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Impact of Dynamic Modelling on The Optimum GL Implementation ScheduleImpact of Dynamic Modelling on The Optimum GL Implementation ScheduleContent

1. Dynamic Simulation2. Dynamic Well Modelling3. Optimum Gas Lift Implementation Schedule

ALRDC – 2004 Spring GAS LIFT WORSHOP

byby Juan Carlos Mantecon Juan Carlos Mantecon

www.scandpowerpt.com

9

1. Dynamic Simulation

10

Dynamic Simulation

11

Dynamic Engineering

12

Dynamic Engineering

APPLIED THROUGHOUT THE PROJECT LIFE-CYCLE

FIRST OIL

DETAILEDDESIGN

PRODUCTION

CONCEPT/FEED

OPERATIONS

SCREENING• Fluid Properties• Production Profiles• Well Locations• Pipeline Routings• Process Options

AS-BUILDING• As-built Profiles• Tuned Models• Capacity Constraints• Prod. Optimisation• Troubleshooting

SIMULATION• Operating Procedures• Pipeline Management• Well Management• Training Simulators• On-line/Off-line

INTEGRATION• Field Layout• Well Allocations• Pipeline Data • Process Scheme• Control Scheme

13

ROUTINE CONSIDERATION OF TRANSIENT EVENTS

Hydrate Inhib.

Wax / Corrosion

Slugging

Pigging

Rate Changes

NORMALPRODUCTION

START-UP

Start-up Pressurisation

Steady State

PLANNED SHUTDOWN

Short Term

Inhibitor

Displace

Long Term

EMERGENCY SHUTDOWN

Short Term

Inject Inhibitor

Blowdown

Cooldown

14

ProductionProfile

Development Plateau Decline

PerformanceMeasures

CAPEXWell Cost

Rate of Completion

Well UptimeProduction Volume

Incremental Production

OPEXData Quality

Safety & Environment

BusinessDrivers

Early ProductionCAPEX Minimisation

Maximise Total Production Reduce Production Decline

Minimise OPEX

28

Dynamic Simulation

Goals Alignment

Why use a transient simulator?• Normal production

– Sizing – tubing / pipeline diameter, insulation requirement

– Stability - Is flow stable? How to achieve stable production

– Gas Lifting / Compressors

– Corrosion

• Transient operations

– Shut-down and start-up, ramp-up (Liquid and Gas surges)

– Pigging

– Depressurisation (tube ruptures, leak sizing, etc.)

– Field networks (merging pipelines / well branches with different fluids)

• Thermal-Hydraulics

– Rate changes

– Pipeline packing and de-packing

– Pigging

– Shut-in, blow down and start-up / Well loading or unloading

– Flow assurance: Wax, Hydrate, Scale, etc.

16

When things are frozen in time

When not to use dynamic simulation

Photo: T. Husebø

17

Unstable vs. Stable flow situations

• Pipeline with many dips and humps:– high flow rates: stable flow is possible– low flow rates: instabilities are most likely (i.e. terrain induced)

• Wells with long horizontal sections – Extended Reach• Low Gas Oil Ratio (GOR):

– increased tendency for unstable flow

• Gas-condensate lines (high GOR):– may exhibit very long period transients due to low liquid velocities

• Low pressure – increased tendency for unstable flow

• Gas Lift Injection– Compressors problems, well interference, choke sizing, etc.

• Production Chemistry Problems– Changes in ID caused by deposition

• Smart Wells – Control (Opening/Closing valves/sliding sleeves)

Multiphase Flow is Transient !Well Production is Dynamic!

P/T Development – Flow Assurance

Oil

Gas Condensate

Pre

ssu

re

Temperature

LIQUID

GAS

GAS + LIQUID

Typical phase envelopes

Gas OilReservoir Temperature

70 -110 oC /160 - 230oF

Emulsion 40oC/104o

F30oC/86oF

20oC/68oF

WaxWater

HydrateHydrate

< 0oC/32oF(Joule Thompson)

~ +4oC/39oF

Temperature effects

OLGA OLGA

OLGA RESERVOIRSIMULATOR(ECLIPSE)

OLGA/ D-SPICE

Time (min.)

LIQUID FLOW INTO SEPARATOR(m / s)3

SLUG FLOW

Front Tail Front

Separated flow Dispersedbubble

19

2. Dynamic Well Modelling

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Dynamic Well Modelling

Especially suited for:

• Start-up and shut down of production

• Production from several reservoir zones

• Reservoir injection• Analysing cross flow

between reservoir zones• Flow from multilateral wells• Smart Wells• Gas Lifting• Well testing – Segregation• Gas/Condensate Wells - Dewatering• Simulation of fluid flow in

conventional and underbalanced drilling operations

• Blowout simulations

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Advanced Well Module

IPR models in OLGA 2000

– Constant Productivity Index

– Forcheimer model– Single Forcheimer model

(High Pressure Gas Wells)

– Vogel equation– Backpressure equation

(Gas Wells)

– Normalized Backpressure (Saturated Oil Wells)

– Tabulated IPR curve

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• The reservoir can be divided into multiple zones with differences in properties and IPR models

• Properties can be defined as time series (well’s life cycle) for each zone:– Reservoir pressure

– Reservoir temperature

– Gas fraction / GOR

– Water fraction / Water cut

– Drainage radius

– Skin

– Fracture pressure

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Productivity Index in OLGA

• The following equations are used to calculate the PI for the oil, water and gas to be used by OLGA. The PI in OLGA is the TOTAL PI (the associated gas must be added to the given PIProsper): The GOR is given in standard cubic feet per standard barrels, the densities as kilograms per cubic meters and the water-cut in fraction

689536002429.6

)1(Pr

OILosper

OIL

WCPIPI

689536002429.6Pr

WATERosper

WATER

WCPIPI

6895360024315.35

)1(Pr

GASosper

GAS

GORWCPIPI


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PHASE = GAS - = STDFLOWRATE

The following equations show how the total mass flow is calculated in OLGA when Watercut, GORGOR and Volume flow are known

• The properties at standard condition are taken from the PVT table.

))1

(11

(ST STw

STo

STggtot wc

wc

GORGORQm

STgQ

PHASE = LIQUID - = STDFLOWRATE

STliqQ

))1()1((ST STg

STo

STwliqtot wcGORwcwcQm


Mass Sources

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PHASE = OIL - = STDFLOWRATE

The following equations show how the total mass flow is calculated in OLGA when Watercut, GORGOR and Volume flow are known

• The properties at standard condition are taken from the PVT table.

PHASE = WATER - = STDFLOWRATE

SToQ

)1

(ST STw

STg

STootot wc

wcGORQm

STwQ

))1

(1

(ST STg

STo

STwwtot wc

wcGOR

wc

wcQm


Mass Sources

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Annular flow

• In annular flow there will be a higher wetted surface area compared to the flow area

• In OLGA 2000 a single pipeline with corresponding flow area is assumed

• The wall interfacial friction is calculated based on a hydraulic diameter, Dh:

tch D - DS

4A D

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Gas lift

• No library of commercial gas lift valves– OLGA is reasonably effective at simulating the unloading operation

• Specific valve characteristics or controller routines can be defined:

– The LEAK command coupled with the CONTROLLER command provides a means of reasonably accurate representation of an unloading valve

• Casing and/or Tubing sensitive valves

• Concentric casing or parasite string injection– Well kick-off – Continuous GL to reduce static pressure

• Riser gas lifting– To reduce static pressure– To reduce / avoid slugging

• Stability prediction with Slugtracking

ProductionFluids + GL

Gas Lift

Production

Fluids + GL

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Gas lift

• The OLGA bundle can be use to calculate a source temperature at injection point– e.g. gas flowing in the annulus of

the CARRIER

• Annulus flow model with normal OLGA Branch features gives very exact countercurrent heat exchange

• It is possible to combine various branch models with the BUNDLE, the SOIL and FEM-Therm

Branch = “GASINJ”

Branch = “WELLH”

Node

Branch = “WELLB”

Gas Injection

Production

Casing

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Gas lift Unloading (Duals, Check Valve Wash-out, etc.)

• The “Annulus’ keyword is used to model the GL annulus with a number of ‘Leaks’ installed to provide communication between the well annulus and the tubing

– Each ‘Leak’ is then assigned a GLV to control the opening and closing of the valve

• The GLV operation is simulated using a combination of cascade and PID controllers

– e.g. Pdome is modified based on temperature and depth. The output is then used to determine the Ptbg at which the GLV will open based on the local Pcsg. This is compared against the actual Ptbg to determine if the GLV is open

ACPC

PT

PD

AD

AT

ANNULUS

TU

BIN

G

ACPC

PT

PD

AD

AT

ANNULUS

TU

BIN

G

ACPC

PT

PD

AD

AT

ANNULUS

TU

BIN

G

ACPC

PT

PD

AD

AT

ANNULUS

TU

BIN

G

ACPC

PT

PD

AD

AT

ANNULUS

TU

BIN

G

ACPC

PT

PD

AD

AT

ANNULUS

TU

BIN

G

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3. Optimum Gas Lift Implementation Schedule

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• OLGA is a powerful tool for establishing the watercut limits for which the well would not produce at steady state and where it would not kick off – investigate a future kick-off problem

– Gas Lift will be required at some time in the future in order to kick-off the wells

– Wells will encounter kick-off problems at a lower watercut than their their natural flow limit

– Determining the kick-off limits is a key issue for determining the optimum gas lift implementation schedule

• The installation cost of a GL system to support the kick-off of the well is high and deferring this expenditure is of high NPV ($MM).

• On the other hand, the inability to kick-off the well has a high impact cost in terms of deferred production ($100MM).

– Watercut limits may increase with increasing Reservoir pressures– Watercut limits are more sensitive to FTHP and PI.

• The matrix of results (dynamic sensitivity runs) will determine at what point in the future the well will need GL to overcome the impact of fluid segregation on kick-off (and optimum GL volume)

Dynamic Wells ModellingWatercut Limit for Kick-off / Shut-in Segragation

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• Elevation Profile vs. Horizontal and Tubing Length– Model from Reservoir to Christmas tree – number of pipes =F(trajectory), pipe is divided into 50m section lengths


Well #SPT69

-3000

-2500

-2000

-1500

-1000

-500

0

0 500 1000 1500 2000 2500 3000 3500

Position [m]

Ele

va

tio

n

[m]

Horizontal Length Pipeline Length

Top of tubing Top of tubing

Reservoir

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• Productivity Index and Oil Rate vs. Water Cut– The reservoir fluid PVT is critical to the model results– The time at which the well will not naturally kick-off is dependent on PI, Reservoir Pressure and Watercut.


Well SPT69 - FTHP = 500 psia

0

5,000

10,000

15,000

20,000

25,000

0 10 20 30 40 50 60 70

Watercut [%]

Oil

Ra

te

[ST

B/D

]

2500 psia 3000 psia 3500 psia 3600 psia 3800 psia

Well SPT69

0

5

10

15

20

25

30

35

40

45

0 10 20 30 40 50 60 70 80 90

Watercut [%]

Pro

du

ctio

n I

nd

ex

[b

bls

/d/p

sia]

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• Watercut Limits – Steady State – OLGA vs. Prosper– The watercut limits at steady state may be found using OLGA (Transient) and Prosper (Steady State) software. Differences for the particular study case are shown below – WC

predicted by Prosper are lower than predicted by OLGA



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39

47

54

28

36

44

52

62

0

10

20

30

40

50

60

70

2700 2900 3100 3300 3500 3700

Reservoir Pressure [psia]

Wa

ter-

cu

t [%

]

Prosper OLGA 2000

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• Watercut Limits – Steady State vs. Kick-Off– This well will only kick-off for 20-26% lower watercuts (absolute) than it will produce at steady state (this may increase with R pressure)



28

36

44

52

62

0

10

24

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0

10

20

30

40

50

60

70

2500 2900 3100 3300 3500 3700

Reservoir pressure [psia]

Wa

terc

ut

[%]

Steady state Kick-off

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• Watercut Limits – Steady State vs. Kick-Off– Roughness and U-value sensitivities– Low (half), Base and High (double) Overall transfer Coefficient


Well SPT69 - 3000 psia reservoir pressure

46 44 44

26 24 24

0

5

10

15

20

25

30

35

40

45

50

0.0006 0.001 0.002

Roughness [inch]

Wa

terc

ut

[%]



44 44 44

24 24 22

0

5

10

15

20

25

30

35

40

45

50

Low Base High

U-value

Wa

terc

ut

[%]


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• Watercut Limits – Steady State vs. Kick-Off– FTHP and PI sensitivities– Watercut limits increase a little with increasing PI– Watercut limits are more sensitive to FTHP changes



40 44

48

20 24

28

0

10

20

30

40

50

60

Low Base High

Productivity Index

Wa

terc

ut

[%]



60

44

28

38

24

6

0

10

20

30

40

50

60

70

500.00 700.00 900.00

FTHP [psia]

Wa

terc

ut

[%]


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• Watercut Limits – Steady State vs. Kick-Off– Temperature profiles at different points in time – base case


Well SPT69 at 3000 reservoir pressure and 20% WC

0

20

40

60

80

100

120

0 500 1000 1500 2000 2500 3000 3500

Pipeline length [m]

Te

mp

era

ture

[C

]

Steady state 1 hour after shut-in 3 hours after shut-in 6 hours after shut-in 12 hours after shut-in 24 hours after shut-in

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• Watercut Limits – Steady State vs. Kick-Off– Segregation during Steady State before Shut-in – Watercut = 20%, Reservoir Pressure 3,000 psia, FTHP = 500 psia


Steady state

-2700

-2200

-1700

-1200

-700

-200

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1

Fraction [-]

Ele

vati

on

[m

]

Water Oil Gas

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• Watercut Limits – Steady State vs. Kick-Off– Segregation during Shut-in – Watercut = 20%, Reservoir Pressure 3,000 psia, FTHP = 500 psia– The apparently sudden changes in O,W & G hold-up are due to the graphs being plotted as TVD rather than along the hole.


6 min after shut-in

-2700

-2200

-1700

-1200

-700

-200

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1

Fraction [-]

Ele

vati

on

[m

]

Water Oil Gas

1 min after shut-in

-2700

-2200

-1700

-1200

-700

-200

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1

Fraction [-]

Ele

vati

on

[m

]

Water Oil Gas

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• Watercut Limits – Steady State vs. Kick-Off– Segregation during Shut-in – Watercut = 20%, Reservoir Pressure 3,000 psia, FTHP = 500 psia


24 hours after shut-in

-2700

-2200

-1700

-1200

-700

-200

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1

Fraction [-]

Ele

vati

on

[m

]

Water Oil Gas

WATER

OIL

GAS

1 hour after shut-in

-2700

-2200

-1700

-1200

-700

-200

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1

Fraction [-]

Ele

vati

on

[m

]

Water Oil Gas

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• Watercut Limits – Steady State vs. Kick-Off– Segregation during Start-up – Watercut = 20%, Reservoir Pressure 3,000 psia, FTHP = 500 psia


1 min after start-up

-2700

-2200

-1700

-1200

-700

-200

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1

Fraction [-]

Ele

vati

on

[m

]

Water Oil Gas


-2700

-2200

-1700

-1200

-700

-200

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1

Fraction [-]

Ele

vati

on

[m

]

Water Oil Gas

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• Watercut Limits – Steady State vs. Kick-Off– Segregation during Start-up – Watercut = 20%, Reservoir Pressure 3,000 psia, FTHP = 500 psia



-2700

-2200

-1700

-1200

-700

-200

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1

Fraction [-]

Ele

vati

on

[m

]

Water Oil Gas


-2700

-2200

-1700

-1200

-700

-200

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1

Fraction [-]

Ele

vati

on

[m

]

Water Oil Gas

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• Watercut Limits – Steady State vs. Kick-Off– Steady State after Start-up – Watercut = 20%, Reservoir Pressure 3,000 psia, FTHP = 500 psia


Steady state after start-up

-2700

-2200

-1700

-1200

-700

-200

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1

Fraction [-]

Ele

vati

on

[m

]

Water Oil Gas

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• Watercut Limits – Steady State vs. Kick-Off– Steady State after Start-up – Watercut = 26%, Reservoir Pressure 3,000 psia, FTHP = 500 psia


Steady state after start-up

-2700

-2200

-1700

-1200

-700

-200

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1

Fraction [-]

Ele

vati

on

[m

]

Water Oil Gas

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• OLGA is a powerful tool for establishing the watercut limits for which the well would not produce at steady state and where it would not kick off – investigate a future kick-off problem

– Gas Lift will be require at some time in the future in order to kick-off the wells

– Wells will encounter kick-off problems at a lower watercut than their their natural flow limit

– Determining the kick-off limits is a key issue for determining the optimum gas lift implementation schedule

• The installation cost of a GL system to support the kick-off of the well is high and deferring this expenditure is of high NPV ($MM).

• On the other hand, the inability to kick-off the well has a high impact cost in terms of deferred production ($100MM).

– Watercut limits may increase with increasing R pressures– Watercut limits are more sensitive to FTHP and PI.

• The matrix of results (dynamic sensitivity runs) will determine at what point in the future the well will need GL to overcome the impact of fluid segregation on kick-off (and optimum GL volume)

47

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Thank You! Any Questions?

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