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PRODUCTION FUNDAMENTALS

Section 4 Crude Oil Metering and Export

Section 4

Crude Oil Metering and Export

4.1 Introduction 3

4.2 Pumps 3

4.2.1 Head 44.2.2 Net Positive Suction Head 44.2.3 Centrifugal Pumps 44.2.4 Specific Speed 5

4.2.5 Cavitation 54.3 Metering 54.3.1 Variable Head or Differential Meters 74.3.2 Pressure Tappings 74.3.3 Primary Elements 74.3.4 Turbine Meters 94.3.5 Ultrasonic Systems 94.3.6 Metering Systems 104 3 7 Meter Proving and Sampling 10


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Contents (Contd)

Figures

4.1 Liquid Metering and Export Overview

4.2 Pump Characteristics

4.3 Pump Head

4.4 Centrifugal Pump

4.5 Pump Type Classification

4.6 Flow Versus Differential Pressure

4.7 Principle of Orifice Plate

4.8 Square Based Orifice Plate with D and D/2 Tappings

4.9 Turbine Meter

0 M i d S li Skid


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4.1 Introduction

The crude oil metering and export system on an offshore installation is the section of plantwhich is situated between the final stage of separation and the point of sale, that is the pointat which petroleum revenue tax (PRT) is liable.

Normally this system consists of the following:

Booster pumps

Fiscal metering

Oil sampling

Main oil line (MOL) pumps

Pig launch/receiving facility

Export pipeline

A typical crude oil metering and export system is shown in Figure 4.1.

Booster pumps are designed to raise the pressure of the oil to that required in order to


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It follows that, for a given speed of rotation, a positive displacement pump will move a fluidat an almost constant flowrate, irrespective of the pressure required to pass that fluidthrough the system; it will operate independently of the system to which it is connected.A centrifugal pump, on the other hand, will generate a dynamic head and pass a flowratewhich depends on the system.

We can therefore describe the operation of the two different types of pumps graphically asshown in Figure 4.2. These are the idealised characteristics (more correctly, the head/flowcharacteristics) of the two types of pump.

4.2.1 Head

The head generated by a pump is the difference between the pressure at the pump suctionand the pressure at the pump discharge. The pumping industry tends to speak in terms of

head, rather than pressure.

The relationship between pressure and head is shown in Figure 4.3. In general, the industrystandard is to work in terms of water.

4.2.2 Net Positive Suction Head

For all types of pump other than vacuum pumps, some head is required on the suction side

to force the fl id into the p mp itself This is kno n as net positi e s ction head (NPSH)


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4.2.4 Specific Speed

There are three basic types of impeller design for centrifugal pumps and the type of impellerto be used depends on the specific speed of the pump (refer to Figure 4.5).

High head, low capacity pumps will have a low specific speed, and high capacity, low headpumps will have a high one. Low specific speed pumps have radial flow impellers and high

specific speed pumps have axial flow impellers. It follows that the third type, the mixed flowimpellers, have specific speeds in the middle of the range.

4.2.5 Cavitation

The principal restriction to the use of pumps is that imposed by cavitation. Cavitation occurswhen the suction pressure at the pump inlet becomes lower than the vapour pressure of the

liquid (essentially the boiling of the liquid), due to low pressure rather than high temperature.

This in itself is quite harmless, but the function of a pump is to increase the pressure of theliquid. Here the vapour phase cannot exist and the bubbles collapse back to a liquid. Thereis then a tiny void, or cavity, created in the liquid which then tends to rush in from all anglesto fill the cavity. The inrushing liquid can impart large forces and, when bubbles near metallicsurfaces collapse, these forces are applied to the solid surface. This process is beingrepeated many thousand of times each second and the effect results in noise, vibration andeventual erosion of metal from the surfaces. More importantly, severe cavitation can result in


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The fourth objective is to ensure that no loss of product has occurred. The sum ofmetered offshore product together with losses or gains due to drafting or packing of thepipeline, is compared regularly with onshore metered product for this purpose

Metering and sampling is given a high priority accordingly. The priority is so high that themeters themselves must be checked regularly. This may be done using a meter prover, apermanent installation through which oil may be diverted to prove the meters.

Sampling

In Figure 4.10 a side stream is removed from the inlet header by sample pump GJE07A.

This side stream flows to two continuous sampling devices (SMP725A and SMP725B) wherea small continuous sample is removed and stored in sample drums. These samples arebacked up by one litre spot samples which are taken manually at 0700 hours and 1900

hours on a daily basis.

The sample pump discharges to two densitometers (DT1464 and DT1465) and a BS&Wanalyser before returning the side stream back to the inlet header.


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The most common method of measuring flow is the differential pressure device which usesrestriction elements (orifices, venturi etc) in a line. In this case, flowrate is proportional to thesquare root of the pressure drop through the restriction. It is popular because it has nomoving parts and is very accurate if calibrated and maintained correctly. However, there areother flow instruments available and these include turbine meters, positive displacementmeters, ultrasonic flowmeters and metering pumps.

Most flowrates are determined indirectly by measuring a particular property and then relatingthis to known behaviour determined beforehand, for example in a calibration laboratory.

Indirect methods of flow measurement include:

The head type (inferred from a pressure drop across a restriction)

Turbine meters (inferred from a speed of rotation)

Ultrasonic meters (inferred from the speed of a sound wave)

The variable area or a rotameter type (inferred from measuring the position of a floatresulting from a balance of weight against a velocity)

4 3 1 V i bl H d Diff ti l M t


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Directly between flanges in the line

In a carrier ring which is then fitted between line flanges

As an integral unit in a length of pipe which is then inserted into the pipeline (meter run)

The orifice assembly may be constructed as a single unit together with its pressure tappings

and a piece of machined pipe which is inserted into the pipeline. The lengths of pipeupstream and downstream of the orifice flanges should be long enough to ensure that theflow entering the device is steady and not full of eddies which would affect the accuracy ofthe meter.

High accuracy can only be obtained when the orifice plates are designed and fabricated withthe greatest of care, when the orifice flanges and pressure tappings are properly made andfinished and when the orifice plate is properly installed.


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The installation of the orifice plate should be carried out according to the following rules:

The plate should be installed such that the squared and sharp edge is at the upstreamside

The plate should be centred in the line

Gaskets of the correct thickness should be used and inserted in such a way that they donot protrude at any point inside the pipe

An adequate amount of straight pipe should be available upstream of the orifice so that anormal velocity distribution exists near the orifice assembly

4.3.4 Turbine Meters

Turbine meters consist of a straight flow tube within which a turbine or fan is free to rotate(refer to Figure 4.9). The flowing stream causes the turbine to rotate at a speed proportionalto flowrate. In most units, a magnetic pickup system senses the rotation of the turbine rotorthrough the pipe wall and, in some cases, two pickup coils are mounted so that they may becompared for accuracy in the number of pulses generated. As each blade passes themagnetic pickup coil, an electric pulse is generated, each pulse representing a knownamount of flow.


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4.3.6 Metering Systems

So far, we have looked at the various devices available for measuring actual flows. The useof these devices to determine mass or standard flows depends on the temperature andpressure of the measured fluid remaining constant. In practice, the pressure andtemperature, and sometimes the density, of the fluid will change as its flow is being

measured. To compensate for these changes, readings of the temperature, pressure anddensity if required, are taken and fed, along with the data from the flow measurement device,into a computer which can then convert the actual flow into a mass flow.

A typical metering run (refer to Figure 4.10) will contain the following:

Line filter with differential pressure gauge

Thermal relief PSV

Flow straightener

Turbine meter with dual pick-ups

Resistor type temperature element

Twin seal positive isolation valves


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Metering and Sampling Systems

On most systems the crude oil passes through a pump to raise the pressure prior tometering and sampling and thereby ensure that there is no gas breakout.

Further reasons for the location of meters and samplers in this position are:

No further processing of the fluid occurs and therefore the fluid sampled and meteredhere is representative of the fluid being exported

Metering takes place downstream of water removal

At water percentages greater than 1%, serious discrepancies can occur in meter accuracy.


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4.5 Pipelines

Pipelines are the most common means of transporting oil or gas. Refer to Figure 4.14.

A pipeline is like any other flowline. The main differences are that pipelines are long andcontinuously welded, they have a minimum number of curves, they have no sharp bends,and they are most often either buried or otherwise inaccessible due to their location over the

majority of their length.

A pipeline is extremely expensive to lay and, in the case of offshore pipelines, costs in theorder of several million pounds per subsea mile have been encountered.

Maintenance on pipelines is also expensive, but this expenditure is necessary since,regardless of the expense, pipelines frequently form the most efficient and cost effectivemethod of transporting the quantities of oil or gas produced. Pipeline sharing agreements

may result in the flow from a number of oil fields being transported through a single pipeline.A problem in a pipeline of this type can mean the shutdown of all of these fields with aresulting operating loss of several million pounds per day.

4.5.1 Pipeline Design

When designing a pipeline, the engineer considers the following factors:


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4.5.3 Heavy Crudes

Some crudes with very high pour points or high wax contents require pipelines ofspecial design.

Accommodating such crudes can be especially troublesome offshore where heat loss to the

water is great and any heat added to the crude before it enters the pipeline is dissipatedwithin a short distance if a conventional pipeline is used. If the crude cools, excessive waxdeposits in the pipeline can lower operating efficiency. In cases of extremely viscous crudes,flow can even be halted if the temperature is allowed to fall too low. Not only is the halting offlow a problem, but restarting flow after such an occurrence can be difficult.

To handle these special crudes, pipelines have been successfully installed and operatedsimply by insulating the pipelines, but other approaches include:

Heating the crude to a high temperature at the inlet to the pipeline, allowing it to reachits destination before cooling below the pour point. (The pipeline may or may not beinsulated)

Pumping the crude at a temperature below the pour point using high pressure pumps

Adding a hydrocarbon dilutent such as a less waxy crude or a light distillate


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In view of this, flow regimes can exist which are considerably more complex than thosealready discussed.

The key difference between single-phase flow and two-phase flow is that it is much moredifficult to determine pressure drops for two-phase flow. This is complicated if you considerthat a difference in incline of several degrees, never mind 90, can change entirely thenature of the flow regime.

Well flowlines often work in a two-phase regime, particularly because the well fluids usuallycontain both oil and gas and there may be no facility at the wellhead (eg at subsea wells)prior to the fluid reaching the gathering station (or platform).

Despite the problems associated with the prediction of two-phase estimates, more and morepipelines are being designed for such flow systems.

For example when hydrocarbon condensate is separated from the gas at offshore platforms,it is invariably spiked back into the gas for transportation to the shore in the pipeline. This ismainly because the economics would not support a separate line for condensate sales.

In both vertical and horizontal directions, the avoidance of slug flow is desirable. Slug flowmight possibly be avoided by choice of a smaller pipe diameter. This will increase fluidvelocities and reduce the pipeline liquid inventory.


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4.6 Pipeline Pigging

Pipeline pigs and spheres are used for a variety of purposes in both liquids and natural gaspipelines. Pigs and spheres are forced through the pipeline by the pressure of the flowingliquid. A pig usually consists of a steel body with rubber or plastic cups attached to sealagainst the inside of the pipeline and to allow pressure to move the pig along the pipeline.

Different types of brushes and scrapers can be attached to the body of the pig for cleaningor to perform other functions. Figure 4.15 illustrates a variety of pipeline pigs.

Pipeline pigging is done for the following reasons:

To clean up pipelines before use (foam pigs)

To fill lines for hydrostatic testing, dewatering following hydrostatic testing, and drying andpurging operations (spheres and foam pigs)

To periodically remove wax, dirt and water from the pipeline (scraper pigs and brush pigs)

To sweep liquids from gas pipelines (spheres)

To separate products to reduce the amount of mixing between different types of crude oil


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Pigs and spheres travel at about the same velocity as the fluid in the pipeline and travelspeed is relatively constant.

4.6.1 Pigging Operations

Pigs are used in all types of pipelines to increase efficiency and avoid problems at pump orcompressor stations that could result from the presence of unwanted materials. Brushes andscrapers on a cleaning pig remove dirt and wax from the pipeline walls. Brush and scraperpigs feature longitudinal holes which pass through the body of the pig. The holes allow a flowof fluid through the pig to prevent the buildup of wax or debris in front of the pig.

Very large amounts of debris can be removed by a pig if it is run over a long distance.

For example, assume a pig is run in a 24in pipeline, 100 miles long, and removes 0.016in ofwax material from the wall of the pipeline. After 100 miles, a plug about 1,450ft long wouldform. For this reason, pipelines are operated to very definite pigging programmes.

Pipelines are often pigged first during testing following construction. Most pipelines aretested with water (hydrostatic testing) either in sections or over the entire length. A foam pig,or pigs, is normally sent ahead of the water when filling the test section to prevent mixingthe test water with air in the line. Internally coated pipelines are often flushed with waterahead of a pig to prevent debris from being dragged along the inside surface, damagingthe coating.


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Combination pig and sphere launchers can also be designed if both cleaning pigs andspheres for liquid control are needed.

Pig launching and receiving procedures are often supervised by senior operations staffand fully monitored by all pipeline users but the actual procedures laid down for each piglaunching/pig receiving facility will vary.

4.6.3 Pigging Problems

The pig launcher/receiver is probably the only high pressure vessel on the facility, inhydrocarbon service, which is regularly opened to the atmosphere and then pressured as anormal operating procedure.

If the launcher/receiver is incorrectly purged and pressured, an explosion becomes a majorpossibility. To reduce the chances of such an incident, the relative procedures are commonlybacked up by an interlock system which prevents the movement of valves and door closingdevices until certain criteria have been met within the system. Figure 4.19 illustrates the logicof a simple interlock system.

In the last decade at least two launchers have been involved in major explosions in Britain.

When pigs are launched into a pipeline there is always the possibility that the pig will stopor reduce the flow of fluid through the pipeline. The most common incidents and their


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The pipeline has been dented and the pig is stuck at the damaged section

The pigs leapfrog each other in the pipeline (usually foam pigs). The possiblecauses are:

The operator launched them 1, 3, 2 but did not realise (most common)

The front pig hangs up on an obstruction and is only cleared by the second pig rollingover it

Whatever the causes of pigging problems, the effects can be severe and in some instancesthe pipeline has had to be cut to remove the offending pig.

Note: Treat all pigging activities as a potential hazard to production.

4.7 Gravity Based Storage and Export

Refer to Figure 4.21

Oil is stored in the Gravity Based Storage (GBS) which is located on the seabed. The systemconsists of several tanks, each of which is sub-divided into compartments, which are againsub-divided into cells. Stabilised oil is supplied to the GBS via pipework leading down from


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Fig 4 .1 Liquid Meter ing a nd Expo r t Over v iew

P R O D U CTIO N F U N D A M EN TA LS

ODL04_01

XV

XXV

XXV

XXV

XXV XV

XV

FCV

LCV XXV

XV

XV

XV

FC

V

XV

XXV XV

LCV XXV

FCV

XVXXV

LCV XXV

XV

XXV

XXV

XXV

PCV

XV

XV

LP SEPARATORS

MOL BOOSTER PUMPS

MOL PUMPS

OIL EXPORTMETER/

PROVER UNIT

FIC

FIC

PC

FIC

FIC

FIC

HIC

HIC

HIC

FROM HPSEPARATOR

FROM HPSEPARATOR

SPEED CONTROL

SPEED CONTROL

SPEEDCONTROL

PDT

PCVXXV

XXV

XXV

FCV

FCV

FCV

FIC

LIC

LIC

OIL EXPORT

PDC


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Fig 4 . 2 G e n e r a t io n , M i g r a t i o n a n d A c cu m u l a t io n o f H y d r o ca r b o n s


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FLOW

CENTRIFUGAL

POSITIVE DISPLACEMENT

HEAD


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Fig 4 . 3 P u m p H e a d

SUCTIONHEAD

TOTALHEAD

DISCHARGEHEAD

BY USING PRESSURE INDICATION AT SUCTION ANDDISCHARGE OF THE PUMP,

THE PUMP HEADS CAN BE CALCULATED AS SHOWN ON THE RIGHT

23ft

23ft

46ft

SUCTION HEAD =10

0.433= 23ft

DISCHARGE HEAD =20

0.433= 46ft

TOTAL HEAD =DISCHARGE HEAD MINUS SUCTION HEAD

= 46 23 = 23ft

1 CUBIC FOOT OF WATER (6 1/4 gallons) weighs 62.4 lbs

1ft1ft

1ftH20 = = 62.4 lbs mass

A COLUMN OF WATER MEASURING 1in x 1in x 1ft HIGH WILL HAVE A MASS OF :62.4

12 x 12= 0.433 lbs

A COLUMN OF WATER 1ft HIGH WILL EXERT A PRESSURE OF 0.433 lbs PER SQUARE INCH


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10psig

20psig


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Fig 4 .4 Cent r i fug a l Pum p


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DISCHARGE NOZZLE

IMPELLER

CASING WEAR RING

IMPELLER WEAR RING

EYE OF IMPELLER

CASING

VANE

SHAFT SLEEVE

SHAFT

PACKING

PACKING BOX


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Fig 4.5 P um p Typ e Cla ssif ication

IMPELLER CONFIGURATION PUMP TYPE SPECIFIC SPEED (rpm)

RADIAL FLOW 500 5000

MIXED FLOW 5000 10000

AXIAL FLOW ABOVE 10000


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Fig 4 .6 Flow Versu s Dif fe ren t ia l Pressure


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100 20 30 40 50 60 70 80 90 100

10

20

30

40

50

60

70

80

90

100

20

30

40

50

60

70

80

90

100

10

00

% DIFFERENTIALPRESSURE

% FLOW EXPRESSED ASDIFFERENTIAL PRESSURE

%Q = (%p) x10

% FLOW


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Fig 4.7 Principle o f Orifice Plate


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FLOWVENACONTRACTA

EDDIES

EDDIES

VENACONTRACTA

P1 P2 P3

PRESSURELOSS

DIFFERENTIALPRESSURE

EDDIES

EDDIES


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Fig 4 . 8 S q u a r e B a s e d O r i fic e P la t e w it h D a n d D/ 2 Ta p p i n g s


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FLOW

PRESSURETAPPINGS

D

D

D/2


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Fig 4 .9 Turb ine Meter


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FLOW

FLOW

DEFLECTOR RING

HANGERBLADE

HANGERHUB

SHAFT

NUT

COTTERPIN

HOUSING

CABLECONNECTOR

PICK-UPCOIL

THRUSTWASHER

BEARINGAND JOURNAL

DOWNSTREAMCONE WITH

THRUST WASHER

HANGER

BLADE

NUT

COTTERPIN

HANGERHUB

ROTOR

UPSTREAMCONE


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Fig 4 .1 1 Bid irec t iona l Prover Loop


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PRESSURETRANSMITTERS

OUTLET BLOCKAND BLEED VALVE

CONNECTIONSFOR MASTER

PROVER

MAIN LINEBLOCK AND BLEED

VALVE

INLET BLOCK AND BLEEDVALVE

FLOW

FOUR-WAYDIVERTER

VALVE

RESISTANCETHERMOMETERS

DETECTORS

DETECTOR SWITCHES

CALIBRATEDVOLUMES

OUTLET

INLET

METER PULSEPRE-AMPLIFIER

TURBINE METER

STREAM

FLOWCOMPUTER

DUAL METER PULSES

CORRECTED METERPULSES

DETECTOR PAIRCHANGEOVER SWITCH

PROVER CONTROLMICROCOMPUTER

SPHERE

AB

DC


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Fig 4 .1 2 Deta i ls o f Va r iab le Speed Coup l ing


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11

10

8

6

9

7 5 3 1 2 4 12

34

56

78

91011

- PRIMARY WHEEL- SECONDARY WHEEL

- SHELL- COUPLING HOUSING

- SCOOP TUBE HOUSING- OIL SUMP

- SCOOP TUBE- OIL PUMP

- AUXILIARY LUBE PUMP- OIL COOLER- DOUBLE FILTER


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Fig 4.1 3 Fluidrive Scoo p Trimm ing Coup ling


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OIL RESERVOIR

CASING

SCOOPCHAMBER

OILCIRCULATING

PUMP

SUCTIONPIPE

RUNNER

CONTROL LEVER

IMPELLER

SCOOP TUBE


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Fig 4 .1 4 P ipe l ine Roots


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Fig 4 .1 5 Type s of P ipe l ine P igs


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Fig 4.16 Intell igent Pig


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Fig 4 .1 7 Ca l ipe r P ig


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ODOMETER WHEEL

FINGER ASSEMBLY

CHART

STYLUS


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Fig 4 .1 8 P ig Rece iver


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Fig 4 .19 A Typ ica l Inte rlock Log ic


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INTERLOCK E(LAUNCHER/RECEIVER HIGH PRESSURE)

INTERLOCK A(DOOR CLOSURE DEVICE)

INTERLOCK B(BY-PASS VALVE POSITION)

INTERLOCK C(INLET/OUTLET VALVE POSITION)

INTERLOCK D(LAUNCHER/RECEIVER LOW PRESSURE)

PRESSURE NOT HIGH

PRESSURE HIGH

PRESSURE NOT LOW

PRESSURE LOW

VALVE CLOSED

VALVE OPEN

VALVE CLOSED

VALVE OPEN

DOOR CLOSED

DOOR OPEN

DOOR MAY BEOPENED

BY-PASS VALVEMAY BE OPENED

OUTLET VALVEMAY BE OPENED

AND

AND

AND


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Fig 4.20 Buffer Cell


ODL04_20

FRESHWATER FROMDISTRUIBUTION HEADER

EL +15.5m

FROM BUFFER CELL

TO NON-HAZARDOUS AREAOPEN DRAINS HEADER

TO DRAINS

SKIMMED OIL TOTEST SEPARATOR

HH 5.5H 5.0

L 1.0LL 0.5

PI

95002

HV-95004

HV95003

H

PSV-95001SET AT 8.2barg

BUFFER CELLSKIMMING CAISSONX-9502

AIRRELEASEVALVEAV-9502

BUFFER CELLSKIMMING PUMP

P-9502

SB

EL-5000m

FO95003

FROM BUFFER CELL

HH 5.5H 4.5

L 1.0LL 0.5

PI

95002

XA

95012

PSV-95004SET AT 6.1barg

BUFFER CELLSAMPLE CAISSONX-9501

AIRRELEASEVALVEAV-9501

BUFFER CELLSAMPLE PUMP

P-9501

SB

EL-5000m

FO95006

AE95009

HV46049

ANALYSERGENERALALARM

AI

95009

OILINWATER

IAS

SC95006

PIT95002

PIT95005

SC95007

PCS PCS

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