chevron olga user meeting

7/28/2019 Chevron OLGA User Meeting

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Mu t p ase F ow anFlow AssuranceOl a Users Meetin

Sam KashouETC Flow Assurance, MCP Team


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Safety Moment

Ensure safety devices are in place and functioning.

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Objective

To give a high level overview of Flow

Assurance in Multiphase Flow

fluid faces while flowing insidewe ores, pipe ines, an risers, etc.

have.

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What i sFlow Assurance

The ability toproduce and transport

in an economically and technically

.

Designing and operating the productionand transportation systems to manage

challenges to the flow throughout the

e e.

4

Flow Assurance = Cash Flow Assurance


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Identify FA drivers that will influenceconcep se ec on

Identify technology gaps & developso u ons

Ensure preferred concept is feasible froma perspec ve

Ensure preferred concept can be

opera e sa e y an e ec ve y

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What could happen if Flow AssuranceStudies are not performed?

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Hydrate Blockage and RemediationOffshore Pipeline (plug can be many meters

long and in many sections of line)

Due to improper MEG dosage to prevent hydrates

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Hydrate Blockage Offshore

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Wax in Pipeline

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Napthenates

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Asphaltenes

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SluggingTest Separator Liquid Rates, Feb 7

1000

1200

1400

ate,m3/d

400

600

800

tSeparatorL

iquid

0

200

8500 8510 8520 8530 8540 8550 8560

Time, minutes

Te

12


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Explosion, Fire

I t Co u l d be due to internal pipe corrosionand lack of corrosion monitoring

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Is this Flow Assurance?Overloaded Donkey (cant move, therefore cantflow - gravity dominated flow)

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Flow Assurance Activities

SYSTEM

SAMPLING

SOLIDS

FORMATION

DESIGN

PARAMETERS

HYDRAULIC

MODELINGSTRATEGIES

HYDRATES DIAMETERSMULTIPHASE

FLOW

BOUNDARIES

STARTUP &

ANALYSES WAX

ASPHAL- CHEMICAL

SLUGGING

SHUTDOWN

FLUID

MODELING

TENES

SCALE

INJECTION

TOPSIDES

THERMAL

MODELINGINTER-

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EQUIPMENT VENTION


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The Flow Assurance Challenge

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HOW ARE FLOW ASSURANCE STUDIES INTEGRATED

PHASE 1 PHASE 2 PHASE 3 PHASE 4 PHASE 5

IDENTIFY AND

ASSESSOPPORTUNITY

GENERATE AND

SELECTALTERNATIVE(S)

DEVELOP

PREFERREDALTERNATIVE(S)

EXECUTE OPERATE ANDEVALUATE

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HOW ARE FLOW ASSURANCE STUDIES INTEGRATED WITHTHE PROJECT WORKSCOPE?


ASSESS

OPPORTUNITY

Fluid Sampling Program

Reservoir Fluids

Water Samples

Plan Fluid Testing Program

Measure Key Fluid Properties

PVT Data

Water Composition

H drate

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Wax & Asphaltenes

Scale


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SELECT

ALTERNATIVE(S)


Perform any additional

experimental testing e ne u property pre ct ons

Steady state hydraulics ofconcepts

of concepts

System deliverability

Preliminar FA Miti ation lan

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Input to subsea facilities design

work


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PREFERRED

ALTERNATIVE(S)


Continue experimental work if

needed p ate re nement o pre erre

concept(s) using

Details of subsea facilities

Refine transient simulations

Updates of FA MitigationStrate

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Development of Subsea

Operating Philosophy


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EXECUTE


Major flow assurance related

tasks complete

Selection / compatibility of

treating chemicals

Operating procedures

Start-up & commissioning

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OPERATE AND

EVALUATE

ow ssurance c v es

Provide support to operations as

needed: Modifications to chemical

selection Program

Support of processing

z Separation

z Naphthenates

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Blockage remediation issues

Optimize production


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FLOW ASSURANCE Spectrum

ReservoirFluids S stem

u p ase

Flow

Integration

Solids Injection

FlowInternal Operability

Assuranceorros on

Thermal

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Sand


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FLOW ASSURANCE Spectrum (1)

(1) Reservoir Fluids

, ,

(2) Multiphase Flow

z Rheology, flow modeling

z Pressure loss, diameter of tubing & flowlines

z ugg ng an qu surge

(3) Solids

z Hydrates, wax, asphaltenes, scale, naphthenates, etc.

z Flow restrictions or blockages

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(4) Internal Corrosion


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(5) Emulsions

(6) Sand

z Sand transport / deposition

z Erosion

erma anagemen

z Insulation, heating

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(8) System Operability

zVarious operating modes: normaloperation, shutdown, startup, well

testing, turndown/rampup, pigging,

etc.

(9) Chemical Injection

(10) System Integration

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(1) RESERVOIR FLUIDS

Hydrocarbons

z Saturates / Paraffins /

Alkanes

z Aromatics THERE CAN BE THOUSANDSOF DIFFERENT MOLECULESIN A RESERVOIR FLUID

z es ns

z Asphaltenes

-

z Water

z Mineral salts

z CO2, H2S, mercaptans, N2,

He

THIS LEADS TO COMPLEXFLUID BEHAVIOR

WHICH CAN BE DIFFICULT TO

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z Metals

z Microorgansims

ANALYZE AND PREDICT


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RESERVOIR FLUIDS

Form the Basis for Flow Assurance and other

design work; Fl o w A s s u r a n c e w o r k i s a s

g o o d a s t h e Re se r v o i r F l u i d Sam p l i n g

a n d A n a l y s i s .

PVT Pressure, Vo ume, Temperature

z Describes the thermodynamic relationship between pressure,

volume, and temperature for all phases

Phase Behavior

z Phase refers to the state of matter: gas, liquid, solid,

z ,

relative quantities of each phase

Fluid Properties

28

z Parameters related to solids formation


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RESERVOIR FLUIDS

PHASE ENVELOPE

300

350

RESERVOIR

Highest possibletemperature andpressure for which

250

LIQUID

CRITICAL POINT

CRICONDENBAR

s nc qu orgas phases can beobserved

200

ssure

(bara

)

CRICONDENTHERM

WELLHEAD

CHOKEFLOWLINE/

PIPELINE

100

Pr

TWO PHASE REGION

50

VAPOR

DEW POINT CURVE

TOPSIDES SEPARATOR

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0 50 100 150 200 250 300 350 400 450 500

Temperature (C)


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RESERVOIR FLUIDS

Sampling

F

Separator

F

Liquid Sampling Port

Downhole Sampling Tool

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(2) MULTIPHASE FLOW

Multiphase flow is the simultaneous flow of

multiple fluid phases (gas, oil, and water) inside a

flow device.

The flow device can be:

z Reservoir

z Wellbore

z Flowlines

z Risers

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Quiz: What is a Pipeline?

zA i eline is a lon hole surrounded b

metal concentric with hole,

zO.D. of all pipes must exceed the I.D.

otherwise the hole will be on the outside,

PipelinezAll pipe is to be hollow throughout

blockageen re eng , as o , gas, an wa er canbe added on site.

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MULTIPHASE FLOW

Flow Regimes in Pipes

, ,

stability, slug catcher sizing, etc.

Dispersed Bubble Flow Annular Flow

Slug Flow Stratified Flo

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Fl R i i Pi li


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Flow Regimes in Pipelines

-

- -

Various Flows

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Flow Regimes in Pipelines,Severe Slugging

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MULTIPHASE FLOW

Holdup (HL)

.

z Due to slip HL > fraction of liquid due to phase

behavior

Gas

~50% Liquid Holdup

Liquid

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MULTIPHASE FLOW

Holdup, this is very real

Gas Condensate Liquid Holdup Example

PIPESIM Plot Mar 17 2001

60000

40000

50000

ldu

p(bbl)

Gas

Li uid

20000

30000

lLiquid

Ho

Gas

0

10000Tot

Liquid

37

PIPESIM for Windows Baker Jardine & Associates, London

Stock-tank Gas at Outlet (MMSCFD)


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(3) SOLIDS

Hydrates

Scale

Asphaltenes

Calcium Naphthenates

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HYDRATES

Ice that burns

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HYDRATES

Water molecules

Methaneguest molecule

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HYDRATES

Subcooling Definition250

200Design

PressureSubcooling or Temperature Depression

150

ure

(bara

)

Hydrate Zone100

Pres

Design Temperature

Hydrate Free

0

41

0 5 10 15 20 25 30

Temperature (C)


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HYDRATES

Hydrate prevention - Chemical Inhibitors

f Methanol

f yco s , , , o ers

Salt (brine)

z Low dosage (a.k.a. LDHI)

f Anti-agglomerants (prevents accumulation)

f Kinetic inhibitors (delay nucleation)

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HYDRATES

Hydrate prevention

above hydrate formation conditions)f Insulation

f Active heating

z

z Low pressure operation (maintain pressure below

hydrate formation conditions)

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WAX / PARAFFINS

Wide range of high molecular

weight paraffins (alkanes or

saturated hydrocarbons)

Slightly soluble in oil

Solidify from oil primarily

due to a decrease in temperature

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WAX / PARAFFINS

As wax solidifies from oil, there are

zWax deposition on tubing and pipe walls

during normal flow

z Gelling of the oil during shutdown

z Increases in viscosity due to wax

articles sus ended in the oil

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WAX / PARAFFINS

Wax Management

z Pigging

z Chemical injection

z Insulation

z c ve ea ng

z Operating procedures

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Pigging

- -

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SCALE

A deposit of inorganic mineral compounds

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SCALE

Scale formation and deposition occurs due to:

z Mixing of different waters

z Corrosion

Deposition can occur in t e:

z Formation

z Wellbore

z Flowlines

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z Process equipment


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SCALE

Scale can be managed by:

zPrevent deposition using chemical

inhibitors

zPre-treatment to remove scale

zAllow scale to form and periodically

remove it

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ASPHALTENES

What are Asphaltenes?

,

z Defined by solubility

What is a Colloidal System?

z Dispersion of one phase in a continuous phase

z Example: Milk fat in water

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ASPHALTENES

Causes of Asphaltenes deposition

z Gas lifting

Asphaltenes can deposit

z Formation, wellbore

tubing, flowlines,

and to sides

Courtesy of Baker Petrol itCourtesy of Baker Petrol it

Asphaltenes can

cause emulsion As halteneAs haltene

52

problems depositiondeposition


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ASPHALTENES

Asphaltenes Control

z Inhibitors

prevent asphaltene deposition

orma y n ec e a e o om o e

well

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CALCIUM NAPHTHENATES

Naphthenates are a solid that forms from a

reaction between calcium in produced water and

naphthenic acid in oil

Found in some West African and North Sea fields

High TAN oils (TAN = total acid number)

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(4) INTERNAL CORROSION

Corrosion can occur inside a pipe any time water

is present

Corrosion is accelerated by the presence of O2

,

CO2, or H2S (sour)

Pipeline failures are a big

potential liability

Corrosion prevention

z Chemical inhibitors

z

Protective coatings, corrosion resistant alloysz Limit flow rates / velocities

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z Other


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(5) EMULSIONS

Emulsions are complex mixtures of immiscible

liquids consisting of a dispersed liquid in a

continuous liquid phase

Water-in-oil emulsions

z Most common in crude oil systems

z Exists in water cuts as hi h as 80%

Oil-in-water emulsions

Increased viscosity

56

Separation problems


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EMULSIONS

Viscosity

A3WCMU14Albacore-Leste Oil -Brine Fluid

2500100

o

F

Flow Velocity2 ft/sec.

Fluid Temperature

osity,cP2000

120

o

F

110oF

FluidVis

1000

1500

130oF

500

140oF

57

Water-Cut, %

0 10 20 30 40 50 60 70 80 90 1000


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(6) SAND

Belongs on the beach

58

SAND


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SandSAND

Small quantities of sand are typically produced from oil

and gas reservoirs

Sand can have detrimental impacts on production

z Erosion

z Increase corrosion

z Can form restrictions or plugging

can se e n ops es equ pmen

Sand transport

be defined for sand transport

59

SAND P di ti d M it i


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SandSAND Prediction and Monitoring

Prediction in design phase

z ore ana ys s we es a a

z Erosion & solids transport modeling

Continuous or periodic monitoring for sand

-

If a well begins to produce significant sand, then

z

z Permanently shut-in

z Operate at reduced flow rate

60

SAND D t ti


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SandSAND Detection

Subsea sand detectors are commercially

available

zIntrusive

zAcoustic

61

S dSAND Detection


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SandSAND Detection

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(7) THERMAL MANAGEMENT


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(7) THERMAL MANAGEMENT

Why are we interested in thermal

mana ement?

zMany of the potential solids are

hydrates and wax

z significantly) with decreasing temperature

z Insulation keep the heat you have

63

z Active heating add energy

THERMAL MANAGEMENT


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THERMAL MANAGEMENT

Insulation

z Flowlines

z Subsea equipment

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Pipeline Insulation Manufacturing


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Pipeline Insulation Manufacturing

65

(8) OPERABILITY


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(8) OPERABILITY

Development of Operating Philosophies,

Strate ies and eventuall Procedures

Integration of Flow Assurance into system

Definition of operating boundaries/ranges

Consider various modes of operation

O erational monitorin

Intervention requirements

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GENERAL OPERABILITY STRATEGIES


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GENERAL OPERABILITY STRATEGIES

For Life Cycle

zSteady State Operations (line sizes,

pressure and temperature drops,

flow rates, etc.)

(Production Start-up, Planned Shut-

, u - , , .

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(9) CHEMICAL INJECTION


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(9) CHEMICAL INJECTION

Chemicals are needed to control a number of

potential solids and production chemistry

concerns

Chemical compatibility

Chemical Injection Design Philosophy

z Chemical performance testing

z Operation monitoring

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CHEMICAL INJECTION


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CHEMICAL INJECTION

STORAGE

Example Chemical Injection Layout

TANK

PUMPFILTER

FLOWMETER

FLOWCONTROL

VALVE

M TUTA UMBILICAL

SUBSEA TREE

SUTAFLYINGLEADS

69

Introduction(10) SYSTEM INTEGRATION


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Introduction( 0) S S G O

Consider all components of production

z Reservoir, wells, subsea equipment,ow nes, r sers, ops es process ng

facilities, control and umbilical

, .

Consider interaction of all components

Address design interfaces

70

SYSTEM INTEGRATION


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Emulsions/ Foaming

Advanced MPF Modeling

Corrosion ControlAsphaltene Control

Wax Control

Hydrate Control

MP Flow Improvement Scale Control

71

Integrated Production System Model

Systems World WideExisting and to be Developed


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g p

Field Country Length Diameter Depth Subsea Production Fluid

[km] [in] [m] Development Start

Gorgon Australia 70 34 200 Yes ? 3 Phase

Jansz Australia 134 30-34 1340 Yes ? 3 Phase

Wheatstone Australia 160 34 190 Both ? 3 Phase

WTR Australia 165 18 140 Yes ? 3 PhaseOrmen Lange Norway 120 2x30 800-1100 Y es 2007 3 Phase

atar Gas II ata 90 32 50 No 2006 3 PhaseSnhvit Norway 143 28 250-345 Yes 2005 3 PhaseGoldeneye UK 105 20 120 No 2004 3 PhaseScarrab/Saffron Egypt 90 20 to 36 90 Yes 2003 3 PhaseSouth Pars 2+3 Iran 105 2x32 65 No 2002 3 Phase

Canyon Express US 92 2x12 2200 Yes 2002 3 PhaseFirebird US 10 dual 6 300 yes 2001 3 PhaseHuldra Norway 145 22 120 No 2001 3 phaseGemini US 44 dual 12 1050 Yes 1999 3 Phase

a e s an ana a o aseSable Island Canada 175


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Deepwater pipe section replacement

73

Being at the wrong place and at the wrong time

Final Thoughts, Is this Flow Assurance?


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Pipeline or

a way

Blockage?

74


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Flow Assurance Modeling Example

75

Modeling: LNG Plant Start-up Gas Flow Rate


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80

100% gas flow is 22.5 BCM annual gas rate

60

70

(MMm

3/D) ramp up to

25% in

3 months hold at25% for

Hold at

100%

40

50

a

tLNG

Plan

Gas

hold at

12.5% for 1

month

ramp up to

50% over 1

month

20

30

sFlow

Ra

te

ramp up

from 0 to

12.5% in

3 monthshold at 50%

for 12

months

ramp up to

100% over

1 month

0

0 60 120 180 240 300 360 420 480 540 600 660 720 780 84

G.

3 months

76

Time (days)

Modeling: LNG Plant Start-up Pipeline Pressure


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150

160100% is 22.5 BCM annual gas rate

110

120

130

140

(bar)

Inlet

ramp up to

25% in

3 months hold at

25% for

1 month

Hold at

100%

70

80

90

100

n

ePressure

12.5% for 1

monthramp up to

50% over 1

month Outlet

20

30

40

50Pipe

li

ramp up

from 0 to

7.5% in

12.5% in

3 months hold at 50%

for 12

months

ramp up to

100% over

1 month

0

10

0 60 120 180 240 300 360 420 480 540 600 660 720 780 84

Time da s

mon s

77

Modeling: LNG Plant Start-up


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26000


18000

20000

22000

ne

(m

3)

25% in

3 monthshold at

25% for

1 month

12000

14000

16000

up

inPipe

li

ramp up to

50% over

1 month

ramp up to

100% over

1 month

12.5% for

1 month

4000

6000

8000

10000

Liqu

idHol

Condensate

ramp up

from 0 to

ramp up to

12.5% in

3 monthshold at

50% for

12 months

Hold at

100%

0

2000

0 60 120 180 240 300 360 420 480 540 600 660 720 780 840

Water/MEG

7.5% in

3 months

78

Time (days)

Modeling: LNG Plant Start-up Liquid Flow Rate


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2500


ram u to

1750

2000

2250

lant(m

3/D)

hold at

25% in

3 monthshold at

25% for1 month

ram u to

1000

1250

1500

ateatLNG

12.5% for

1 monthramp up to

50% over 1

month

hold at

100% over

1 month

500

750

iquidFlow

Condensateramp up

from 0 to

12.5% in

3 months

50% for

12 months Hold at

100%

0

0 60 120 180 240 300 360 420 480 540 600 660 720 780 84

Water/MEG

.

3 months

79

Modeling: LNG Plant Start-up Accumulated Liquid Flow


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40000

22.5 BCM annual gas rate

30000

35000

Plan

t(m

3)

20000

25000

Flow

atLN

hold at 50%

ramp up to

50% over 1

month

5000

10000

TotalLiqui for 12

months

25000 m3 of

liquid produced

in a month

0300 310 320 330 340 350 360 370 380 390 400

Time da s

a ou m

80

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