Article onTG & Review Of Errors.doc

Tank Gauging In Refinery&

Review of tank measurement errors reveals techniques for greater accuracy.

1. Introduction

Tank gauging is a common source of error in custody transfer measurements of hydrocarbons. Although the accuracy of tank gauging has improved markedly over the last century, several sources of error still exist. This article traces the history of tank measurement accuracy, reviews the sources of measurement errors, and recommends procedures to increase measurement accuracy.

2. Measurement history

In the 1860s, oil measurement accuracy was +5% and the price of oil ranged from $5 to $10/bbl. In 1866 oil producers agreed to give buyers an allowance of 2 gal for every 40 gal gauged, to cover spillage, evaporation, and measurement errors. In other words for every 40 gal of crude oil purchased, the buyers received 42 gal (This is the origin of the 42 –gal barrel).

In the 1960s crude oil sold for $1-2/bbl and custody transfer accuracy was about –0.5%. This loss was caused mainly by errors in temperature measurement, sampling, sediment and water analysis.

During this decade, the buyer paid for 200 gal of crude oil and received 199 gal. This level of accuracy was built into most of the 1965 API measurement standards. The loss was accepted by buyers and sellers.

By the late 1970s, the price of crude oil had risen to $20-30/bbl. In many cases, the seller was a government and the buyer was an oil company. The oil company’s profit was a small fraction of the value of crude oil, and the 0.5% loss was significant.

Oil company made a concerted effort to improve the accuracy of oil measurement and to avoid measurement losses. As a result, the API manual of petroleum measurement standards (MPMS) has been rewritten entirely since 1070s. Today, if tank-gauged custody transfer is performed according to state-of-the –art procedures, accuracy 0f 0.25% can be achieved . With today’s accuracy, a producer receives 399-401 bbl for every 400 bbl purchased.

3. Measurement uses

Tank measurements are taken for three purpose:

Operations

This requires the least accuracy. The main purpose is to avoid overfilling or emptying a tank

Inventory control or stock accounting

This requires an intermediate level of accuracy. Accounting and loss-control programs work better with accurate measurements, but there are timing problems associated with measuring

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Special Assignment 2001-2002 Page 1 of 16 Setal Kalavadia & Himanshu DesaiCES InstrumentationDate : 11th May’2001-05-11

changing tank inventories. Many tank measurement errors cancel each other, especially when a large number of readings are involved.

Custody transferThis requires the highest level of accuracy because money is changing hands. Metering is the most accurate method of custody transfer. The use of ATGs for custody transfer normally requires mutual contractual agreement between the buyer and the seller and may be subject to state and local regulations. ATG used for custody transfer should provide facilities to allow sealing the calibration adjustment to prevent unauthorised adjustment or tampering.

4. Tank gauging systems

There are many tank gauging systems on the market. They are based on a variety of measuring principles. Only those five principles are described that are most suitable for refinery tank farm operation:

manual dipping servo radar hydrostatic hybrid

4.1 Tank dipping

Tank dipping is volume measurement. It is performed by lowering a tape covered with paste through the dip pipe of the tank and determining the ullage on basis of the location of the colour change of the paste.

It is the oldest way of tank gauging and in some countries still required for fiscalisation.

In some countries it is the only authorised way of fiscal metering.

Negligible capex (capital expenditure)

Labour intensive.

Accuracy at best + 2 mm which is twice as inaccurate as the other tank gauging methods.

4.2 Servo gauges

Its heart is a static force transducer, which continuously measures the apparent weight of the displacer, controlling the position of a grooved drum. Intelligent data processing, which compensates for drum diameter variations, for the weight of the measuring wire and for hydrostatic tank deformation, made it possible to achieve high accuracy in a relatively light and robust instrument.

Among the functionality's of the intelligent microcomputer based electronics is the remote availability of results of internal diagnostics, so that any malfunction can be detected timely. The main features of this instrument are:

Accepted in almost any country for custody transfer and fiscal metering Automatic calibration of top, bottom or reference position Self checking features with malfunction alarm Density and interface measurement (for clean products only)

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Level accuracy typically ± 1 mm. Interface accuracy typically ± 2 mm (for clean liquids only) Density accuracy typically ± 5 kg/m3 Low cost However: specialised maintenance required.

4.3 Radar gauges

In radar gauges the time delay between a transmitted and reflected microwave signal is used to measure the distance between the gauge and the liquid surface.

Modern electronics used for signal processing and automatic calibration make this principle a viable alternative for servo gauges. They were first developed for marine applications, because of unreliability and high maintenance efforts experienced with mechanical instruments on board of tankers.

Although still relatively expensive they are now also used in land applications because of the absence of moving parts and the fact that no contact exists between the instrument and the liquid. This makes them suitable for measurements of "difficult" products such as bitumen.

On floating roof tanks, where the radar beam is guided through a standpipe, considerable measurement errors can take place, because rust on the surface of the pipe attenuates the signals severely.

When the roof itself is used as a reflection point for the radar beam, the effects of liquid density variations will decrease the measurement accuracy considerably.

The main features of this instrument are:

No moving parts No contact with the liquid High level accuracy of + 1 mm Self checking features with malfunction alarm Measures direct ullage level and compensated innage level However: Acceptability for custody and fiscal metering still to be established in most countries Standpipe may give measurement errors due to stray reflections of signal

4.4 Hydrostatic tank gauges

An old principle that only recently became a viable alternative for level measurements is the hydrostatic tank gauge (HTG). When the hydrostatic pressure, measured near the bottom of the tank, is multiplied by the average tank area, the mass of the product is obtained.

With an additional sensor the product density can be determined and volume and level may be calculated as derived variables. Measurements and calculations can be done at high speed so that for all practical purposes the system is continuous.

In the past large scale applications of this principle were prevented because of the insufficient overall accuracy obtainable with conventional analogue pressure sensors.

Based on modern "smart" transmitters (transmitters with integrated microcomputers having accuracies of 0.05% or better and with digital signal transmission), HTG systems became practical alternatives. Exxon and Texas Instruments have pioneered the development of such systems. After they proved the viability of the method, Foxboro, Rosemount and others followed.

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Based on the transmitter accuracy's, theoretical accuracy's for mass, density, level and volume can be calculated. For mass measurement HTG systems have already proven to be far more accurate than legally required (about 5 times better than 0.5% which is the requirement of the Dutch Weights and Measurement authority).

An engineering guideline is the draft ISO standard for static mass measurement, which is in an advanced stage. Several field tests, witnessed by ISO representatives formed the basis for that document. The main features of this instrument are:

Accurate direct mass measurement ( + 0.1%)

Direct innage measurement

No standpipe required

Self checking features

Optional density measurement of the lower 2.5 metres

Optional level measurement

No moving parts

However:

Acceptability for custody and fiscal metering still to be established in most countries

Requiring perforation of tank wall

Relatively high cost of installation as compared to servo gauge.

4.5 Hybrid gauging systems

Hybrid gauging systems consist of a level gauge combined with one or two pressure sensors for hydrostatic height measurement. These systems are being developed.

Tests have already been carried out with promising results. Manufacturers of servo and radar gauges are working on integrating hydrostatic sensor information into their gauging systems.

The main features of these systems are:

Presentation of accurate mass and level data

Presentation of accurate average density information

Ability to cope with non cylindrical tanks for mass measurement

Increased availability of the measurement through redundancy in the information.

4.6 Suitability for different tank shapes and products

4.6.1. Shapes

The shape of the tank and the position of existing flanges can influence the gauge selection. For volume and for mass calculations the primary measurements have to be multiplied by the area of the tank. When the exact level is not known the resulting error in calculated mass or volume will be small for vertical cylindrical tanks but can be quite considerable for bullets or spheres.

In the case where radar gauges are envisaged, together with the use of existing mechanical connections on the tanks, the following conditions must be checked:

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A minimum distance is specified for radar gauges between the wall and the centre of the connection

If a stilling well is used, it must be vertical within 0.30 degree, straight, may not have too many slots and must be clean (no scale)

4.6.2. Products

The selection of the most suitable type of gauge is also influenced by product properties like viscosity, crystallisation, solidification and possible impurities.

For a brief overview we have grouped products in the following main groups: crude, white products, black products, asphalt and LPG. The suitability and limitations of the different gauging principles are given in the matrix below.

Radar HTG Servo

Crude + + +

White products + ++ +

Black products + + +

Asphalt ++ - -

LPG + -- (note 1) ++

note 1 : flanges on LPG tanks are not allowed

++ best choice

+ suitable

- possible with high maintenance

-- not advised

5. Installation of ATGs

The mounting location of an ATG may affect its accuracy after installation. For accuracy in custody transfer it is essential that the mounting location have minimal vertical movement with respect to the tank reference, which is the joint where the atnk shell and bottom meet, or the bottom corner.

Top Mounting without still pipeThe ATG may be supported on the roof of a fixed roof tank, this kind of mounting may cause the ATG to move vertically when the tank is field or emptied.

Top Mounting with a still pipe

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Figure 1 (a) shows an ATG mounted on a still pipe on a foxed roof tank. Figure 1 (b) shows an ATG mounted on a still pipe on a floating roof tank. Alternatively, the still pipe may use a trunnion supported by the bottom course of the shell, as shown in figure 2 (a) and 2 (b).

ATG mounted on properly supported still pipes , as illustrated in figure 1 and 2, deliver higher accuracy because the still pipe is supported on a stable location, and ATG movement is minimised when tank is filled or emptied.

The ATG should be located near the gauging hatch so that its accuracy can be easily checked by manual gauging. The ATG mounting and the tank reference point of the manual gauging hatch should be rigidly connected to avoid errors caused by differential movement.

Figure 1 – a Figure 1 - b

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Figure 2 – a Figure 2 - b

6. Calibration

6.1 For custody transfer

The purpose of calibration for custody transfer is to ensure that the ATG, as installed, can sense and indicate level over its measuring range as accurately as manual tank gauging that is properly performed. The following procedure apply to all types of ATGs to be used for level measurement of custody transfer.

The manual gauging tape used for ATG calibration should be a test tape certified by national institute of standards and technology .

At least five consecutive manual gauging should be taken, and the result should be averaged. The five consecutive manual gauging should agree within an error band of 3 mm.

The preliminary calibration should be done when the tank is approximately half full, and the ATG should be set to the average of five manual gauging.

The final calibration should be performed by verifying the ATG reading at three random test level in the top, middle, and bottom third of the gauge travel. Five manual gauge should be taken by experienced personnel. These five manual gauges should be taken consecutive at each level, by the same person using the same tape. These readings should be synchronised with five consecutive ATG readings read by another person at the same time.

The average manual levels and the average ATG levels should be compared at each of three test levels. If the average manual and average ATG level agree within 3 mm at all three

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levels, the ATG should be consider properly calibrated for custody transfer level measurement.

A regular verification program should be established for custody transfer ATGs. All essential components of the ATG installation should be checked as recommended by the manufacture’s instructions. Initially, each ATG should be inspected and its calibration verified at a single level at least once per month. If operating experience confirms stable performance within the calibration tolerance, the verification schedule can be extended to once per quarter.

6.2 For inventory control

Inventory control has less rigorous requirements for accuracy than custody transfer. Since inventory control is largely for internal use, the user can substitute more or less rigorous requirements.

Three consecutive manual gauging should be taken, and the result should be averaged. The three gauging should agree within an error of 6 mm.

The preliminary calibration should be done when the tank is approximately half full, and the ATG should be set to the average of three manual gauging.

The final calibration should be performed by verifying the ATG reading at three random test level in the top, middle, and bottom third of the gauge travel. Three manual gauge should be taken by experienced personnel. These three manual gauges should be taken consecutive at each level, by the same person using the same tape. These readings should be synchronised with three consecutive ATG readings read by another person at the same time.

The average manual levels and the average ATG levels should be compared at each of three test levels. If the average manual and average ATG level agree within 25 mm at all three levels, the ATG should be consider properly calibrated for inventory control level measurement

7. Measurement accuracy is influenced by

The quantity of oil in a tank can be measured manually or with automatic tank gauging (ATGs). Both methods involve a three-step process.

Determining the volume by measuring the level of liquid in the tank. This can be done by measuring either the “innage” (the liquid height) or the “outage” (the vapour space above the liquid)

Determining the temperature by measuring the average temperature of the liquid in the tank.

Determining the density by analysing a tank sample or a hydrostatic pressure transmitter.

7.1 Volume measurement

Regardless of the quantity of manual or automatic tank gauging, the accuracy of volume measurement is limited by the inherent imperfection of the tank.

A tank is not a perfect can. Filling a large tank causes the bottom to srink, the shell to bulge, and the roof or top course to drop. The shell dimensions also change with temperature. These small movements are neither predictable nor repeatable.

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The following accuracy limitations are listed in the new API MPMS standards for manual and automatic tank gauging.

Accuracy of the manual gauging tape or ATG +/- mm.

Accuracy of the tank capacity table.

Level accuracy is influenced by Roof movement.

A roof in a floating roof tank can simplified be illustrated with the figure below:

The figure resembles a hydraulic piston, and when the "roof" is pushed downwards the suspendedvolume will raise in the pipe/well. If the total area of the "tank" is A, and the area of the well is A1,the following simple relation will apply:

A * h = A1 * h1

Where h is the movement of the roof, and h1 is the resulting increase of the level in the well.

The example illustrates what happens in a floating roof tank when the roof not safely floats on the liquid surface. It is obvious, that the relation between A and A1 is important to determine how good h1 corresponds to the movement h. To get an answer the actual design of the roof is important.

The theory above is quite simple, and is used on all tanks to correct for the influence of a floatingroof. In this case the weight of the roof, and the density of the product determines the influenceof the level in a stillpipe and the effect on calculated volume.

Static deformation of tank shell. A full tank takes the shape of a wooden barrel.

The tank shell will be affected by the static pressure from the liquid, and it will typically show as a bulging of the lower part of the shell. The order of this bulging will depend on the filling height of the tank and the mechanical construction. The bulging will cause the tank shell to be less in height; i.e. the reference height will decrease with increasing filling height.

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Level Accuracy depends on how much the tank bulges within the grey area and then the reference height changes from R1 to RN. This can be adjusted by good hand dipping at several levels to correct the measurement (see Tank Adjustment record). You should then program this into the RTG.

RadarTankGauge

Ullage or Level Dip Hatch

R1

RN

Datum Plate

Reference height R1 up to RN

Level = Ref. H - Ullage

Under measurement due to tank bottom movement +/- mm. This varies with the compression strength of the soil under the tank.

Movement of the gauging well +/- mm.Floating roof tanks are normally tilted with slotted gauging wells. Vertical movement of the gauging well affects measurement of outage and causes an error when converting measured outage to innage. Radar ATGs measures outage and they often are installed on gauging wells. If the gauging well is improperly installed, these ATGs can not deliver their high potential accuracy. Chapter 3, Section B of the API MPMS describes how to support gauging wells properly for minimum movement.

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ULLAGE

LLEVEL

Movement of the datum plate affects innage measurements +/- mm

Thermal expansion of the tank shell and gauging well +/- mm.Thermal expansion causes two errors causes two errors because it affects both the tank diameter and the tank height. Tank capacity tables are calculated for one temperature. They do not correct for thermal expansion of the gauging well for floating roof tanks, or of the tank shell for cone-roof tanks. The amount of error depends on the product temperature and the ambient temperature.

Thermal effects of the tank wallThe tank wall will expand and contract depending on the temperature of the metal in the wall.This will of course effect the reference height and the level measurement. The levelgauges can compensate for this if a temperature system is installed in the tank. If a multispotRTD is installed, the level gauge will use all horizontally distributed elements to estimate thetemperature of product and the temperature of the vapour in the tank. These measurementswill then be used to correct for linear expansion of the tank wall.

Tank wall temperature influence in volume calculationThe Tank Capacity Tables (volume tables) are only valid for a certain calibration temperature (typically 20-30 degree C). To achieve a correct volume indication, these tables therefore must be corrected with the actual tank wall temperature. The temperature used for the correction is basically the same as used for estimation as above, i.e. the installed RTD’s are used.

Recently API has changed the recommended procedure for this correction, by also taking theoutside temperature into account.

Human errors.These are greater with manual gauging than with ATGs.

It is important to note that the errors are both positive and negative, and sometimes compensate for one another. In addition to the preceding, tank measurement is more accurate when tanks are full or nearly so. Measuring small parcels by tank gauging leads to serious errors, because the measurement errors account for a much larger fraction of the total volume.

7.2 Temperature Measurement

The errors caused by poorly measured temperatures are much greater than those caused by poorly measured levels. In fact, level measurement errors are the third leading cause of errors. A temperature error of 2.5deg F is the same as a level error of 0.1%.

Both manual temperature measurements and those made with automatic tank thermometers (ATTs) are in accurate.

Chapter 7, Section 1, the API MPMS standard for manual temperature measurement, recommends taking three readings for tanks taller than 10 ft. The standard also lists lengthy immersion times and an elaborate procedure for obtaining accurate manual temperature readings. Most users do not take the time to follow the standard and , as a result, record inaccurate liquid temperature.

There is a rule of thumb for estimating the size and direction of this error : A manually measured temperature will be in error by about one tenth the difference between the oil temperature and ambient temperature.

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The simple solution to this problem is to use a digital electronic thermometer, This devices measures oil temperature accurately and quickly. It reaches temperature stability in about 1 min and indicates when the reading is stable.

It should be noted that rule of thumb for manual temperature measurement was determind using a digital thermometer to measure the true oil temperatures after gaugers or inspectors measured inaccurate temperatures using cup-case thermometers.

Also ATT measurements are accurate, Chapter 7, Section 4 the API MPMS standard on automatic temperature measurement describes the required equipment.

When purchasing a high performance ATG to obtain accurate level measurements, one should choose an ATG that has automatic average temperature measurement. This adds about $1500 to the material cost of a level-only ATG system., but is well worth it.

As per IEC 751 the tolerance values for 100 ohms thermometers are as mentioned bellow.

7.3 Density measurement

The density of the product can be calculated and presented continuously with a pressure sensor at the bottom of the tank.

The tank gauge measures the level of the product with high accuracy. By mounting a pressure

sensor at the bottom of the tank, the density can be determined. The level of the product above the pres-sure sensor is known and the density of the product can be calculated.

The accuracy of the density calculation largely depends upon the accuracy of the pressure sensor.

ATG can interface to any pressure sensor with a standard output of 4-20 mA. The 4-20 mA signal is converted from analog to digital form in the ATG equipment with a resolution of approximately 0.025% (with a 12 bit A/D converter).

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Tolerance values as a function of temperature for 100 ohm

thermometer

0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

5

-200

0

200

400

600

700

850

deg C

+/-

deg

C

0

0.25

0.5

0.75

1

1.25

1.5

1.75

2

2.25

2.5

Ohm

Deg C

+/- O h m

When the measured density is used for calculating mass for custody transfer or for determination of product type, it has to be of very high accuracy . The price for this added feature in the system,

has to be compared with the cost of taking manual samples of the product and establishing the density in a laboratory. The density can be determined with an accuracy of 0.2%.

The accuracy of the online line density and mass measurement are shown in below graphs.

8. Inventory calculations

Gross or natural volumeThe gross volume is calculated by direct conversion from level to volume by use of strapping tables. There is a correction for floating roof tanks.

Water volumeIf available, the water level is converted into a water volume by using strapping tables. The water level is either measured or manually entered.

Net volumeThe net volume is calculated from the gross volume and Water volume:

Net volume = gross volume - Water volume

Volume Correction FactorThe Volume Correction Factor (VCF) is calculated from information of the appropriate American Petroleum Institute (API) table, the Density at 15 C, and the temperature of the product in the tank.

The VCF gives the density at observed temperature in relation to the density at 15 C.

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The standard API tables 54A, 54B, 54C and 54D are implemented. If either the temperature or the density is outside the valid ranges for the API tables, the VCF is set to 1.0.

Net volume at 15 CThe Net volume at 15 C is calculated from the Gross volume and the VCF with the formula:

Net volume at 15 C = Gross volume * VCF

UllageThe ullage is calculated from the gross volume and the maximum working volume. The maximum working volume should be consistent with the high high level alarm position.

Ullage = Maximum working volume - Gross Volume

Pumpable volumeThe pumpable volume is calculated from the gross volume and the minimum working volume. The minimum working volume should be consistent with the low low level alarm position.

Pumpable volume = Gross Volume – Minimum working volume

MassThe mass is calculated from the net volume at 15C and the density at 15C. Conversely with HTG, the mass is calculated from the hydrostatic pressure with corrections for floating roofs, atmospheric pressure and the liquid below the pressure transmitter.

Liquid products

For liquid products the product weight in air is defined by (using API table 56):

Net weight = Net volume at 15 C * (D15 - 0.0011 )

Gaseous products

For gaseous products the product weight is corrected with the weight in the vapour space. This weight is calculated from the measured Vapour pressure, Vapour Temperature, Gas Volume and Molar weight as follows:

Net weight = Net volume at 15 C * ( D15 - 0.0011 ) + Weight in vapor space

Density

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Density at temperature can be calculated by HTG using two liquid phase pressure transmitters or one transmitter and level in a hybrid HTG/level system

Density = (Hydrostatic Pressure – Static Pressure) / Liquid head above Hydrostatic PT

9. Measurement rules

More oil is mismeasured because of thermometer than because of tank level gauges.

Measuring small parcels of oil in large tanks is inaccurate.

Measuring outage is accurate only for measuring the vapour space above the oil. To determine the oil volume innage measurement is more accurate.

Using an unslotted gauging well is a measurement disaster. It gives inaccurate levels and temperatures and produces a non repersentable sample. It also makes it easier to overfill tanks.

10. API Standards

API’s tank measurement standards have been significantly revised since the 1960s to reflect the ten-fold increase in the price of oil. These revisions had three main goals:

To correct standards that contained significant measurement mistakes.

To outline procedures that permit custody transfer by automatic tank gauging rather than manual gauging.

To incorporate new, more-accurate procedures, laboratory tests, and measuring equipment.

Here is a brief summary of the current API standards

Chapter 3, section 1A, standard practice for the manual gauging of petroleum and petroleum products, was issued in 1994. It describes the uncertainties of tank measurement and includes a procedure for checking the calibration of gauging tapes.

Chapter 3, section 1B, Standards Practice for level measurement of liquid hydrocarbons in stationary tanks by Automatic Tank Gauging, was issued in 1992. It describes the accuracy limitation of tank measurements and provides installation, calibration, and verification procedures for different types of ATGs. It differentiates between custody transfer and inventory control measurement. It describes the gauging wells that are required for custody transfer with ATGs.

Chapter 3, Section 3, Standard Practice for level measurement of liquid hydrocarbons in stationary pressurised storage tanks by ATG, was issued in 1996.

Chapter 7, section 1, Temperature determination using mercury-in-glass tank thermometers, was reissued in 1991.

Chapter 7, section 3, Temperature determination using portable electronic thermometers, was issued in 1985, Digital electronic thermometers read the correct temperature in less than 1 min.

Chapter 7, section 4, static temperature determination using fixed ATT thermometers, was issued in 1993.

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11. Reference

Shell DEP 32.31.00.32-Gen

Shell best practices, Oil Movements Encyclopedia nos 16, 34 and 46

Oil & Gas Journal March 3, 1997

Special Reports from M/s Saab Tank Control Sweden.

API MPMS 3.1B

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