variation due to ability to measure minute variations in velocity

API Guideline to Proving Runs

API Chapter 4.8, Table B-1 recognizes that an increase in proving runs may be needed in order to achieve a ±0.027% uncertainty of meter factor

Table B-1 – Proving an Ultrasonic Flow Meter

+/- 0.027% 0.22% 20

+/- 0.027% 0.21% 19

+/- 0.027% 0.20% 18

+/- 0.027% 0.19% 17

+/- 0.027% 0.18% 16

+/- 0.027% 0.17% 15

+/- 0.027% 0.16% 14

+/- 0.027% 0.15% 13

+/- 0.027% 0.14% 12

+/- 0.027% 0.13% 11

+/- 0.027% 0.12% 10

+/- 0.027% 0.10% 9

+/- 0.027% 0.09% 8

+/- 0.027% 0.08% 7

+/- 0.027% 0.06% 6

+/- 0.027% 0.05% 5

+/- 0.027% 0.03% 4

+/- 0.027% 0.02% 3

Uncertainty Repeatability * Runs

Low Counts) X 100 Counts – Low Counts) / Repeatability = ((High

* per API MPMS Ch. 5.8, Table A-1 to achieve +/- 0.027% uncertainty of meter factor.

1st prover detector

Final prover detector

1st prover detector

1st prover detector



1200.1234 interpolated pulses



22,887.9017 interpolated pulses



Turbine Meter

Ultrasonic Meter

Repeatability 0.011%

Repeatability 0.23%

Increasing the number of pulses does not necessarily improve repeatability

Proving Results – Pulses

1st prover detector

849,313 whole pulses

Repeatability 0.017%


849,457 whole pulses

Ultrasonic Meter Run # 1

Ultrasonic Meter Run # 2

Increasing proving volume improves Liquid USM repeatability

Proving Results - Pulses

Proving Volume is Important

The number of pulses generated during a prove is not the issue

The proving volume is important in order to achieve a successful prove on a LUSM

The critical issue is the proving not the prover

Use Master Meter – Prover combination or a prover with sufficient volume

5 Runs 0.05%

8 Runs 0.09%

10 Runs 0.12%

Meter Size (in.)4 33 15 106 73 34 228 130 60 4010 203 94 6212 293 135 8914 399 184 12116 521 241 158

Prover Volume vs. Meter Size

Prover Size (bbl)

Table B-2 – Suggested Prover Volume to obtain +/- 0.027% Uncertainty of Meter Factor

API Chapter 5.8 2005 edition

Proving LUSM – Master Meter - Prover

• In-situ prover – master meter combination is accepted and recognized as a valid method to prove Liquid Meters • Small volume Prover or Ball Prover used in combination with a master meter • Master Meter is calibrated against prover in-situ under actual operating

conditions • Master Meter proving is recognized by API and described in the standard API

MPMS Chapter 4.5 • This methodology allows for longer proving cycle to improve meter repeatability • Eliminates uncertainties due to laboratory calibration of master meter on different

fluids at different operating conditions

Compact Prover 1,000 : 1 Turndown

Small size / Light weight

Utilizes precision optical detectors

Pulse interpolation reduces pulse collection

Volumetric and/or Mass proving

Prover proves the master meter which proves the pipeline meters

Densitometer and Master Turbine Meter incorporated to prove mass flow meters

Master Meter

Master Meter Proving Using Small Volume Prover

Field Proving

Field Proving of Liquid USM

Prover-Master Meter Proving Procedure Establish flow through the prover loop and verify the integrity of double

block and bleed valve Adjust pipeline flow rate to desired setting and verify temperature stability

between line meter and prover loop Prover the master turbine meter with prover to meet uncertainty

+/- .027% or better uncertainty of meter factor Reconfigure prover electronics for master meter prove operation using

new K-factor of master meter Prove UFM (line meter) with master meter to +/- .027% or better

uncertainty of meter factor (recommend minimum 2 minutes per run) Re-prove master turbine meter with prover to verify K-factor has not

changed more than 0.02% from initial prove The above sequence is repeated for every flow rate tested OR if the

reprove of the master meter shows a change in K-factor greater than 0.02%

Field Results

Field Results – Prove Direct Against SVP

In-situ Master Meter Proving

• 10 repeats per flow rate averaged, each proving run 1 minute duration – NO flow conditioning

0.985

0.990

0.995

1.000

1.005

0 2000 4000 6000 8000 10000 12000 14000 16000

Flow Rate (BPH)

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Rep

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In-Situ Master Meter Proving

• 10 repeats per flow rate averaged, each proving run 2 minutes in duration – NO flow conditioning

0.990

0.995

1.000

1.005

1.010

0 2000 4000 6000 8000 10000 12000 14000 16000

Flow Rate (BPH)

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Increasing proving run volume improves repeatability

Master Meter Proving Using Small Volume Prover

• 24” high temperature Small Volume Prover configured to prove Liquid Ultrasonic Meters (6” to 10”) on crude oil pipeline in Northern Alberta, Canada

• 10” Multi-Viscosity Turbine Meter as master meter

• Major Oil Companies have this methodology in practice today

Proving Considerations Due to this frequency variation consideration must be

given in selection of proving methodology As a general rule the longer the proving cycle the more

repeatable the results

While proving a range exceeding 0.05% in 5 runs does not mean that a UFM is defective

Goal is to achieve +/- 0.027% meter factor uncertainty at a 95% confidence level

Rangos del Compact® Prover

Summary • While proving Liquid Ultrasonic Meters the Goal should be

to achieve +/- 0.027% meter factor uncertainty at a 95% confidence level

• Advancements in electronics and flow conditioning are resulting in proving volumes becoming smaller

• Successful field proving can be achieved providing proper consideration of proving methodology is given

• Customers today are proving their meters in the field and reporting excellent results using the small volume prover/master meter method

LNG Introduction Expenditure on LNG facilities expected to be worth

$111bn over the 2010 – 2014 period (Douglas Westwood Ltd, 2009)

Expenditure in FLNG facilities expected to be worth $23bn over the 2010 – 2016 period (Douglas Westwood Ltd, 2009)

Energy Industries Council (EIC) database lists 333 projects that either planned or currently underway in the LNG / FLNG arena

Financial transactions are huge – Typical LNG system moves circa $4M / Hr of gas during loading / unloading

Measurement accuracy ties directly to financial exposure / risk on the transaction - Optimizing the measurement system is extremely important

Cost of Uncertainty – Why Measurement Matters

Data shows typical LNG flowrates

Measurement uncertainty ties directly to $ throughput

Financial risk quickly builds with poor measurement

Mass Flow (Kg/h) 3,122,000Volume Flow (scf/h) 247,350Pressure (barg) 17Temperature (degC) -170Density (kg/m3) 446Henry Hub Price ($/1000cf) 4.3Financial Transaction ($/h) $3,828,975

Process Data

Measurement Uncertainty 0.20% 0.40% 0.80% 1.00% 1.50% 2.00%Financial Risk ( +/- $/h) $7,658 $15,316 $30,632 $38,290 $57,435 $76,580

Financial Risk Associated With Measurement Accuracy

Minimizing measurement uncertainty is extremely important

LNG Overview

LNG is predominantly methane that has been cooled to below -160°C at atmospheric pressure

Natural gas is liquefied at an export terminal and is then transported to import terminals in large purpose built ships. The LNG is then regasified at a plant at the import terminal for supply to the national distribution network

Measurement of the quantity of LNG delivered to or received from a ship’s tanks is currently made in the form of energy transferred

Two Approaches to LNG Measurement

Static Measurement (Current Approach) – Tank Gauging

Dynamic Measurement (New Approach) – Flow Metering

Both approaches have advantages and disadvantages

Current Approach to LNG Measurement – Measuring LNG Volume

Measuring the LNG volume in the ship’s tank requires – Equipment for measuring the liquid level in the LNG

tank

– Calibration tables

• Main Gauge Tables

• Correction Tables for List, Trim and Tank Contraction

– Level instrument specific correction tables

– Temperature probes distributed over the height of the LNG carrier tanks

– Pressure measurements within the tank

Challenges with Current Approach Uncertainty is difficult to define for the various

correction tables for vessel list and trim

Selection of the differing level gauge technologies (different advantages and disadvantages)

Maintaining accuracy and avoiding drift in temperature elements

Accurate sampling to ensure a homogeneous sample of LNG

Estimation of tank deformation under the weight of LNG

Future Approach to LNG Measurement 1 (Dynamic Measurement) Dynamic measurement is the

determination of flowrate and then integrating over a period of time to get a total volume passed

Measuring the flowrate of LNG volume requires – Primary element flow meter

– Upstream meter runs

– P&T instrumentation

– Calibration or proving methodology

Challenges with Dynamic Measurement Unsteady fluid – LNG is stored and transported at

temperatures close to its boiling point. May become two phase if

– There are hot spots on the pipeline

– There is excessive pressure drop in the system

Conducting a flow calibration of the meter at conditions similar to operating conditions

– There are no large scale cryogenic flow laboratories

Verifying the performance of the meter once installed

– A methodology or mechanism is required for in-situ proving

Model 3818 Mechanical Packaging 8-path design for redundancy and

profile immunity without flow conditioner

Proprietary meter insulation package

Minimal contact points to meter body to minimize heat sinks and hot spots

Correction model for changes in meter geometry due to temperature delta from CMM to site

Proprietary cable routing design

Termination of cables redesigned for cryogenic temperatures

Transducers can be field replaceable

30” LNG Meter LN2 Testing

Overcoming Challenges – Meter Calibration As a fluid flows inside a

pipeline it does not have the same velocity across the entire diameter. The flow profile depends upon: – Viscosity of the fluid – Density of the fluid – Mean flow velocity – Pipe inner diameter – Upstream pipeline

configuration – Interior pipe wall

roughness – The parameters are

combined using the Reynolds number, Re

Often LUSMs are flow calibrated on water and performance is characterized as a function of Re

LNG viscosity is much lower than water. For a given flow rate, Re is circa 5 x more than water

There is an unquantified additional uncertainty associated with extrapolating the calibration

µρUD

=Re

Proposed Solution Establish industrial scale LNG calibration facilities

– Costly and complex

– Still does not fully solve the issue due to the potential installation effects in the field relative to the lab

Develop a mechanism for in-situ proving

– Provides a method to directly calibrate meters in LNG applications

Patent application M&C07000 (filed 4/29/09) “Meter Prover and Method for Direct Proving at Cryogenic Temperatures”

– Patent covers: Sensors, target ring material and attachment method, piston rotator, flow tube finish, seal material

In Situ Proving – Cryogenic Prover Concepts evolved from bi-

directional piston provers

Free floating piston

Honed prover barrel

Daniel major supplier of piston and conventional provers for many years

Meets API repeatability criteria

Special design details applied for LNG for operation at approximately -260⁰F (-162 ⁰C)

US and PCT Patents pending

Automación de Terminales

Truck Loading

Ultrasonic

Electronic Preset

+ =

Turbine

Coriolis

+ Control Valve

INPUTS Permissives

Additive Selection Recipe Selection

Auto/Manual Alarm Reset

Terminal Automation Temperature Probe

Pressure Sensor Densitometer

OUTPUTS Pulse Per Unit Volume Trip Recipe Selections Component Combination Alarms Valve Control Ticket Printing Meter Proving Terminal Automation

A P D

M

T

From Product Pump

Strainer Block Valve Meter: PD Coriolis Turbine

Control Valve

A P Additives Pressure Transducer

T D Temperature probe Densitometer

TAS

Typical Loadrack Preset Configuration

Coriolis Meters Advantages

– Multiple Measurement • Mass, Volume, Density

– No maintenance

– Factor Stability

788 Digital Control Valve

788 DVC Solenoid Operated Valve – Provides precise Flow Rate Control

and Batch Delivery when used with an Electronic Batch Control Device

– Eliminates indicator stem and micro switch - no leakage path

– Positive “bubble-tight” shut-off – Automatic check – no reverse flow – Fails safe on power loss – Linear response with smooth ramp-

up/ramp-down – Balanced Piston design – Serviceable without removal from line – Easy to install – minimal setup and

maintenance requirements

Daniel Liquid Turbine Meters: Series 1200

Designed for Load Rack Applications

1” to 4” ANSI 150 or 300 lb

Bearing Options – Stainless steel ball-bearing

assembly for light duty

– Tungsten carbide bearing assembly for severe service

– Carbon or Stainless Steel Housing

(1) or (2) pickoffs available

Dual output preamplifier

Field retrofitable

700 Series Valve Model 788 Digital Control

Valve

The solenoids are energized and de-energized independently or simultaneously to automatically position the valve to control Hi-Lo flow rates or to close

700 Series Valve 788 DVC Electrical Digital Control Valve

Provides precise Flow Rate Control and Batch Delivery when used with and Electronic Control Device

Closed Position Open - No Control Open - Control Position

700 Series Valve 788 DVC Electric Digital Control Valve Typical

Installation

788 DVC Electric Digital Control Valve

Truck loading applications

700 Series Valve

DL8000

Optional Entry/Exit Data Entry Terminal

Windows Clients Host Interface

COMMS CABINET

TAS

System Printers BOL

Logger Reports

Optional Data Entry Terminal

Typical Load Rack

RS-485

Communications

Ethernet TCP/IP (External Customers)

Additive Control

Truck Grounding

Vapor Recovery

Optional

Typical Terminal Configuration

The Proof - Truck Loading

Modernization and automation of 4 loading island terminal for Total, The Netherlands

Full mechanical construction and loading arms, E& I installation.

Provided higher product throughput, increased security and safer operation

Metering System

Liquid Measurement Station Design

Documents

Transcript of Liquid Measurement Station Design