gas lift fundamentals...

Introduction

Gas Lift Fundamentals

Learning Objectives

This section will cover the following learning objectives:

Explain the role of gas lift in a well performance analysis process

Explain the principles of multi-phase flow and the principleof gas lift

Identify the advantages and disadvantages of gas lift as anartificial lift method

Estimate the production rate achievable by the gas lift

Identify gas lift equipment

Identify gas lift design methods

Establish well unloading procedures

Outline gas lift surveillance and optimization processes

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Gas Lift Fundamentals ═══════════════════════════════════════════════════════════════════════════════════

©PetroSkills, LLC. All Rights Reserved. _________________________________________________________________________________________________________

1

Module Contents

Introduction

Inflow and Outflow Performance Review

Gas Lift Theory

Gas Lift Applications

Gas Lift Equipment

Valve Mechanics

Well Performance Calculations with Gas Lift

Gas Lift Well Unloading Process

Gas Lift Design Outline

Gas Lift Surveillance and Optimization

Gas Lift Case Study

Conclusions

Module Schedule

S. No. Topic of Discussion Activity Time (min)

1 Pre-Assessment Assessment 30

2 Skill Module Introduction Narrated Slideshow 4

3 Gas Lift Video 2

4 Gas Lift Design Introduction Video 3

5 Principles of Gas Lift, Gradient Calculations and Nodal Analysis Virtual Session 1 90

6 Well Inflow Performance Narrated Slideshow 9

7 Flowing Gradient Exercise 10

8 Well Outflow Performance Narrated Slideshow 13

9 Gas Lift Requirement Exercise 10

10 Kickover Tool Gas Lift Valve Setting Procedure Video 1

11 Retrieval of Dummy Valve Video 2

12 Gas Lift Equipment Narrated Slideshow 35

13 IPO Gas Lift Valve Pressure Setting Exercise 10

14 Orifice Gas Valve Gas Passage Exercise 10

15 Gas Lift Design, Troubleshooting and Valve Mechanics Virtual Session 2 90

16 Gas Lift Surveillance and Optimization Narrated Slideshow 8

17 Gas Lift Case Study Exercise 45

18 Skill Module Summary Narrated Slideshow 4

19 Post-Assessment Assessment 30

20 Gas Lift Fundamentals Survey Survey 15

Total Duration 7 hours 1 min

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Well Inflow Performance: Prediction Methods


Learning Objectives

This section will cover the following learning objective:


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The Production System

INFLOW

OUTFLOW

Inflow Performance

• Analytical Methods• Empirical Methods

IPR=Inflow

RelationshipPerformance

The Inflow Performance Relationship (IPR) describes the abilityof the reservoir to deliver fluid (i.e. rate) for a prescribedpressure drop between reservoir and wellbore (drawdown)

The IPR is independent of the tubulars

The IPR can be evaluated using:

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Inflow: Steady-state Radial Flow

Darcy’s Law

Oilfield: C = 0.00708 & Qo in BOPD

Metric: C = 0.0535 & Qo in m3/d

Applicable for non-compressible single phase flow

S = classic mechanical skin (dimensionless)

P

/res wf

oo e w

C k h pQ

B In r r S

Inflow: Semisteady-state Radial Flow

(corrected for non-Darcy skin)

Darcy’s Law

where Qo J* Pres – Pwf

and J PIor Productivity Index, Oilfield Units

0.00708 P

/ 0.75res wf

oo e w

k h pQ

B In r r S Dq

COPYRIG

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5

Productivity Index (PI)

Simplest and most widely used relationship

Straight line

Units stbpd/psi

For oil/water wells above bubble point

Not applicable to gas wells

Straight Line PI

0

200

400

600

800

1000

1200

1400

1600

0 200 400 600 800 1000 1200

Rate (STBLPD)

Pre

ssu

re (

psi

)

Test Point PI Test Point

PI=

IndexProductivity

PIQ

Pr – Pwf=

(31.8) (63.6)(95.4) (127.2)

(159) (190.8)

(11 032)

(9653)

(8274)

(6895)

(5516)

(4137)

(2758)

(1379)

(SCM/Day)

(kPa)

Vogel IPR

Originally developed forsaturated oil reservoirs/ solution gas drive byAlfred Vogel

Applicable belowbubble point

• Need Q and Pwffrom well test

• Calculate Qmax

• Use Qmaxto calculatecomplete IPR

Vogel IPR

0

200

400

600

800

1000

1200

1400

1600

1800

0 100 200 300 400 500 600 700

Rate (STBLPD)

Pre

ssu

re (

ps

i)

Pwf Test Point

(31.8) (63.6) (95.4)(15.9) (47.7) (79.5) (111.3)

(12 410)

(11 032)

(9653)

(8274)

(6895)

(5516)

(4137)

(2758)

(1379)

(SCM/Day)

2

max

1.0 0.2 0.8wfs wfs

r r

P PQQ P P

(kPa)COPYRIG

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Combined IPR for Under-saturated Reservoir

Above Pbp, use straight line IPR

Below Pbp, use a combination of both• Total Oil Prod = Q oil at Pbp + Q oil Vogel

Rate

Pre

ssur

e

Qmax

Pbp

(a) (b)

(a) (b)

Pres

2

rP 1 0.2 0.81.8b wf wf

bb b

P P PQ PI P PI

P P

Pwf

Learning Objectives

This section has covered the following learning objective:


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Back to Work Suggestions

Do you have reliable production data? Do you have good reservoir pressure data?

Do you have average reservoir pressure data as a function of time which can be used as a proxy to determine the hydrocarbons in place?

Do you have good fluid properties measurements?

Do you have good correlations which we can use to predict the fluid properties?

<Course Title>

Leverage the skills you’ve learned by discussing the skill module objectives with your supervisor to develop a personalized plan to implement on the job. Some suggestions are provided.


Do you have reliable production data? Identify a few wells in your asset where the

production decline appears to be mainly due to change in inflow performance. Suggest possible ways for improving production.

Review the variation of PI observed withtime.



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Well Outflow Performance:Prediction Methods


Learning Objectives



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The Production System

INFLOW

OUTFLOW

∆P

System Pressure Drop

Reservoir

Skin ??

Perfs

Tubing

Wellhead

Choke

Flowline

Manifold

Separator

Stock tank

Pst tank

Pre

ss

ure

(p

si)

Produced Fluids Moving Through The System

∆P

Pres

Pwf

Pftp

Pflowline

Psep inlet

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Multiphase Flow

The three components of the total pressure loss are given by thefollowing equation (“m” represents the properties of the mixture):

• hydrostatic: gravitational component

• friction: irreversible heat loss due to work

• acceleration: expansion/kinetic component

Vertical: sinθ = 1 horizontal: sinθ = 0

Whilst hydrostatic and acceleration can be determinedanalytically, friction has to be determined from correlations

2

sin2m m m m m

m mc c ctotal hyd accfr

v v dvdP gf

dz g g D g dz

VLP Multi-phase Flow Regimes

Ideal Flow regimes or categories for multiple flow as illustrated by Orkiszewski. First published in the JPT, June 1967

(A)BUBBLE FLOW

(B)SLUG FLOW

(C)SLUG-ANNULAR

TRANSITION

(D)ANNULAR-MIST

FLOW

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(609.6 m)

(1219.2 m)

(1828.8 m)

(2438.4 m)

(3048 m)(1378.9) (2757.9) (4136.8)

(5515.8)

(6894.7) (8273.7) (9652.6) (11 031.6)

Tubing Performance: Pressure Traverse

Affected by• wellhead pressure

• flow rate

• tubular properties (diameter, roughness)

• fluid properties/PVT (holdup, slip)

• well inclination

• GOR

• water cut

• viscosity

calculated

?

Measured (FGS)

(kPa)

(609.6)

(1219.2)

(1828.8)

(2438.4)

(3048)(10342.1) (15513.2) (20684.2)(5171.1)

Pressure

Mea

sure

d D

epth

(ft

)

Pressure traverse curves for Q = 0, 50, 100,…300 stb/d

selected “node” depth

Pressure traverse curves for Q = 0, 50, 100,…300 stb/d(47.7 m3/Day)

selected “node” depth

Vertical Lift Performance

Vertical Lift Performance VLPTubing Performance relationship TPR

Pre

ssu

re a

t S

elec

ted

N

od

e D

epth

Total Production Rate (STB/day)

(13789.5)

(3447.38) (23.85) (35.77) (47.70)(11.93)(m3/Day)

(kPa)

(m)

(kPa)

2000

1500

1000

50075 150 225 300

2000

4000

6000

8000

100000 750 1500 2250 3000

(10342.1)

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Commonly Used Flow Correlations

Poettman and Carpenter (1952)

Gilbert (1954)

Griffith and Wallis (1961)

Duns and Ros (1961)

Fancher and Brown (1965)

Hagedorn and Brown (1965)

Orkiszewski (1967)

Govier and Azis (1972)

Beggs and Brill (1973)

Gray

Mechanistic (BAX, EPS)

General Multi-phase Flow Correlations

• There is no universal correlation that will fit for all conditions• Correlation selection is mostly by field experience

Different correlations give reasonable match for different wells:

• Conduit Size• Producing Rate• Flowing wellhead pressure• Water Cut• API Gravity• Water Specific gravity• Gas Specific gravity and• Average flowing temperature

Data required for curves includes:COPYRIGHT



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Applications of Gradient Curves

• Estimate Flowing Bottom Hole Pressure (FBHP)• Calculate Productivity Index (PI)• Predict maximum flow rates from well• Evaluate optimum gas lift rates• Determine maximum depth of injection• Evaluate the effect of Flowing Well Head Pressure (FWHP), Tubing

Size, Gas Lift Injection pressure and water cut on FBHP and flowrates

Flowing pressure gradient curves were extensively used beforenodal analysis programs became available

Framed for different production rates, water cuts, gas oil ratios

Typical use of gradient curves:

Leng

th in

100

0 fe

et

Pressure in 100 PSIG

(meters)

(3048)

(2743)

(2438)

(1829)

(1524)

(1219)

(914)

(610)

(304.8)

(kPa)

1

2

3

4

5

6

7

8

9

10

(2134)

4 8 12 16 20 24 28(2758) (5516) (8274) (11 032) (13 790) (16 547) (19 305)

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Leng

th in

100

0 fe

et


(102 mm)

(636 m3/Day)

(60°C)

(meters)

(3048)

(2743)

(2438)

(1829)

(1524)

(1219)

(914)

(610)

(304.8)

(kPa)

1

2

3

4

5

6

7

8

9

10

(2134)

4 8 12 16 20 24 28(2758) (5516) (8274) (11 032) (13 790) (16 547) (19 305)

(meters)

Leng

th in

100

0 fe

et


(3048)

(2438)

(1829)

(1219)

(610)

(636 m3/Day)

(60°C)

(kPa)

For a formation producing from a

well under the conditions in the

box, these curves provide the Pwf to

produce 4000 BOPD

(636 m3/Day) at different

producing GOR’s

1

2

3

4

5

6

7

8

9

10

(304.8)

(914)

(1524)

(2134)

(2743)

4 8 12 16 20 24 28(2758) (5516) (8274) (11 032) (13 790) (16 547) (19 305)

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(meters)

Leng

th in

100

0 fe

et


(3048)

(2438)

(1829)

(1219)

(610)

(kPa)

For a formation producing from a

well under the conditions in the

box, these curves provide the Pwf to

produce 4000 BOPD

(636 m3/Day) at different

producing GOR’s

Generatingsimilar curves with a nodal analysis program allows you to prepare an exact pressure traverse using:

• Actual fluid properties

• Wellhead pressure

• Expected production rate

• Water cut• Other

conditions

1

2

3

4

5

6

7

8

9

10

(304.8)

(914)

(1524)

(2134)

(2743)

4 8 12 16 20 24 28(2758) (5516) (8274) (11 032) (13 790) (16 547) (19 305)

Note: For more examples, refer to the Tubing Gradient and Appendix PDFs (2. Tubing Gradients and 3. Appendix listed with this lecture)

(3048)

(2743)

(2438)

(1829)

(1524)

(1219)

(914)

(610)

(meters)

(kPa)

1

2

3

4

5

6

7

8

9

10

(2134)

(304.8)

4 8 12 16 20 24 28(2758) (5516) (8274) (11 032) (13 790) (16 547) (19 305)

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Learning Objectives









Do you have reliable production data? Matching with the measured BHP or FGS

data for a well, identify the preferred correlation that gives a reasonable match.

Review the FTP of wells in your area and identify wells with excessive back pressures. Suggest action plan to reduce back pressure in an economically attractive way.



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Gas Lift Equipment:Gas Lift Mandrels, Valve Types, Valve

Mechanics


Learning Objectives



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Side Pocket Mandrel

ConventionalMandrel

Orienting Sleeve

Body

Tool Discriminator

Latch Lug

Polished Bore

Pocket

Tubing

Dome

Bellows

Casing Pressure

Seat

Tubing Pressure

Ab

POC

Gas Lift Mandrels

The depth at which the mandrel is included in the completion isdetermined by:

• Casing pressure• Tubing pressure• Flowing gradient expected in tubular• Tubing size• Other parameters

Two types of mandrels commonly used are:• Conventional mandrel• Side pocket mandrel

Side Pocket Mandrel

ConventionalMandrel

Orienting Sleeve

Body

Tool Discriminator

Latch Lug

Polished Bore

Pocket

Tubing

Dome

Bellows

Casing Pressure

Seat

Tubing Pressure

Ab

POC

Gas Lift Mandrels

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Side Pocket Mandrel

ROUND MANDREL DESIGNCAMCO

‘G’ Latch Lug

Polished Seal Bore

ToolDiscriminator

OrientingSleeve

ForgedPocket

OrientingSleeve

ToolDiscriminator

Side Pocket Gas Lift Mandrel Components

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GLV in SPM

Latch

Side Pocket Mandrel

Upper Packing

Lower Packing

Nose (Gas Exit)

GLV Gas inlet port

SPM Gas inlet port

Latch

Side Pocket Mandrel

Upper Packing

Lower Packing

Nose (Gas Exit)

GLV Gas inlet port

SPM Gas inlet port

Kickover Tool

The kickover tool is run on wireline and used to pull and set gaslift valves

The ability to wireline change-out gas lift valves gives greatflexibility in the gas lift design

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Kickover Tool Pulling Procedure

Kickover ToolGLV PullingProcedure

Kickover Tool Setting Procedure

Kickover ToolGLV SettingProcedure

Note: Please view the kickover setting procedure video and the retrieving the dummy valve video.

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Gas Lift Straddles

Used for gas lifting wells that are not equipped with gas liftmandrels in the original completion or do not have a mandrel atthe required depth

Gas lift straddle installed using wireline (e-line or Slickline)

Utilizes a conventional or wireline retrievable valve or concentricgas lift valve (selected based on application)

Can have more than one gas lift straddles installed

Retrievable pack-offs available

Gas Lift Pack-off Straddle Assembly

Typical gas lift pack offconsists of:

• Upper tubing stop• Upper pack off assembly• Gas lift mandrel with

GLV/Check valve (withspacer pipe)

• Lower pack-off assembly• Lower collar stop

Tubing is perforated at apre-determined depth(without damaging casing)before setting the straddle

Will restrict the tubing ID

Production CasingProduction Tubing

Upper Pack-off

Lower Pack-off

Gas Lift valve

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Special Application Valves• Constant Flow Valves• Proportional Response Valves

• Pilot Valves• Surface Controlled Valves

Gas Lift Valve Types

• Injection Pressure Operated: IPO (Pressure Valves)• Production Pressure Operated: PPO (Fluid Valves)

• Orifice Valves• Venturi valves

Operating Valves

Gas Lift Unloading valves

Dummy Valves





• Orifice Valves• Venturi valves

Operating Valves

• Aid the removal of the heavy weight completion fluid insidethe tubing and the annulus

• Work in a sequence to help unload the valve and allow thelit gas to reach the operating point


Dummy Valves

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• Orifice Valves • Venturi valves

• Stay open all the time injecting the required volume of gasfrom the annulus into the tubing

Operating Valves


Dummy Valves

Injection Pressure Operated Valve

ProductionPressure

Injection Pressure

Nitrogen

Bellows

Mechanical Stop

Stem

Ball

Seat

Check ValveCOPYRIGHT



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Unattached Bellows and Stems/Balls

The closing force in an unloading valve is offered by acompressed spring or a bellows charged with nitrogen gas

• Bellows is a sensitive element of the gas lift valve• It should not be exposed to significant differential pressure during

the life of the gas lift valve

Valve Bellows Two stems with balls

Unloading Gas Lift Valve

Normally required during unloading phase only

Valve closes after transfer to next station

Valve opens only when annulus and tubing pressures are highenough to overcome valve set pressure

May be spring or nitrogen charged

Upper Packing

Lower Packing

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Operating Gas Lift Valve

Typically an ‘orifice’ type gas lift valve

Always open - allows gas passage whenever correctdifferential exists

Gas injection controlled by size and differential acrossreplaceable choke

Back-check prevents reverse flow of well fluids from theproduction conduit

Upper Packing

Lower Packing

Dummy Valves

Used to blank off mandrels

Typical applications:• Sealing off the pocket of side-pocket mandrel, preventing

communication between casing and tubing• Blanking off the tubing for production until gas-lift valves are

required• Pressurizing the tubing• Isolating tubing and casing flow during single-alternative

production and for test purposes during multi-point water- orgas-injection floods

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IPO Valve Schematic

Dome(NitrogenCharged)

ChevronPackingStack

Bellows

Stem Tip (Ball)

Square EdgedSeat

ChevronPackingStack

Check Valve

Pc

Pb

Pt

PPO Valve Schematic

Dome(NitrogenCharged)

ChevronPackingStack

Bellows

Stem Tip (Ball)Square EdgedSeat

ChevronPackingStack

Check Valve

Pc

Pb

Pt

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Opening Forces

Dome(Loading Element)

Force Balance at Opening

PdAB Pt Ap Pc ( )AB -Ap

Bellows(Responsive Element)

Pc, Casing Pressure

Area of

Bellows

Ap, Area of Port

Pt, Tubing Pressure

Closing Forces

Force Balance at Closing

Pd AB PC AB

Pd

PC

Ab

ApP1

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Valve Opening And Closing Pressures (1)

1. Calculate the bellows pressure at downhole temperature, Pbt

2. Correct this Pbt to a bellows pressure at 60°F (16°C), Pb@60F

3. Calculate a test-rack opening pressure, PTRO

CLOSING FORCE (IPO VALVE) FC = PBAB

OPENING FORCES (IPO VALVE) Fo1 = PC (Ab – AP)Fo2 = PtAP

TOTAL OPENING FORCE Fo = PC (Ab – AP) + PtAP

JUST BEFORE THE VALVE OPENS THE FORCES ARE EQUAL

Pc (Ab - Ap) + Pt Ap = Pb Ab

SOLVING FOR PC Pb - Pt (Ap/Ab)Pc = --------------------------

1 - (Ap/Ab)

WHERE: Pb = Pressure in bellowsPt = Tubing pressurePc = Casing pressureAb = Area of bellowsAp = Area of port

Test Rack Opening Pressure

Pb ‐ Pt Ap/AbPc ‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐

1‐ Ap/Ab

TRO

Pb @ 60F 0 Pb @60FTRO ‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐

1‐ RR Note: Pb @ 60F = (Tc) (Pb @ Depth)

High pressure air or gas

TesterBleed Valve

Atmospheric Pressure

Note: Pb is same as Pd

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Gas Lift Valves for High Pressure Applications

Based on the demand for sub-sea wells and deep waterapplications, service providers have developed New Series HighPressure gas lift valves and mandrels. Some example valves:

1.75” (60 mm) OD New Series High Pressure gas lift valves• Orifice valve rated for injection pressure of

7500 psi (51 711 kPa) at depth• Rupture disk orifice valve• Injection pressure operated valve rated for injection pressure of

5000 psi (34 474 kPa) at depth

Valves with positive sealing barrier qualified check system• Check valve test pressure: max differential

10,000 psi (68 947.6 kPa)

1.5” OD (54 mm) New Series High Pressure valves• Allow deeper-set valves and higher drawdown• Enhanced wellbore integrity

Gas Lift Surface Equipment

Gas lift injection (typical)• Gas lift header valve• Gas injection metering• Gas lift choke• Check valve• Wing valve• Pressure, temperature sensors• Liquid removal (if needed)• Heat tracing, antifreeze (if needed)

Oil and gas production• Wing valve(s), Header valve(s)• Production choke (generally not used)

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Casing Pressure at Depth

Casing pressure or gas liftinjection pressure at depthpressure will be required

Pd = Ps [1 + 0.02 g/(Tz) ]h

Pd = Pressure at Depth, psiPs = Pressure at Surface, psig = Gas gravity (Air = 1.0)T = Average temperature of the gas column, (Ts+Td)/2; °R =(°F + 460)z = Average compressibility factorh = Depth in feet

Crawford Equation:

Gas Gradient

Note: This spreadsheet is available for your use in the resources section.

Gas Pressure at Depth – Chart 1

(304.8)

(609.6)

(914.4)

(1219.2)

(1524)

(1828)

(2133.6)

(2438.4)

(2743.2)

(3048)(6205) (6895) (7584)(8274)(8963)(9653)(10342)(11032)(11721)

(kPa)

(m)

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Thornhill-Craver Equation can be used to calculate the gas passage

through a square-edged orifice:

Q = Gas Flow in Mscf/Day at 60 DegF and 14.7 psia (101.3 kPa)

Cd = Discharge coefficient

A = Area of opening, Sq inches

P1 = Upstream pressure, psia

P2 = Downstream pressure, psiag = Acceleration of gravity = 32.2 ft/sec2 (10 m/s2)

k = Ratio, Cp/Cv, Sp heat at const press / Sp heat at const volume

r = Ratio P2/ P1≥ ro

ro = Critical Flow pressure ratio, [2/(k+1)] k/(k-1)

G = Specific gravity (Air = 1.0)

T = Inlet temperature, Deg R

Gas Passage Calculation

(2/ ) (( 1)/ )1155 2 ( / 1) [ ]k k k

dxC xAxP g k k x r rQ

GxT

Unloading Valve vs. Orifice: Gas Passage Comparison

Qgi

Pcsg

Ptbg

Orifice

Unloading Valve

Throttling Range

Differential Range

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Orifice vs. Venturi Valve: Gas Passage Comparison

Qgi

Pcsg

Ptbg

Orifice Valve

Venturi Valve

Pup / Pdown ratio = 0.53

Pup / Pdown ratio = 0.90

Critical Flow

Critical Flow

Sub-critical Flow

Valve Geometry Data Available from Supplier

Note: To access PDF of data, refer to the Valve Geometry Data listed with this lecture

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(15.6°C)

Note: To access PDF of data, refer to the Temperature CorrectionFactors listed with this lecture

Learning Objectives



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<Course Title>



Do you have reliable production data? Review the gas lift valve data that is

maintained in your asset. Is GLV failure a common observation? Any specific pointers contributing to valve failures?

Review the percentage of success of gas liftvalve change out jobs. What sort of impact this has on oil production?



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Gas Lift Optimization:Gas Lift Surveillance, Optimization and

Real Time Optimization (RTO)


Learning Objectives



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Three Levels of Optimization

• More a question of “maximising” productivity, and not strictly speakingan exercise in resource distribution

• Completion, stimulation, artificial lift designs, troubleshooting

Level I: Individual well performance optimisation

• Can take into consideration costs as well as revenue in deciding whereto allocate resources

• Lift gas allocation, electrical submersible pump (ESP) powerdistribution

Level II: Allocation of resources to maximise production from a “group” of wells

• True optimisation problem taking into account various possibilities forrevenue generation and different constraints present in theproduction system

• System automation through dynamic modelling linked to SCADA

Level III: Optimising overall performance of a production system

Lift Gas Allocation (Level II)

Available lift gas will be allocated to maximize oilproduction, considering gas lift efficiency of the wells

• Excess gas available: Increase lift gas to wells with highGas Lift Efficiency

• Gas Lift shortage (e.g., compressor issues): Decrease liftgas to wells with low GL efficiency (wells with very lowefficiency may be shut-in during the period)

Gas Lift Efficiency: Volume of oil produced for unitvolume of lift gas injected (e.g., BOPD/MMscfd)

A Well Efficiency ranking list maintained for this purpose

Used to manage short term variations of lift gas supply.Pressure drop in flowlines not taken into account

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A Typical Gas Lift System

Water

Export Gas

Fuel Gas

Lift Gas

Lift GasManifold

ProdManifold

ExternalFuel Supply

ProdManifold

ProdManifold

Oil

Total System Optimization

A total system optimization should consider:• Updated well performance with reservoir management

considerations• Effect of pressure drop in production system• Effect of pressure drop in gas lift supply system• Compression horsepower, performance, availability and costs• An iterative optimal solution with all input constraints considered,

to determine:– Optimum gas lift rate– Optimum gas lift pressure– Optimum production separator pressure– Include any constraints from reservoir management

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Production Optimization Cycle

SPE 126680

Gather field data (production/injection); Quality check the data

Feed data to asset models and

calibrate models

Perform optimization calculations and generate new set

points

Implement new set points; Stabilize

wells

Growth Grid for Gas Lift Optimization

Well & Network Offline

Optimization

Well & Network Real-time

Surveillance

Well & Network Real-time

Optimization

Well Gas Lift Offline

Optimization

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Learning Objectives








<Course Title>



Do you have reliable production data?

Discuss with your Optimization Team how frequent is their optimization cycle.

Do they see any benefit in including the pipeline networks and compressor performance as part of system optimization?



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Module Summary


Summary

In this module:• We have reviewed well performance analysis and identified

when artificial lift will be required for a well• We identified the reservoir and fluid parameters that will favor

the selection of gas lift as the artificial lift method for a well• We identified the factors that can affect the stability of flow and

how stable flow can be achieved in a gas lifted well• We discussed gas lift principles, their advantages and

disadvantages• We showed how well modeling can be used to determine the

production rate achievable by gas lift and to select optimumtubing size and other parameters for efficient gas lift

• We described essential equipment used at the surface and thesub-surface for a gas lifted well

• We reviewed types of gas lift valves commonly used in theindustry and their performance characteristics

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Summary (continued)

In this module:• We examined the force balance concepts used in the opening

/ closing of unloading valves and the calculation of test rackpressures of valves to be used in gas lift designs

• We made gas passage calculations for orifice valves• With the knowledge of unloading process and functioning of

gas lift valves, we created gas lift designs for an example wellwith multiple unloading stations and single point lift injection

• We reviewed factors that contribute to improved gas liftefficiency

• We summarized ways of performing gas lift surveillance andoptimization for wells and gas lift network systems

• We have done sufficient exercises and a case study toreinforce gas lift concepts and the industry practices

Learning Objectives

This section has covered the following learning objectives:

Explain the role of gas lift in a well performance analysis process

Explain the principles of multi-phase flow and the principle of gas lift

Identify the advantages and disadvantages of gas lift as an artificiallift method



Identify gas lift design methods

Establish well unloading procedures


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PetroAcademyTM Production Operations

Production Principles Core Well Performance and Nodal Analysis Fundamentals Onshore Conventional Well Completion Core Onshore Unconventional Well Completion Core Primary and Remedial Cementing Core Perforating Core Rod, PCP, Jet Pump and Plunger Lift Core Reciprocating Rod Pump Fundamentals Gas Lift and ESP Pump Core Gas Lift Fundamentals ESP Fundamentals Formation Damage and Matrix Stimulation Core Formation Damage and Matrix Acidizing Fundamentals Flow Assurance and Production Chemistry Core Sand Control Core Sand Control Fundamentals Hydraulic Fracturing Core Production Problem Diagnosis Core Production Logging Core Production Logging Fundamentals

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gas lift fundamentals...

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