Gas Lift Presentation #2

REDA-1: Gas Lift Products and Gas Lift System Design

INSTRUCTOR : Greg Stephenson

© Schlumberger, 2001

COURSE INTRODUCTION • INTRODUCTIONS • CLASS AIMS • INSTRUCTOR AIMS - Insight into in-exact science - Informed questions - Understand limitations - Participate in design

© Schlumberger, 2001

DAY 1 CONSTANT FLOW GAS LIFT WELL PRODUCED FLUID “FIRST THINGS FIRST.” INJECTION GAS

0

0

PRESSURE (PSI) 1000 2000

SIBHP

DEPTH (FT TVD)

• Course introduction 1000 CASING PRESSURE WHEN • Introduction to artificial lift WELL IS BEING GAS LIFTED 2000 • Types of gas lift 3000 • Applications of continuous flow gas lift OPERATING GAS LIFT VALVE • Advantages & disadvantages of gas lift 4000 • Basic introduction to gas lift principles 5000 • Continuous flow unloading sequence 6000 • Running and Pulling Gas Lift Valves 7000 FBHP

© Schlumberger, 2001

DAY 2 “ALLPRODUCED THE NUTS BOLTS.” FLOW GAS LIFT WELL FLUID ANDCONSTANT INJECTION GAS

0

0

PRESSURE (PSI) 1000 2000

DEPTH (FT TVD)

• Running and pulling gas lift valves 1000 CASING PRESSURE WHEN • Gas lift valve mechanics WELL IS BEING GAS LIFTED 2000 • Gas lift valves and accessories • Gas lift mandrels, latches, kickover tools 3000 • Surface flow control4000equipment OPERATING GAS LIFT VALVE 5000

SIBHP

6000

7000 FBHP

© Schlumberger, 2001

DAY 3 CONSTANT FLOW GAS LIFT WELL PRODUCED FLUID “WELL PERFORMANCE” INJECTION GAS

0

• Exam –Part I

0

PRESSURE (PSI) 1000 2000

1000

3000

OPERATING GAS LIFT VALVE 4000

5000

6000 SIBHP

performance.

DEPTH (FT TVD)

• Overview of inflow2000and outflow

CASING PRESSURE WHEN WELL IS BEING GAS LIFTED

7000 FBHP

© Schlumberger, 2001

DAY 4 “LET’S DO A GAS LIFT DESIGN!” CONSTANT FLOW GAS LIFT WELL PRODUCED FLUID INJECTION GAS

0

0

PRESSURE (PSI) 1000 2000

1000 •Natural gas laws applied to gasCASING lift.PRESSURE WHEN

WELL IS BEING GAS LIFTED 2000 •Flowing gradient exercises. DEPTH (FT TVD)

3000 •Gas lift design methods.

• IPO Gas lift design

OPERATING GAS LIFT VALVE

4000

• PPO Gas Lift Design 5000

SIBHP

6000

7000 FBHP

© Schlumberger, 2001

DAY 5 “GAS LIFT DESIGN AND TROUBLE-SHOOTING.” CONSTANT FLOW GAS LIFT WELL PRODUCED FLUID INJECTION GAS

0

0

PRESSURE (PSI) 1000 2000

1000 • Gas lift trouble-shooting techniques CASING PRESSURE WHEN

WELL IS BEING GAS LIFTED

• Exam – Part II

2000

DEPTH (FT TVD)

• Computer – Aided3000Gas Lift Designs / Evaluation • Course summary4000

OPERATING GAS LIFT VALVE

5000

SIBHP

6000

7000 FBHP

© Schlumberger, 2001

INTRODUCTION TO ARTIFICIAL LIFT KEY LEARNING OBJECTIVES UPON COMPLETION OF THIS SEGMENT, YOU SHOULD BE ABLE TO:

• • • • •

Name the 4 major forms of artificial lift. Fully describe the operation of each. Site at least 3 advantages and 3 disadvantages of each lift method. Identify the most appropriate lift method for a given application. Understand the business relevance of each lift method to Schlumberger.

© Schlumberger, 2001

TYPES OF ARTIFICIAL LIFT

© Schlumberger, 2001

“CHOOSING THE BEST LIFT METHOD” EXAMPLE

• • • • • • • • • • • • • •

10-well field accessed from a small offshore platform. Average production: 1800 bbls/D @ 10% water cut. Average production depth: 5500 ft MD 2-7/8” 6.5# tubing x 7-in 29# casing Dogleg: 5 degrees / 100 ft. BHT = 300 deg. F, Anticipated FBHP of 500 psi 1 Safety Barrier (SCSSV) It will not be necessary to access reservoir until re-completion. Stable formation on primary recovery. Fluid Viscosity = 50 cp, GOR = 500 scf/bbl, VLR = 0.07 Sand production = 15 ppm Well produces scale, treated w/ inhibitor – no other contaminants Electric power generation using natural gas for fuel All well service via workover rig and snubbing unit. © Schlumberger, 2001

OVERVIEW OF CONTINUOUS GAS LIFT KEY LEARNING OBJECTIVES UPON COMPLETION OF THIS SEGMENT, YOU SHOULD BE ABLE TO:

• • • •

Describe the two different types of gas lift and where they are applied. List the surface and sub-surface components of a typical closed rotative gas lift system. Describe, in detail, the continuous unloading sequence. Explain the purpose of unloading valves in a continuous gas lift well.

© Schlumberger, 2001

TYPES OF GAS LIFT • CONTINUOUS FLOW GAS LIFT • INTERMITTENT GAS LIFT • CONVENTIONAL & WIRELINE RETRIEVABLE GAS LIFT EQUIPMENT

© Schlumberger, 2001

APPLICATIONS OF CONTINUOUS FLOW GAS LIFT •

TO ENABLE WELLS THAT WILL NOT FLOW NATURALLY TO PRODUCE

•

TO INCREASE PRODUCTION RATES IN FLOWING WELLS

•

TO UNLOAD A WELL THAT WILL LATER FLOW NATURALLY

•

TO REMOVE OR UNLOAD FLUID IN GAS WELLS

•

TO BACK FLOW SALT WATER DISPOSAL WELLS

•

TO LIFT AQUIFER WELLS

© Schlumberger, 2001

ADVANTAGES OF GAS LIFT • Initial downhole equipment costs lower

• low operational and maintenance cost • Simplified well completions

• Flexibility - can handle rates from 10 to 50,000 bpd • Can best handle sand / gas / well deviation • Intervention relatively less expensive © Schlumberger, 2001

DISADVANTAGES OF GAS LIFT

• Must have a source of gas •Imported from other fields •Produced gas - may result in start up problems

• Possible high installation cost •Top sides modifications to existing platforms •Compressor installation

• Limited by available reservoir pressure and bottom hole flowing pressure © Schlumberger, 2001

CONSTANT FLOW GAS LIFT WELL

PRODUCED FLUID

0

INJECTION GAS

PRESSURE (PSI) 1000

2000

0

1000 CASING PRESSURE WHEN WELL IS BEING GAS LIFTED

3000

OPERATING GAS LIFT VALVE 4000

5000

6000

7000

SIBHP

DEPTH (FT TVD)

2000

© Schlumberger, 2001 FBHP

CONSTANT FLOW GAS LIFT WELL

PRODUCED FLUID

0

INJECTION GAS

PRESSURE (PSI) 1000

2000

0

1000 CASING PRESSURE WHEN WELL IS BEING GAS LIFTED

3000

4000

5000

OPERATING GAS LIFT VALVE

6000

SIBHP

DEPTH (FT TVD)

2000

7000

© Schlumberger, 2001 FBHP

CONTINUOUS FLOW UNLOADING SEQUENCE

© Schlumberger, 2001

TO SEPARATOR/STOCK TANK

INJECTION GAS

TO SEPARATOR/STOCK TANK

INJECTION GAS

© Schlumberger, 2001

TO SEPARATOR/STOCK TANK

INJECTION GAS

TO SEPARATOR/STOCK TANK

INJECTION GAS

© Schlumberger, 2001

TO SEPARATOR/STOCK TANK INJECTION GAS

TO SEPARATOR/STOCK TANK INJECTION GAS

PLUGGED

© Schlumberger, 2001

PRODUCED FLUID

INJECTION GAS

© Schlumberger, 2001

TO SEPARATOR/STOCK TANK

PRESSURE PSI 0

1000

2000

3000

4000

5000

6000

7000

INJECTION GAS CHOKE CLOSED

2000

TOP VALVE OPEN

THIRD VALVE OPEN

DEPTH FTTVD

SECOND VALVE OPEN

4000

6000

8000

10000 FOURTH VALVE OPEN

12000

14000

TUBING PRESSURE CASING PRESSURE

SIBHP

© Schlumberger, 2001

TO SEPARATOR/STOCK TANK

PRESSURE PSI 0

1000

2000

3000

4000

5000

6000

7000

INJECTION GAS CHOKE OPEN

2000

4000

SECOND VALVE OPEN

THIRD VALVE OPEN

DEPTH FTTVD

TOP VALVE OPEN

6000

8000

10000 FOURTH VALVE OPEN

12000

14000

TUBING PRESSURE CASING PRESSURE

SIBHP

© Schlumberger, 2001

PRESSURE PSI

TO SEPARATOR/STOCK TANK

0

1000

2000

3000

4000

5000

6000

7000

INJECTION GAS CHOKE OPEN

2000

4000

SECOND VALVE OPEN

THIRD VALVE OPEN

DEPTH FTTVD

TOP VALVE OPEN

6000

8000

10000 FOURTH VALVE OPEN

12000

14000

TUBING PRESSURE CASING PRESSURE

SIBHP

© Schlumberger, 2001

PRESSURE PSI

TO SEPARATOR/STOCK TANK

0

1000

2000

3000

4000

5000

6000

7000

INJECTION GAS CHOKE OPEN

2000

4000

SECOND VALVE OPEN

THIRD VALVE OPEN

DEPTH FTTVD

TOP VALVE OPEN

6000

8000

10000 FOURTH VALVE OPEN

12000

14000

DRAWDOWN

TUBING PRESSURE CASING PRESSURE

FBHP

SIBHP

© Schlumberger, 2001

TO SEPARATOR/STOCK TANK

PRESSURE PSI 0

1000

2000

3000

4000

5000

6000

7000

INJECTION GAS CHOKE OPEN

2000

4000

SECOND VALVE OPEN

THIRD VALVE OPEN

DEPTH FTTVD

TOP VALVE OPEN

6000

8000

10000 FOURTH VALVE OPEN

12000

14000

DRAWDOWN

TUBING PRESSURE CASING PRESSURE

FBHP

SIBHP

© Schlumberger, 2001

PRESSURE PSI

TO SEPARATOR/STOCK TANK

0

1000

2000

3000

4000

5000

6000

7000

INJECTION GAS CHOKE OPEN

2000

4000

SECOND VALVE OPEN

THIRD VALVE OPEN

DEPTH FTTVD

TOP VALVE CLOSED

6000

8000

10000 FOURTH VALVE OPEN

12000

14000

DRAWDOWN

TUBING PRESSURE CASING PRESSURE

FBHP

SIBHP

© Schlumberger, 2001

PRESSURE PSI

TO SEPARATOR/STOCK TANK

0

1000

2000

3000

4000

5000

6000

7000

INJECTION GAS CHOKE OPEN

2000

4000

SECOND VALVE OPEN

THIRD VALVE OPEN

FOURTH VALVE OPEN

DEPTH FTTVD

TOP VALVE CLOSED

6000

8000

10000

12000

14000

DRAWDOWN

TUBING PRESSURE CASING PRESSURE

FBHP

SIBHP

© Schlumberger, 2001

PRESSURE PSI

TO SEPARATOR/STOCK TANK

0

INJECTION GAS CHOKE OPEN

1000

2000

3000

4000

5000

6000

7000

2000

4000

SECOND VALVE CLOSED

THIRD VALVE OPEN

FOURTH VALVE OPEN

DEPTH FTTVD

TOP VALVE CLOSED

6000

8000

10000

12000

14000

DRAWDOWN

TUBING PRESSURE CASING PRESSURE

FBHP

SIBHP

© Schlumberger, 2001

FIGURE 3-8: Example of the Unloading Sequence Casing Operated Valves and Choke Control of Injection Gas 2000 1800 1600

Pressure psi

1400 1200 1000 800 600 400 200 0 12:00 AM

03:00 AM

06:00 AM

PRESSURE CASING

09:00 AM Time

12:00 PM

03:00 PM

06:00 PM

PRESSURE TUBING

© Schlumberger, 2001

GAS LIFT WELL KICK-OFF • Unload well carefully – 50 - 100 psi (3.5 bar) per 10 min – 1 - 2 bbl per min

• • • • • • •

Maximize production choke opening Gradually increase gas injection rate Monitor well clean up and stability Get to target position Perform step rate production test Optimize gas injection rate Note - when unloading all valves open! © Schlumberger, 2001

RUNNING AND PULLING GAS LIFT VALVES KEY LEARNING OBJECTIVES UPON COMPLETION OF THIS SEGMENT, YOU SHOULD BE ABLE TO:

• • • • •

Explain the procedure for running and pulling gas lift valves from a side pocket mandrel. Describe the precautions that should be taken during running and pulling operations. Explain the operation of the OK series kickover tool. Explain the operation of the BK-1 latch. List and describe the different latch profiles available and explain the importance of latch / pocket compatability.

© Schlumberger, 2001

GAS LIFT VALVE CHANGEOUTS! • • • • • • • •

Methodical Equalise pressure Valve catcher Latches Running / pulling tools Pressure tests Experience Risk © Schlumberger, 2001

KICKOVER TOOL THE KICKOVER TOOL IS RUN ON WIRELINE AND USED TO PULL AND SET GAS LIFT VALVES. THE ABILITY TO WIRELINE CHANGE-OUT GAS LIFT VALVES GIVES GREAT FLEXIBILITY IN THE GAS LIFT DESIGN

© Schlumberger, 2001

© Schlumberger, 2001

© Schlumberger, 2001

GAS LIFT VALVE LATCHES KEY LEARNING OBJECTIVES UPON COMPLETION OF THIS SEGMENT, YOU SHOULD BE ABLE TO:

• • •

Understand the purpose of a gas lift valve latch. Identify key latch components. Explain the operation of a latch.

© Schlumberger, 2001

© Schlumberger, 2001

RK / BK LATCH

THERE ARE OTHER LATCHES • 1-1/2” RK • 1-1/2” RA • 1-1/2” RM • T2 LATCHES • 1” BK

© Schlumberger, 2001

END DAY 1

© Schlumberger, 2001

DAY 2 “ALLPRODUCED THE NUTS BOLTS.” FLOW GAS LIFT WELL FLUID ANDCONSTANT INJECTION GAS

0

0

PRESSURE (PSI) 1000 2000

DEPTH (FT TVD)

• Gas lift mandrels 1000 • Gas lift valve mechanics 2000 • Gas lift valves and accessories • Surface flow control3000equipment

CASING PRESSURE WHEN WELL IS BEING GAS LIFTED

OPERATING GAS LIFT VALVE 4000

5000

SIBHP

6000

7000 FBHP

© Schlumberger, 2001

GAS LIFT MANDRELS KEY LEARNING OBJECTIVES UPON COMPLETION OF THIS SEGMENT, YOU SHOULD BE ABLE TO:

•

• • • • •

Understand the features / benefits, operation and nomenclature of: •Orienting-style mandrels. •Non-orienting mandrels. •Conventional mandrels. Identify and explain the purpose of key SPM components. Describe how pressure rating is determined for SPM‟s. Identify an appropriate SPM based on its nomenclature. Explain advantages and disadvantages of oval / round GLM‟s. Understand SPM manufacturing processes.

© Schlumberger, 2001

GAS LIFT MANDRELS

SIDE POCKET MANDRELS

CONVENTIONAL MANDREL

© Schlumberger, 2001

5 1/2” MMRG-4, 1 1/2” POCKET ROUND MANDREL DESIGN Orienting Sleeve

CAMCO Tool Discriminator

„G‟ Latch Lug

Polished Seal Bore

ENGINEERING DATA PART NUMBER SIZE MAX O.D. MIN I.D. DRIFT I.D. THREAD TEST PRESSURE INTERNAL TEST PRESSURE EXTERNAL LATCH TYPE KICKOVER TOOL RUNNING TOOL PULLING TOOL MATERIAL TENSILE STRENGTH (EOEC)

05712-000-00001 5 1/2” 7.982” 4.756” 4.653” 17 LB/FT MANN BDS B x P 7740 PSI 6280 PSI RK, RK-1, RKP, RK-SP OM-1, OM-1M, OM-1S RK-1 15079 1 5/8” JDS 15155 410 S.S., 13 CR 22 HRC MAX 490,000 LBS

CAMCO 1996

© Schlumberger, 2001

© Schlumberger, 2001

© Schlumberger, 2001

© Schlumberger, 2001

GAS LIFT MANDREL NOMENCLATURE BASIC DESIGN FEATURES KB M M M G R T A U E EC W

1ST IDENTIFIER 1ST IDENTIFIER 2ND IDENTIFIER 3RD IDENTIFIER

1" POCKET 1-1/2" POCKET OVAL BODY PIPE MACHINED POCKET W/TOOL DISCRIMINATOR TOOL DISCRIMNINATOR AND ORIENTING SLEEVE CAMCO DESIGN - ROUND BODY PIPE TRUGUIDE DESIGN - ROUND BODY PIPE A POCKET PROFILE REDUCED O.D. AND I.D. STANDARD POCKET PORTING - BOTTOM EXHAUST POCKET PORTED TO TUBING - BOTTOM EXHAUST WATERFLOOD BASIC DESIGN VARIATIONS

2 3 4 5 7 8 9 10 LT LTS V

SLIGHTLY REDUCED MAJOR O.D. SPECIAL THREADING CONSIDERATIONS THREAD RECUTS EXTERNAL GUARD DEVICES SPECIAL INTERNAL MODIFICATIONS SPECIAL POCKET MODIFICATION BOTTOM LATCH ONLY PLUGGABLE OR NO PORTS SIDEPIPE POCKET PORTING SIDELUG TO ACCEPT INJECTION TUBE MULTIPLE POCKET

© Schlumberger, 2001

GAS LIFT VALVES AND ACCESSORIES KEY LEARNING OBJECTIVES UPON COMPLETION OF THIS SEGMENT, YOU SHOULD BE ABLE TO:

• •

Derive the formula for opening pressure based on knowledge of valve mechanics and the force-balance equation. Describe models, operation, features/benefits, pros and cons of: •Unloading Valves •Proportional Response Valves •Orifice Valves •NOVA Venturi Orifice Valves •Shear Orifice Valves •Dummy Valves •Equalizing Dummy Valves •Circulating Valves •Chemical Injection Valves •Waterflood Flow Regulator Valves •Reverse Flow Check Valves © Schlumberger, 2001

GAS LIFT VALVE MECHANICS

© Schlumberger, 2001

GAS LIFT VALVE MECHANICS 3 basic types of gas lift valve, each available in 1” & 1-1/2” sizes:

Dummy valves Orifice valves • Square edged • Venturi (nova)

Unloading valves • Injection pressure (casing) operated valves • production pressure (fluid) operated valves • Throttling/proportional response valves

© Schlumberger, 2001

UNLOADING GAS LIFT VALVE • Normally required during unloading phase only • Open only when annulus and tubing pressures are high enough to overcome valve set pressure • Valve closes after transfer to next station • May be spring or nitrogen charged

© Schlumberger, 2001

Diaphragm/ Atmospheric Bellows Spring

Stem

Upstream/ Casing

Stem Tip Upstream Downstream

Port Downstream/Tubing

Pressure Regulator

Spring Operated Gas Lift Valve © Schlumberger, 2001

VALVE OPENING & CLOSING PRESSURES F=PXA

Pd

WHEN THE VALVE IS CLOSED TO OPEN IT….. 1 Pd x Ab= Pc (Ab - Ap) + Pt Ap

Pd 2

Pc 1

Pc

WHEN THE VALVE IS OPEN TO CLOSE IT….. 2 Pd x Ab = Pc (Ab)

Pt UN BALANCED VALVE © Schlumberger, 2001

VALVE OPENING & CLOSING PRESSURES CLOSING FORCE (IPO VALVE)

Fc = PbAb

OPENING FORCES (IPO VALVE)

Fo1 = Pc (Ab- Ap) Fo2 = Pt Ap

TOTAL OPENING FORCE

Fo = Pc (Ab - Ap) + Pt Ap

JUST BEFORE THE VALVE OPENS THE FORCES ARE EQUAL Pc (Ab - Ap) + Pt Ap = Pb Ab

SOLVING FOR Pc WHERE:

Pb - Pt (Ap/Ab) Pc = -------------------------1 - (Ap/Ab) Pb = Pressure in bellows Pt = Tubing pressure Pc = Casing pressure Ab = Area of bellows Ap = Area of port © Schlumberger, 2001

VALVE OPENING & CLOSING PRESSURES Pc =

Pb - Pt (Ap/Ab) ---------------------1 - (Ap/Ab)

Pc =

Pb - Pt (R) ---------------------1-R

Pb = Pc (1 - R) + Pt (R)

Where R = Ratio Ap/Ab © Schlumberger, 2001

PRODUCED FLUID

0

500

1000

1500

2000

2500

3000

3500

INJECTION GAS

2000

DEPTH FTTVD

4000

6000

8000

10000

12000

14000

DRAWDOWN

TUBING PRESSURE CASING PRESSURE

FBHP

SIBHP © Schlumberger, 2001

GAS LIFT VALVES CLOSE IN SEQUENCE 0

500

1000

1500

2000

2500

3000

3500

2000

DEPTH FTTVD

4000

6000

8000

10000

12000

14000

DRAWDOWN

TUBING PRESSURE CASING PRESSURE

FBHP

SIBHP

© Schlumberger, 2001

CASING P. TO OPEN

PRODUCED FLUID

INJECTION GAS

CASING P TO CLOSE DOME P.

AT SURFACE

1200 PSI

? PSI

TUBING P. @ DEPTH VALVE # 1

1260 PSI

? PSI

VALVE # 2

1300 PSI

? PSI

VALVE # 3

1340 PSI

? PSI

560 PSI

740 PSI

890 PSI

Pd = Pc (1-R) + Pt (R) NOTE : ALL VALVES 3/16” R-20 R = 0.038 1-R = 0.962

© Schlumberger, 2001

Pb

Pb

Dome

Dome

Chevron Packing Stack

Chevron Packing Stack

Bellows

Bellows

Stem Tip (Ball) Pc

Square Edged Seat

Pc

Stem Tip (Ball) Square Edged Seat Pt Chevron Packing Stack

Pt

Check Valve

Nitrogen Charged Bellows Type Injection Pressure (Casing) Operated Gas Lift Valve

Chevron Packing Stack

Check Valve

Nitrogen Charged Bellows Type Production Pressure (Fluid) Operated©Gas Lift Valve 2001 Schlumberger,

Dome

Pb Atmospheric Bellows

Spring

Chevron Packing Stack Bellows

Chevron Packing Stack

Pc

Spring Adjustment Nut & Lock Nuts

Large T.C. Ball Tapered T.C. Seat Chevron Packing Stack

Pc

Pt

Check Valve

Nitrogen Charged Bellows Type Proportional Response Gas Lift Valve

Stem Tip (Ball) Square Edged Seat Chevron Packing Stack

Pt

Check Valve

Spring Operated Injection Pressure (Casing) Operated Gas Lift Valve

© Schlumberger, 2001

© Schlumberger, 2001

© Schlumberger, 2001

GAS LIFT VALVE FEATURES • • • • • • •

Bellows protection Max dome charge Check valve Stem travel Metallurgy Elastomers Max fluid rate

© Schlumberger, 2001

OPERATING GAS LIFT VALVE • Typically an „orifice‟ type Gas lift valve • always open - allows gas across Passage whenever correct differential exists • Gas injection controlled by size and differential across replaceable choke • Back-check prevents reverse flow of well fluids from the production conduit

© Schlumberger, 2001

ORIFICE VALVES THERE ARE 2 TYPES OF ORIFICE VALVE: • SQUARED EDGED ORIFICE • VENTURI (NOVA)

• Valve designed for accurate gas passage prediction.

• One-way check valve for tubing integrity.

© Schlumberger, 2001

NOVA VALVE

© Schlumberger, 2001

EQUIPMENT SUMMARY • Side pocket mandrels • IPO unloading valves • Fluid pressure operated valves • Proportional response valves • Orifice valves • Shear open valves • Latch system • Dump kill valves • Circulating valves • Pilot valves • Check systems • Waterflood regulators • Chemical injection systems • Time cycle controllers © Schlumberger, 2001

SURFACE ACTUATED/CONTROLLED GAS LIFT VALVE

• Hydraulic controlled valve • Electric controlled valve

© Schlumberger, 2001

SURFACE FLOW CONTROL EQUIPMENT KEY LEARNING OBJECTIVES UPON COMPLETION OF THIS SEGMENT, YOU SHOULD BE ABLE TO:

•

Describe models, operation, features/benefits, pros and cons of: •Flow Control Valves •Adjustable Choke Valves •Surface Flow Control Accessories

© Schlumberger, 2001

Well Completions and Productivity Completion Systems

© Schlumberger, 2001

Well Completions & Productivity Completion Systems

Surface Flow Control Equipment

© Schlumberger, 2001

Surface Flow Control Equipment • Primary Purpose –

Control and measure flow from a producing oil and gas well, secondary recovery water or gas injection well and injected gas in a gas lift field operation.

• Secondary Purpose –

Real time flow control measurement which allows precise valve positioning from a remote RTU by use of an electric actuator with 4Milliamps or digital hart communication control.

© Schlumberger, 2001

Surface Flow Control Equipment • Applications – All producing oil and gas wells – Platform gas lift manifolds – Water or gas secondary recovery/pressure maintenance projects – All wells employing electrical submersible pump systems

© Schlumberger, 2001

Manual Injection Control for Gas Lift

CN00998

Camco/Merla FCV flow control valve

• Packing and trim changed without removing body from line • Easy-to-read indicator ring in 1/64 in. scale • Variety of trim sizes, materials and connections © Schlumberger, 2001

Prevent Reverse Flow into Gas Lift Lines • Floating seat acts as check valve to prevent reverse flow

CN00998

CN00998

Optional Seat for Reverse Flow Check

Camco/Merla FCV flow control valve

© Schlumberger, 2001

Injection Control for High-Temperature Application • Primarily designed for steam injection

CN01000

Camco/Merla FCVT high temperature flow control valve

• Applicable for service with other high-temperature gas or liquids • Easy-to-read 1/64 in. indicator scale • Rated to 3500 psi at 700°F • 2-in. angle body with various trim sizes and materials © Schlumberger, 2001

Manual Injection Control for Waterflood Systems • Designed for water injection applications

CN01026

Camco/Merla WFC water flood control valve

• Long throat seat controls turbulence and erosion • Adjustable hand wheel calibrated in 1/64 in. with easy-to-read indicator • Secondary choke option for high differentials • Available in variety of trim sizes and materials © Schlumberger, 2001

Adjustable Choke Valves for Production • Three body sizes for accurate match to flow rate – ACV-5, ACV-8 and ACV-12

• Common Features

– Available with API or ANSI flanges, socket weld, butt weld or threaded connections – Variety of trim and body materials to match application – No stem leaks with spring-loaded, bubble-tight sealing system CN00997

ACV-5

CN01002

ACV-8

CN01003

ACV-12 © Schlumberger, 2001

Adjustable Choke Valves for Production • Low flow rate applications (ACV-5) /4-in., 1-in. and 11/4in. port sizes – Maximum Cv values: –

3

19.3 to 35

CN00997

Camco/Merla ACV-5 adjustable choke valve

© Schlumberger, 2001

Adjustable Choke Valves for Production • Medium flow rate applications (ACV-8) –1-in., 11/2-in. and 2-in. port sizes –Maximum Cv values: 30.8 to 85.8

• High differential pressure applications CN01002

–Optional positive choke bean

Camco/Merla ACV-8 adjustable choke valve

© Schlumberger, 2001

Adjustable Choke Valves for Production • High flow rate applications (ACV-12) –2-in. and 3-in. port sizes –Maximum Cv values: 124 to 285

• High differential pressure applications CN01003

–Semi-balanced stem feature for reduced torque

Camco/Merla ACV-12 adjustable choke valve © Schlumberger, 2001

Chokes to Reduce Erosion and Noise • Reduce cavitation or erosion damage CN01067

CAVROSION™ trim closed position

CN00996

CAVROSION trim throttling position

–Cavrosion trim

• Reduce noise levels –Cavnoise trim

• Reduce cavitation and noise CN01068

CAVNOISE™ trim

CN01066

CAVROSION/ CAVNOISE trim

–Combination Cavrosion/ Cavnoise trim

© Schlumberger, 2001

Remote Flow Control Applications • Actuators for electric control and automation systems – Available for FCV and ACV series valves – 120 Vac or 24 Vdc with low current draw for remote applications

CN01069

FCV with electric actuator

– High modulation rate for precise positioning

– 4-20 ma or Digital Hart communication control – Corrosion resistance housing © Schlumberger, 2001

Nonadjustable Choke Applications • Positive inline choke –Bean sizes from 1/2 to 3 in. –Beans easily replaced with body in flow line –In-line feature for bi-directional flow

CN01159

Camco/Merla positive in-line choke © Schlumberger, 2001

Control for Low-Pressure Liquids and Gas • Motor valves for onoff service –Intermittent lift control –Plunger lift control

–Separator dumps CN01001

• Motor valves for throttling service –Pressure regulators

–Back pressure valves Camco/Merla MV-60 motor valve

© Schlumberger, 2001

Strengths • • • • •

Name - SLB, MERLA, CAMCO Well engineered and field proven products SLB International locations Manufacturing Points - Houston and Maracaibo High pressure niche market

© Schlumberger, 2001

Development Opportunities • • • • •

Real time measurement market Fit with/integrated completions/target markets Complete ported cage designs Software design and trouble shooting package Complete 10k product design for speciality markets

© Schlumberger, 2001

Current Projects • WEB interphase software design and troubleshooting package. • Performing test with FCV/Jordan electric actuators using different material combinations, and thread types with and without special antigauling coating. • Complete conversions of all flow control products to sherpa.

© Schlumberger, 2001

END DAY 2

© Schlumberger, 2001

DAY 3 CONSTANT FLOW GAS LIFT WELL PRODUCED FLUID “WELL PERFORMANCE” INJECTION GAS

0

• Exam –Part I

0

PRESSURE (PSI) 1000 2000

1000

3000

OPERATING GAS LIFT VALVE 4000

5000

6000 SIBHP

performance.

DEPTH (FT TVD)

• Overview of inflow2000and outflow

CASING PRESSURE WHEN WELL IS BEING GAS LIFTED

7000 FBHP

© Schlumberger, 2001

OVERVIEW OF INFLOW AND OUTFLOW PERFORMANCE KEY LEARNING OBJECTIVES UPON COMPLETION OF THIS SEGMENT, YOU SHOULD BE ABLE TO:

• • • •

Use the linear PI relationship to predict a well‟s production. Explain the difference between a linear and non-linear IPR relationship. Understand the factors affecting a well‟s inflow performance. Understand the factors affecting a well‟s outflow performance.

© Schlumberger, 2001

SUCCESSFUL DESIGN DEPENDS UPON PREDICTION OF FLOWRATE Predicting Flowrates and Pressure Transients for Different Cases

© Schlumberger, 2001

SURFACE PRESSURE

PRODUCED FLUID

INJECTION GAS

WELL OUTFLOW RELATIONSHIP (VLP) or (TPC) BOTTOM HOLE PRESSURE AS A FUNCTION OF FLOWRATE

PRODUCTION POTENTIAL AS A FUNCTION OF PRODUCTION RATE

RESERVOIR PRESSURE

SANDFACE PRESSURE BHFP

WELL INFLOW (IPR)

© Schlumberger, 2001

WELL & RESERVOIR INFLOW PERFORMANCE ( Successful design depends upon prediction of flow rate)

TYPES OF RESERVOIR DRIVES

• Dissolved / solution gas drive • Gas cap drive • Water drive

© Schlumberger, 2001

© Schlumberger, 2001

WELL & RESERVOIR INFLOW PERFORMANCE ( Successful design depends upon prediction of flow rate)

DISSOLVED / SOLUTION GAS DRIVE • Constant volume • No water encroachment • Two phase flowing reservoir below bubble point • No gas cap • PI not linear • PI declines with depletion • Formation GOR increases with depletion • Least efficient with circa 15% recovery

© Schlumberger, 2001

© Schlumberger, 2001

WELL & RESERVOIR INFLOW PERFORMANCE ( Successful design depends upon prediction of flow rate)

GAS CAP DRIVE

• Gas from solution will form gas cap • With production gas cap increases providing drive • Excessive drawdown can cause coning • PI usually not linear • GOR constant except near depletion • Circa 25% recovery

© Schlumberger, 2001

© Schlumberger, 2001

WELL & RESERVOIR INFLOW PERFORMANCE ( Successful design depends upon prediction of flow rate)

WATER DRIVE

• Not constant volume • Reservoir pressure more constant - expansion of Water 1 in 2500 per 100 psi • PI more constant • GOR more constant • Combination of water drive & gas cap expansion • Often supplemented by water injection • Most efficient with upto 50% recovery

© Schlumberger, 2001

WELL & RESERVOIR INFLOW PERFORMANCE ( Successful design depends upon prediction of flow rate)

DEPLETION DRIVE

• • • • •

Small isolated pockets No pressure support High rates initially Very quick depletion May use several artificial lift methods • Natural flow initially • Continuous gas lift • Intermittent gas lift

© Schlumberger, 2001

IDEAL FLOW ASSUMPTIONS • • • • • • • • • • • • • •

Ideal well Purely radial flow Infinite reservoir Uniform thickness Stabilized flow Single phase Above bubble point Homogeneous & isotropic reservoir Perforations penetrate throughout reservoir Reservoir shape Proximity of wellbore Wellbore clean / uncased No skin Darcy‟s law © Schlumberger, 2001

NON IDEAL FLOW • • • • • • • • •

Departures from Darcy‟s law Effects at boundaries Position of well Non homogeneous reservoir Perforation positions High velocities Fluid type / high GOR Transient behavior Relative permeability effects - oil/water/gas near the wellbore • Depletion if reservoir • Flow restrictions (skin) © Schlumberger, 2001

WELL & RESERVOIR INFLOW PERFORMANCE ( Successful design depends upon prediction of flow rate)

• Straight line productivity index (PI) • Inflow performance relationship (IPR)

© Schlumberger, 2001

WELL & RESERVOIR INFLOW PERFORMANCE ( Successful design depends upon prediction of flow rate)

PRODUCTIVITY INDEX

The relationship between well inflow rate and pressure drawdown can be expressed in the form of a Productivity Index, denoted „PI‟ or „J‟, where:

q = J(Pws - Pwf) or

q J = -----------------Pws - Pwf

kh(Pav - Pwf) qo = ----------------------------------141.2  oBo.[ln(re/rw) - 3/4] © Schlumberger, 2001

WELL & RESERVOIR INFLOW PERFORMANCE ( Successful design depends upon prediction of flow rate)

FACTORS AFFECTING PI

1. Phase behaviour •Bubble point pressure •Dew point pressure

2. Relative permeability behaviour •Ratio of effective permeability to a particular fluid (oil, gas or water) to the absolute permeability of the rock

3. Oil viscosity •Viscosity decreases with pressure decrease to Pb •Viscosity increases as gas comes out of solution

4. Oil formation volume factor (bo) •As pressure is decreased the liquid will expand •As gas comes out of solution oil will shrink © Schlumberger, 2001

WELL & RESERVOIR INFLOW PERFORMANCE ( Successful design depends upon prediction of flow rate)

AS RATE INCREASES IS NO LONGER STRAIGHT LINE • Increased gas sat. Near wellbore - rel. Perm. Effects • Laminar > turbulent flow • Exceeds critical flow of sandface

© Schlumberger, 2001

WELL & RESERVOIR INFLOW PERFORMANCE ( Successful design depends upon prediction of flow rate)

INFLOW PERFORMANCE RELATIONSHIP • Vogel • Back pressure/Fetkovich • Lit (Jones, Blount and Glaze) • Normalized pseudo pressure

© Schlumberger, 2001

WELL & RESERVOIR INFLOW PERFORMANCE ( Successful design depends upon prediction of flow rate)

VOGEL Dimensionless reference curve based on the following equation:

Q/Qmax = 1 - 0.2(Pwf/Pws) - 0.8(Pwf/Pws)2 where:

Q = the liquid production rate, stb/d Qmax = the maximum liquid rate for 100% drawdown Pwf = bottom hole flowing pressure, psi Pws = the reservoir pressure, psi

© Schlumberger, 2001

Pbhf/Pbhs

Dimensionless Inflow Performance Relationship Curve for Solution Gas Drive Reservoir (after Vogel) 1.00 0.90 0.80 0.70 0.60 0.50 0.40 0.30 0.20 0.10 0.00 0.00

0.10

0.20

0.30

0.40

0.50 Q/Qmax

0.60

0.70

0.80

0.90

1.00

© Schlumberger, 2001

© Schlumberger, 2001

EXERCISE

© Schlumberger, 2001

SURFACE PRESSURE

PRODUCED FLUID

INJECTION GAS

WELL OUTFLOW RELATIONSHIP (VLP) or (TPC) BOTTOM HOLE PRESSURE AS A FUNCTION OF FLOWRATE

PRODUCTION POTENTIAL AS A FUNCTION OF PRODUCTION RATE

RESERVOIR PRESSURE

SANDFACE PRESSURE BHFP

WELL INFLOW (IPR)

© Schlumberger, 2001

MULTIPHASE FLOW OUTFLOW PERFORMANCE MOVEMENT OF A MIXTURE OF FREE GASES AND LIQUIDS

Vertical flowing gradients Horizontal flowing gradients

© Schlumberger, 2001

OUTFLOW PERFORMANCE AND MULTIPHASE FLOW MOVEMENT OF A MIXTURE OF FREE GASES AND LIQUIDS

Vertical flowing gradients Horizontal flowing gradients • Select correct tubing size • Predict when artificial lift will be required • Design artificial lift systems • Determine BHFP • Determine PI • Predict maximum and/or optimum flow rate • Determine maximum depth of injection

© Schlumberger, 2001

FACTORS EFFECTING TPC/VLP/TPR • • • • • • • • • • • • •

TPC is a function of physical properties not inflow Tubing id Wall roughness Inclination Liquid / gas density Liquid / gas viscosity Liquid / gas velocity Well depth / line lengths Surface pressure Watercut GOR / GLR Liquid surface tension Flowrate © Schlumberger, 2001

PRESSURE LOSS IN WELLBORE

„Complicated expression‟

© Schlumberger, 2001

Z

P/Z

• System described by a energy balance expression • Mass energy per unit mass in = energy out • (+ - exchange with surroundings) • For wellbore- pressure Calc. for length of pipe • Integrated each section • Pressure conveniently divided into three terms © Schlumberger, 2001

PRESSURE LOSS IN WELLBORE TOTAL PRESSURE DIFFERENCE

GRAVITY TERM

FRICTION TERM

ACCELERATION TERM

2

P/Ztotal = g/gccos + fv /2gcd + v/gc[P/Z]

© Schlumberger, 2001

PRESSURE LOSS IN WELLBORE • Fluid density in every term • Errors would be accumulative • PVT important

© Schlumberger, 2001

VERTICAL GRADIENTS : GLR  PRESS  HORIZONTAL GRADIENTS : GLR  PRESS 

© Schlumberger, 2001

FLOW REGIMES • Based on observations • Different flow patterns – – – –

Proportion of phases Flow velocity Viscosities Interfacial tension

© Schlumberger, 2001

FLOW REGIMES

© Schlumberger, 2001

CORRELATIONS • • • • • • • • • • • •

Babson (1934) Gilbert (1939 / 1952) Poettmann & Carpenter (1952) Duns & Ros Hagedorn & Brown Orkiszewski Fancher & Brown Beggs &Brill Duckler Flannigan Gray Mechanistic Proprietary © Schlumberger, 2001

INFLOW AND OUTFLOW PERFORMANCE Pressure, psig 0 1000 2000 3000

5200

4000 5000

FBHP, psig

Depth, feet

5000 6000 7000

4800 4600

8000

4400

9000

4200

10000

0

1000

2000

3000

Rate, bbls/d

11000 12000 13000 14000 0

1000

2000

3000

4000

5000

© Schlumberger, 2001

© Schlumberger, 2001

© Schlumberger, 2001

APPLICATION OF FLOWING PRESSURE GRADIENTS / EXERCISES

© Schlumberger, 2001

END DAY 3

© Schlumberger, 2001

DAY 4 “LET’S DO A GAS LIFT DESIGN!” CONSTANT FLOW GAS LIFT WELL PRODUCED FLUID INJECTION GAS

0

0

PRESSURE (PSI) 1000 2000

1000 •Natural gas laws applied to gasCASING lift.PRESSURE WHEN

WELL IS BEING GAS LIFTED 2000 •Flowing gradient exercises. DEPTH (FT TVD)

3000 •Gas lift design methods.

• IPO Gas lift design

OPERATING GAS LIFT VALVE

4000

• PPO Gas Lift Design 5000

SIBHP

6000

7000 FBHP

© Schlumberger, 2001

NATURAL GAS LAWS APPLIED TO GAS LIFT KEY LEARNING OBJECTIVES

UPON COMPLETION OF THIS SEGMENT, YOU SHOULD BE ABLE TO:

• • •

Predict the casing pressure at depth for a gas lift well. Predict the gas passage through a square-edged orifice. Explain the relationship between a valve‟s bellows pressure and its temperature

© Schlumberger, 2001

GAS CALCULATIONS RELATED TO GAS LIFT SYSTEMS

• Gas injection pressure at depth

• Gas volume stored within a conduit • Temperature effect on bellows-charged dome pressure

• Volumetric gas throughput of a choke or g.L. Valve port

© Schlumberger, 2001

GAS CALCULATIONS RELATED TO GAS LIFT SYSTEMS GAS INJECTION PRESSURE AT DEPTH S.G. x L 53.34 x T x Z P@L = P@Se Where:

e = 2.71828 P@L = Pressure at depth, psia P@S = Pressure at surface, psia S.G. = Gas Specific Gravity L = Depth, feet T = Average Temp Degrees R Z = Average Compressibility for T and average pressure © Schlumberger, 2001

GAS CALCULATIONS RELATED TO GAS LIFT SYSTEMS GAS INJECTION PRESSURE AT DEPTH

“Rule of thumb” Equation based on S.G. of 0.65, a geothermal gradient at 1.60F/100ft and a surface temperature of 700F P@L = P@S + (2.3 x P@S x L ) 100 1000

Where:

P@L = Pressure at depth, psia P@S = Pressure at surface, psia L = Depth, feet © Schlumberger, 2001

GAS VOLUME STORED WITHIN A CONDUIT (see page 3-10)

Internal capacity of a single circular conduit Q(ft3/100ft.) = 0.5454 di2 Q(barrels/100ft.) = 0.009714 di2 Annular capacity of a tubing string inside casing Q(ft3/100ft.) = 0.5454 di2 - do2 Q(barrels/100ft.) = 0.009714 di2 - do2 Where:

di = inside diameter in inches do = outside diameter in inches

© Schlumberger, 2001

GAS VOLUME STORED WITHIN A CONDUIT To find the volume of gas contained under specific well conditions): P x Tb b = V x ---------------Z x Pb x T Where:

b = gas volume at base conditions V = capacity of conduit in cubic feet P = average pressure within conduit Tb= temperature base in degrees Rankin Z = compressibility factor for average pressure and temperature in a conduit (see Figure 3.2) Pb= pressure base (14.73 psi) T = average temperature in the conduit in degrees Rankin © Schlumberger, 2001

TEMPERATURE EFFECT ON CONFINED BELLOWS CHARGED DOME PRESSURE Major Advantages of Nitrogen

•Availability •Non-explosive •Non- corrosive •Predictable compressibility •Predictable temperature effect

© Schlumberger, 2001

TEMPERATURE EFFECT ON CONFINED BELLOWS CHARGED DOME PRESSURE P2 = P1 Where:

X

Tc P1 = Pressure at initial temperature P2 = Pressure resulting from change of temperature Tc = Temperature correction factor

and

1 + 0.00215 x (T2 - 60) Tc = -------------------------------1 + 0.00215 x (T1 - 60) Where :

T1 = Initial temperature, Deg F T2 = Present temperature, Deg F © Schlumberger, 2001

VOLUMETRIC GAS THROUGHPUT OF A CHOKE OR A GAS LIFT VALVE PORT Equation based on Thornhill-Craver Studies Page 3-13 Since this equation is so complex the chart in figure 7.4 page 7-14 provides a means of quickly obtaining an approximate gas passage rate for a given port size

© Schlumberger, 2001

GAS INJECTION RATE (MMSCF/D)

SUB-CRITICAL FLOW

ORIFICE FLOW

PTUBING = 55%

PRESSURE (PSI)

PCASING © Schlumberger, 2001

Gas Passage through a RDO-5 Orifice Valve with a 1/2" Port (163 deg F, Gas S.G. 0.83, Discharge Coefficient 0.84) 9

Gas Fl ow Rate MMSCF/D

8 7 6 5 4 3 2 1 0 0

100

200

300

400

500

600

700

800

900

1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000

Pressure psi

© Schlumberger, 2001

RDO-5 Orifice Valve, 24/64" Port, Cd = 0.86

5.00

4.50

4.00

Gas Flowrate (mmscf/d)

3.50

3.00

2.50

2.00

1.50

1.00

0.50

Calculated Flowrate

Measured Flowrate

Calculated Flowrate

Measured Flowrate

Calculated Flowrate

Measured Flowrate

Calculated Flowrate

Measured Flowrate

0.00 0.00

200.00

400.00

600.00

800.00

1000.00

1200.00

1400.00

1600.00

1800.00

2000.00

Downstream Pressure (psig)

© Schlumberger, 2001

IPO GAS LIFT DESIGN KEY LEARNING OBJECTIVES

UPON COMPLETION OF THIS SEGMENT, YOU SHOULD BE ABLE TO:

• • • •

Perform a gas lift design for a well utilizing injection pressure operated gas lift valves. List at least 3 possible sources of design bias in an IPO gas lift design. Explain the purpose of design bias and its effect on a gas lift design. Understand how a gas lift design can be developed to accommodate changing conditions over time.

© Schlumberger, 2001

MANDREL SPACING • For unloading • For flexibility

© Schlumberger, 2001

GAS LIFT DESIGN METHODS • Variety of design methods published – Pmax / P min – Casing Pressure drop – Equilibrium curve

• • • • •

Vary with application Vary with data Vary with experience Not an exact science We are dealing with a very dynamic system © Schlumberger, 2001

GAS LIFT DESIGNS • • • • •

Learn basics Do the designs by hand graphically Build mental picture of dynamic system Introduce „design bias‟ Think about it then apply

© Schlumberger, 2001

GAS LIFT DESIGNS • • • • •

New design Pre-spaced mandrels All methods require objective gradient Fixed rate design Optimum rate design

© Schlumberger, 2001

GAS LIFT DESIGNS Casing Pressure Drop Method

© Schlumberger, 2001

CAMCO GAS LIFT TECHNOLOGY - EXAMPLE DESIGN Constant Pdrop Method - No Design Bias PRESSURE (PSIG) 0

1000

2000

TEMPERATURE F 100

150

200

0

1000

2000

DEPTH FTTVD

3000

4000

5000

6000

7000

8000

9000

DEPTH OF WELL (MID PERFS)

10000

FIGURE 1

© Schlumberger, 2001

CAMCO GAS LIFT TECHNOLOGY - EXAMPLE DESIGN Constant Pdrop Method - No Design Bias PRESSURE (PSIG) 0

1000

2000

TEMPERATURE F 100

150

200

0

1000

2000

DEPTH FTTVD

3000

4000

5000

6000

7000

8000

9000

DEPTH OF WELL (MID PERFS) S.I.B.H.P.

10000

FIGURE 2

© Schlumberger, 2001

CAMCO GAS LIFT TECHNOLOGY - EXAMPLE DESIGN Constant Pdrop Method - No Design Bias PRESSURE (PSIG) 0

1000

2000

TEMPERATURE F 100

150

200

0

1000

2000

DEPTH FTTVD

3000

4000

5000

6000

7000

8000

9000

DEPTH OF WELL (MID PERFS) F.B.H.P.

S.I.B.H.P.

10000

FIGURE 3

© Schlumberger, 2001

CAMCO GAS LIFT TECHNOLOGY - EXAMPLE DESIGN Constant Pdrop Method - No Design Bias PRESSURE (PSIG) 0

1000

2000

TEMPERATURE F 100

150

200

0

1000

2000

DEPTH FTTVD

3000

4000

5000

6000

7000

8000

9000

DEPTH OF WELL (MID PERFS) F.B.H.P.

S.I.B.H.P.

10000

FIGURE 4

© Schlumberger, 2001

CAMCO GAS LIFT TECHNOLOGY - EXAMPLE DESIGN Constant Pdrop Method - No Design Bias PRESSURE (PSIG) 0

1000

2000

TEMPERATURE F 100

150

200

0

1000

2000

MANDREL #1

DEPTH FTTVD

3000

4000

5000

6000

7000

8000

9000

DEPTH OF WELL (MID PERFS) F.B.H.P.

S.I.B.H.P.

10000

FIGURE 5

© Schlumberger, 2001

CAMCO GAS LIFT TECHNOLOGY - EXAMPLE DESIGN Constant Pdrop Method - No Design Bias PRESSURE (PSIG) 0

1000

2000

TEMPERATURE F 100

150

200

0

1000

2000

MANDREL #1

DEPTH FTTVD

3000

4000

5000

6000

7000

8000

9000

F.B.H.P. #1 DEPTH OF WELL (MID PERFS) F.B.H.P.

S.I.B.H.P.

10000

FIGURE 6

© Schlumberger, 2001

CAMCO GAS LIFT TECHNOLOGY - EXAMPLE DESIGN Constant Pdrop Method - No Design Bias PRESSURE (PSIG) 0

1000

2000

TEMPERATURE F 100

150

200

0

1000

2000

MANDREL #1

3000

DEPTH FTTVD

MANDREL #2 4000

5000

6000

7000

8000

9000

DEPTH OF WELL (MID PERFS) F.B.H.P.

F.B.H.P. #2

S.I.B.H.P.

10000

FIGURE 7

© Schlumberger, 2001

CAMCO GAS LIFT TECHNOLOGY - EXAMPLE DESIGN Constant Pdrop Method - No Design Bias PRESSURE (PSIG) 0

1000

TEMPERATURE F

2000

100

150

200

0

1000

2000

MANDREL #1

3000

DEPTH FTTVD

MANDREL #2 4000

5000

MANDREL #3

6000

7000

8000

9000

DEPTH OF WELL (MID PERFS) F.B.H.P.

F.B.H.P. #3

S.I.B.H.P.

10000

FIGURE 8

© Schlumberger, 2001

CAMCO GAS LIFT TECHNOLOGY - EXAMPLE DESIGN Constant Pdrop Method - No Design Bias PRESSURE (PSIG) 0

1000

TEMPERATURE F

2000

100

150

200

0

1000

2000

MANDREL #1

3000

DEPTH FTTVD

MANDREL #2 4000

5000

MANDREL #3

6000 MANDREL #4

7000

8000

9000

DEPTH OF WELL (MID PERFS) F.B.H.P.

F.B.H.P. #4

S.I.B.H.P.

10000

FIGURE 9

© Schlumberger, 2001

CAMCO GAS LIFT TECHNOLOGY - EXAMPLE DESIGN Constant Pdrop Method - No Design Bias PRESSURE (PSIG) 0

1000

TEMPERATURE F

2000

100

150

200

0

1000

2000

MANDREL #1

3000

DEPTH FTTVD

MANDREL #2 4000

5000

MANDREL #3

6000 MANDREL #4

7000

MANDREL #5

8000

9000

DEPTH OF WELL (MID PERFS)

F.B.H.P. #5 F.B.H.P.

S.I.B.H.P.

10000

FIGURE 10

© Schlumberger, 2001

GAS LIFT DESIGN (P-MIN / P-MAX) Re-opening valves / valve interference (P-min / P-max / Production Pressure Effect)

© Schlumberger, 2001

#1. Pressure Pt Pc1

D e p t h

Valve #1

Pt@L

Pc @ L

Differential

30-50#

© Schlumberger, 2001

#2. Pressure Pt Pc1

D e p t h

Pc2 = Pc1-[ (Pt max-Pt min) (TEF)]

#1

Pt min

Pt max

Point A

50# Differential

© Schlumberger, 2001

#3. Pressure Pt Pc1

D e p t h

Pc1

Pc2=1000-[(750-425) (.104)] Pc2=966 psi (33.8 psi)

#1

Pt max

#2

Pt min 50# Differential

Point A

© Schlumberger, 2001

Pressure Pt

D e p t h

#4.

Pc2 Pc3

Pc1

Pc3=966-[(815-625) (.104)] #1

Pc3=946 psi (19.76 psi)

#2

#3

© Schlumberger, 2001

Pt

D e p t h

Pressure Pc3

#5.

Pc2 Pc1

#1

#2

#3

Pt min

Pt max

Point A

© Schlumberger, 2001

Pt

Pressure Pc3

#6.

Pc2 Pc1

Pc4

D e p t h

#1

#2

Pc = 946-[(925-750) (.104)] 4

#3

#4

Pt min

Pc4= 928 psi (18.2 psi)

(.05 x Depth) + Pwh

© Schlumberger, 2001

GAS LIFT DESIGN EXAMPLE (3 1/2”) GRADIENT CURVE - MANDREL SPACING

TUBING SIZE AVERAGE DEVIATION TARGET PRODUCTION RATE WATERCUT OIL API WATER S.G. GAS S.G. PACKER SETTING DEPTH END OF TUBING MID PERFORATION DEPTH WELLHEAD FLOWING PRESSURE SHUT IN BOTTOM HOLE PRESSURE PRODUCTIVITY INDEX FORMATION GOR CASING KICKOFF PRESSURE CASING OPERATING PRESSURE AVAILABLE GAS FOR INJECTION TEMPERATURE @ DEPTH KILL FLUID GRADIENT FLOW EFFICIENCY

: : : : : : : : : : : : : : : : : : : :

3.5” VERTICAL WELL 600 B/D 50 % 35O 1.08 0.65 7400 FT 7500 FT 8000 FT 175 psig 2800 psig .65 stb/d/psi 100:1 1150 psig 1100 psig 1 MMSCF/D 210O F 0.465 psi/ft 1 (no skin)

© Schlumberger, 2001

GAS LIFT DESIGNS Design Bias

© Schlumberger, 2001

DESIGN BIAS IN GAS LIFT DESIGN • Tubing head pressure • Tubing pressure / minimum gradient • Casing pressure drops to close valve systematically (disadvantage?) • Re-opening valves / Valve interference • Differential at bottom point • Casing pressure available • Design bias will vary depending on condition • Gas passage • Well coming in • Add some more mandrels? • Usually called „safety factors‟ © Schlumberger, 2001

INTRODUCING DESIGN BIAS INTO DESIGNS

© Schlumberger, 2001

CAMCO GAS LIFT TECHNOLOGY - EXAMPLE DESIGN Ptmin-Ptmax Method - with Design Bias PRESSURE (PSIG) 0

1000

2000

TEMPERATURE F 100

150

200

0

1000

2000

3000

DEPTH FTTVD

4000

5000

6000

7000

8000

9000

DEPTH OF WELL (MID PERFS)

10000

FIGURE 1

© Schlumberger, 2001

CAMCO GAS LIFT TECHNOLOGY - EXAMPLE DESIGN Ptmin-Ptmax Method - with Design Bias PRESSURE (PSIG) 0

1000

2000

TEMPERATURE F 100

150

200

0

1000

2000

3000

DEPTH FTTVD

4000

5000

6000

7000

8000

9000

DEPTH OF WELL (MID PERFS) S.I.B.H.P.

10000

FIGURE 2

© Schlumberger, 2001

CAMCO GAS LIFT TECHNOLOGY - EXAMPLE DESIGN Ptmin-Ptmax Method - with Design Bias PRESSURE (PSIG) 0

1000

2000

TEMPERATURE F 100

150

200

0

1000

2000

3000

DEPTH FTTVD

4000

5000

6000

7000

8000

9000

DEPTH OF WELL (MID PERFS) F.B.H.P.

S.I.B.H.P.

10000

FIGURE 3

© Schlumberger, 2001

CAMCO GAS LIFT TECHNOLOGY - EXAMPLE DESIGN Ptmin-Ptmax Method - with Design Bias PRESSURE (PSIG) 0

1000

2000

TEMPERATURE F 100

150

200

0

1000

2000

3000

DEPTH FTTVD

4000

5000

6000

7000

8000

9000

DEPTH OF WELL (MID PERFS) F.B.H.P.

S.I.B.H.P.

10000

FIGURE 4

© Schlumberger, 2001

CAMCO GAS LIFT TECHNOLOGY - EXAMPLE DESIGN Ptmin-Ptmax Method - with Design Bias PRESSURE (PSIG) 0

1000

2000

TEMPERATURE F 100

150

200

0

1000

2000

MANDREL #1

3000

DEPTH FTTVD

4000

5000

6000

7000

8000

9000

DEPTH OF WELL (MID PERFS) F.B.H.P.

S.I.B.H.P.

10000

FIGURE 5

© Schlumberger, 2001

CAMCO GAS LIFT TECHNOLOGY - EXAMPLE DESIGN Ptmin-Ptmax Method - with Design Bias PRESSURE (PSIG) 0

1000

2000

TEMPERATURE F 100

150

200

0

1000

2000

MANDREL #1

3000

DEPTH FTTVD

4000

5000

6000

7000

8000

9000

DEPTH OF WELL (MID PERFS)

F.B.H.P. #1 F.B.H.P.

S.I.B.H.P.

10000

FIGURE 6

© Schlumberger, 2001

CAMCO GAS LIFT TECHNOLOGY - EXAMPLE DESIGN Ptmin-Ptmax Method - with Design Bias PRESSURE (PSIG) 0

1000

2000

TEMPERATURE F 100

150

200

0

1000

2000

MANDREL #1

Ptmax1

Ptmin1 3000 MANDREL #2

DEPTH FTTVD

4000

5000

6000

7000

8000

9000

DEPTH OF WELL (MID PERFS) F.B.H.P.

F.B.H.P. #2

S.I.B.H.P.

10000

FIGURE 7

© Schlumberger, 2001

CAMCO GAS LIFT TECHNOLOGY - EXAMPLE DESIGN Ptmin-Ptmax Method - with Design Bias PRESSURE (PSIG) 0

1000

TEMPERATURE F

2000

100

150

200

0

1000

2000

MANDREL #1

3000 MANDREL #2

Ptmax2

DEPTH FTTVD

4000 Ptmin2 5000

MANDREL #3

6000

7000

8000

9000

DEPTH OF WELL (MID PERFS) F.B.H.P.

F.B.H.P. #3

S.I.B.H.P.

10000

FIGURE 8

© Schlumberger, 2001

CAMCO GAS LIFT TECHNOLOGY - EXAMPLE DESIGN Ptmin-Ptmax Method - with Design Bias PRESSURE (PSIG) 0

1000

TEMPERATURE F

2000

100

150

200

0

1000

2000

MANDREL #1

3000 MANDREL #2

DEPTH FTTVD

4000

5000

MANDREL #3

Ptmax3 Ptmin3

6000

MANDREL #4

7000

8000

9000

DEPTH OF WELL (MID PERFS) F.B.H.P.

F.B.H.P. #4

S.I.B.H.P.

10000

FIGURE 9

© Schlumberger, 2001

CAMCO GAS LIFT TECHNOLOGY - EXAMPLE DESIGN Ptmin-Ptmax Method - with Design Bias PRESSURE (PSIG) 0

1000

TEMPERATURE F

2000

100

150

200

0

1000

2000

MANDREL #1

3000 MANDREL #2

DEPTH FTTVD

4000

5000

6000

MANDREL #3

MANDREL #4

7000 MANDREL #5 8000

9000

DEPTH OF WELL (MID PERFS)

F.B.H.P. #5 F.B.H.P.

S.I.B.H.P.

10000

FIGURE 10

© Schlumberger, 2001

PPO GAS LIFT DESIGN KEY LEARNING OBJECTIVES

UPON COMPLETION OF THIS SEGMENT, YOU SHOULD BE ABLE TO:

• • • • •

Perform a gas lift design for a well utilizing production pressure operated gas lift valves. Explain the purpose of the “Design Line” in a PPO gas lift design. Explain the purpose of the “DP Line” in a PPO gas lift design. Understand the benefits and liabilities of PPO gas lift designs. Explain where a PPO gas lift installation would most likely be run and why.

© Schlumberger, 2001

EXAMPLE

© Schlumberger, 2001

END DAY 4

© Schlumberger, 2001

DAY 5 “GAS LIFT DESIGN AND TROUBLE-SHOOTING.” CONSTANT FLOW GAS LIFT WELL PRODUCED FLUID INJECTION GAS

0

0

PRESSURE (PSI) 1000 2000

1000 • Gas lift trouble-shooting techniques CASING PRESSURE WHEN

WELL IS BEING GAS LIFTED

• Exam – Part II

2000

DEPTH (FT TVD)

• Computer – Aided3000Gas Lift Designs / Evaluation • Course summary4000

OPERATING GAS LIFT VALVE

5000

SIBHP

6000

7000 FBHP

© Schlumberger, 2001

TROUBLE-SHOOTING KEY LEARNING OBJECTIVES

UPON COMPLETION OF THIS SEGMENT, YOU SHOULD BE ABLE TO:

• • • • •

List 5 tools that can aid in the trouble-shooting of gas lift wells. Understand the relationship between gas passage, valve mechanics, well performance and casing pressure. Utilize gradient curves, valve mechanics and gas passage to predict the point (or points) of injection in a gas lift well. Explain the cycle of instability in a well which is injecting in subcritical flow across a square-edged orifice. Explain how to determine if the tubing and casing are in communication.

© Schlumberger, 2001

TROUBLESHOOTING

FOCUS ORGANISATION & PROCESSES

TROUBLESHOOTING

PRODUCTION MANAGEMENT © Schlumberger, 2001

THE FOLLOWING DATA SHOULD BE REGULARLY MONITORED : • GAS INJECTION (PRODUCTION ANNULUS) PRESSURE • GAS INJECTION RATES • TUBING HEAD PRESSURE • WELL TESTS • TOTAL PRODUCTION • WATER CUTS

• TEMPERATURE SLUGGING : AN UNSTABLE SYSTEM SHOULD BE INVESTIGATED. SEVERE SLUGGING IS A MAJOR CONCERN. THE INITIAL START-UP AND LOADING IS THE WHEN THE WELL IS AT IT‟S MOST UNSTABLE.

© Schlumberger, 2001

CHANGE IN THE INJECTION PRESSURE CAN MEAN

INJECTION PRESSURE : THE MOST INFORMATIVE, IT INDICATES: • WHICH UNLOADING VALVES ARE OPEN • AND THE MAXIMUM DEPTH OF INJECTION

0

1000

2000

3000

4000

5000

6000

2000

4000

DEPTH FTTVD

RESTRICTIONS TO THE GAS FLOW, UPSTREAM OF THE GAS INJECTION CIRCULATING VALVE.



OPENING OF THE UNLOADING VALVE.



A CHANGE IN THE TUBING PRESSURE AT DEPTH (CHANGE IN WATER CUT)



A CHANGE IN THE GAS INJECTION RATE



A RESTRICTION IN THE CIRCULATING VALVE



THE CIRCULATING VALVE‟S PORT HAS BEEN FLOW CUT.



LOSS OF PRESSURE INTEGRITY IN EITHER THE TUBING OR THE INJECTION GAS FLOW LINE

7000

Pb

Pc



6000

8000

10000

12000 Pt

14000

DRAWDOWN

TUBING PRESSURE CASING PRESSURE

FBHP

SIBHP

© Schlumberger, 2001

GAS INJECTION RATE: HAS A LARGE INFLUENCE ON THE PRODUCTION RATE INABILITY TO INJECT GAS. THIS NORMALLY INDICATES A MECHANICAL FAILURE. GAS INJECTION IS RESTRICTED. COULD INDICATE :  AN INCREASE IN WATER CUT  WE ARE OPERATING AT THE UNLOADING VALVE.

© Schlumberger, 2001

WELL TESTS •

ACTUAL PRODUCTION RATE & WATER CUT

•

MULTI-RATE TESTING BETTER UNDERSTANDING OF THE WELL

WATER CUTS •

ERRATIC WATER CUTS CAN INDICATE A SLUGGING WELL

© Schlumberger, 2001

TUBING PRESSURE : THE TUBING HEAD PRESSURE (THP) & WELL HEAD TEMPERATURE INDICATE THE WELL IS FLOWING. A DECREASE IN TUBING PRESSURE CAN INDICATE A LOSS OF PRODUCTION DUE TO : •

A CHANGE IN THE INJECTION DEPTH

•

AN INCREASE IN WATER CUT.

AN INCREASE IN TUBING PRESSURE : •

COULD BE AS A RESULT OF EXCESS GAS INJECTION

•

CAN AFFECT THE CASING PRESSURE.

TUBING INSTABILITY CAN BE CAUSED BY : •

CASING PRESSURE INSTABILITY (MULTI-POINTING OR INCORRECTLY SIZED CIRCULATING VALVE)

•

TOO LARGE A TUBING SIZE.

© Schlumberger, 2001

TEMPERATURE

© Schlumberger, 2001

TROUBLESHOOTING •Inlet problems •Choke sized too large •Choke sized too small •Low casing pressure •High casing pressure •Verify gauges •Low gas volume

•Excessive gas volume •Compressor fluctuations © Schlumberger, 2001

TROUBLESHOOTING •Outlet problems •Valve restrictions •High back pressure •Separator operating pressure

© Schlumberger, 2001

TROUBLESHOOTING •Downhole problems •Hole in tubing

•Operating pressure valve by surface closing Method •Well blowing dry gas

•Well will not take any input gas •Well flowing in heads •Installation stymied and will not unload

•Valve hung open •Valve spacing too wide © Schlumberger, 2001

TROUBLESHOOTING TECHNIQUES • Calculations - analysis of casing pressure • Echometer surveys • Tagging fluid level • Two pen pressure recorder charts

• Multi-rate test analysis • Historical well test analysis • Computer modeling • Flowing pressure and temperature surveys © Schlumberger, 2001

TYPICAL CALCULATED CHECKS • Casing pressure analysis • Effect of reservoir pressure & pi with well test data • Gas passage calculations • Well temperature effect

• Frictional/downhole pressure effects • Performance curve • Well stability

© Schlumberger, 2001

GAS LIFT TROUBLESHOOTING FLOWCHART · · · · ·

Flowing Survey

WELL FLOWS

WELL TAKES GAS CHART 2 WELL DOES NOT TAKE GAS CHART 3 IRREGULAR GAS INJECTION CHART 4

WELL TEST DATA WELL HISTORY TWO PEN CHART WELL EQUIPMENT GAS LIFT DATA SHEET

Continuous Flow Design Diagnostics

WELL DOES NOT FLOW

WELL TAKES GAS CHART 5 WELL DOES NOT TAKE GAS CHART 6

© Schlumberger, 2001

WELL FLOWS WELL TAKES GAS

CHART 2

Injection Not Thru Gas Lift Valve

Injection Thru Gas Lift Valve

Injection At Deepest Valve?

Evaluate for Deeper Injection Point

Hole in Tubing

Sidepocket Mandrel Leak

Install Pack Off

Re-install Valve

Mechanical Problems?

Remove Restriction

Install Pack Off

Re-design for Deeper Injection

Consider Workover Re-evaluate OPTIMISE GAS INJECTION RATE

© Schlumberger, 2001

WELL FLOWS WELL DOES NOT TAKE GAS

CHART 3

Failed Gas Lift Valve

Change Out Valve

Casing Bridge

G.L.V. Setting Too High

G.L.V. Design Temperature Too Low

Surface Gas Input Problem

Pump Chemical

Redesign for Lower Pressure

Redesign for Higher Temperature

Plugged Surface Choke

Frozen Surface Choke

Pump Water

Re-evaluate

OPTIMISE GAS INJECTION RATE © Schlumberger, 2001

WELL FLOWS IRREGULAR GAS INJECTION

CHART 4

SubSurface Problem

Surface Problem

Casing Pressure Low

Casing Pressure High

Unstable Gas Supply

Unstable Back Pressure

Hole in Tubing

Unloading Valve Gained Pressure

Compressor Discharge Unstable

Adjacent Well Heading in Shared Manifold

Unloading Valve Lost Pressure

Operating Valve Too Deep

Intermittent Well Robbing Supply Gas Volume

Unstable Separator Back Pressure

Valve Port Fluid Cut

Valve Port Size Too Small

Leaking Sidepocket Mandrel

Re-evaluate

OPTIMISE GAS INJECTION RATE

© Schlumberger, 2001

WELL DOES NOT FLOW WELL TAKES GAS

CHART 5 Casing Pressure High

Lower Valve Won't Open Fluid Load on Bottom Below Design Pressure Bridge in Casing

Lift Gas Injection Rate Too High

Casing Pressure Low

Gas Lift Valve Problem

Mechanical Problem

Unloading Valve Lost Dome Pressure

Hole in Tubing

Cut Out Valve Port

Leaking Mandrel Pocket

Trash in Unloading Valve Port

Leaking Tubing Hanger

Evaluate for Orifice Insert

No Inflow To Wellbore

Re-evaluate

OPTIMISE GAS INJECTION RATE © Schlumberger, 2001

WELL DOES NOT FLOW WELL DOES NOT TAKE GAS

CHART 6

Subsurface Problem

Surface Problem

Wellhead or Manifold Plugged or Closed

Gas Lift Valve Problem

Injection Choke Plugged or Closed

Subsurface Safety Valve Closed

Tubing Closed

Bridge in Casing

Plugged Operating Valve

Valve Set Pressure Too High

Valve Gained Charged Pressure

Top Valve Spaced Too Deep

Rock The well

Re-design for Lower Pressure

Change Valve

Unload to Lower Back Pressure

Circulate Fluid Thru Valve

Displace Casing with Lighter Fluid

Change Valve

Use Higher Injection Pressure

Re-evaluate

OPTIMISE GAS INJECTION RATE © Schlumberger, 2001

TROUBLE-SHOOTING GAS LIFT WELLS

Case Studies using Echometer, Two-Pen Recorder and Nodal Analysis

© Schlumberger, 2001

CASE #1 • New gas lift string – Expected production: 1350 bbls/d @ 580 MCF/D gas injection. – Actual Production: 1050 bbls/d @ 520 MCF/D gas injection.

• Corrective Action Taken – Well modeled to aid in diagnosis. – Acquired fluid level in casing. – Wireline ran in well with impression block to confirm valve was out of pocket. Attempted to re-set valve. – Flowing gradient survey ordered.

© Schlumberger, 2001

CASE #1 GAS LIFT DESIGN VLV # 1 2 3 4 5 6

MD

TVD

1850 2820 3640 4500 5370 6260

1837 2698 3305 3902 4502 5106

Temp.

TCF

Port

144 0.847 3/16" 150 0.838 3/16" 156 0.829 3/16" 161 0.822 3/16" 1/4" Orifice Valve GLV in place

R

TRO

.094 .094 .094 .094

945 940 935 930 N/A

Figure 1

© Schlumberger, 2001

CASE #1 FLUID LEVEL SHOT End

Mandrel #2 @ 2820 ft. MD (13.6 in.)

Start

Mandrel #3 @ 3305 ft. MD (17.8 in.)

SCSSV @ 398 ft. MD (1.9 in.)

Mandrel #4 @ 4500 ft. MD (21.5 in.)

Mandrel #1 @ 1850 ft. MD (9.1 in.)

Figure 2

© Schlumberger, 2001

Case #1 Pressure vs. Depth Plot

Figure 3

© Schlumberger, 2001

CASE #1 SUMMARY & CONCLUSIONS • As figure 2 shows, the fluid level was found at the 4th mandrel. The well has failed to unload to the orifice. • As figure 3 illustrates, there is sufficient pressure differential at depth to unload to the orifice in mandrel #5. • Wireline operations confirmed the valve in mandrel #4 was out of pocket, preventing the well from unloading. © Schlumberger, 2001

CASE #2 • Well has been severely heading with tubing pressures ranging between 120 350 psi. Casing pressures have varied between 900 - 1000 psi. • Well believed to be multi-point injecting between 2 or more valves.

© Schlumberger, 2001

CASE #2 GAS LIFT DESIGN VLV #

1 2 3 4 5 6 7 8 9 10

MD

TVD

1802 3111 4105 4803 5418 5939 6491 7012 7563 8115

1802 3110 4087 4747 5333 5805 6313 6794 7306 7829

Temp.

TCF

Port

R

105 0.912 3/16" .094 121 0.884 3/16" .094 134 0.863 3/16" .094 1/4" Orifice Valve from #10 149 0.839 3/16" .094 156 0.829 3/16" .094 163 0.819 3/16" .094 170 0.809 3/16" .094 174 0.803 3/16" .094 N/A N/A 3/16" .094

TRO

1005 995 980 N/A 960 945 930 920 910 970

Figure 4

© Schlumberger, 2001

CASE #2 FLUID LEVEL SHOT End

Mandrel #4 @ 4803 ft. MD (23.8 in.)

Mandrel #3 @ 4105 ft. MD (20.4 in.)

Mandrel #2 @ 3111 ft. MD (15.4 in.)

Start

SCSSV @ 614 ft. MD (3.0 in.)

Mandrel #1 @ 1802 ft. MD (8.9 in.)

Figure 5 © Schlumberger, 2001

CASE #2 TWO-PEN RECORDER CHART

Figure 6

© Schlumberger, 2001

CASE #2 FLOWING GRADIENT SURVEY

Figure 7

© Schlumberger, 2001

CASE #2 CASING PRESSURE ANALYSIS VALVE NO

DEPTH TVD

1 2 3 4

1802 3110 4087 4747

TRO

Pd@60F

Pt

1005 911 340 995 901 587 980 888 822 1/4" BKO-3 Orifice Valve

R

1-R

PtR

OP

Tv

TCF

Op Force

Cl Force

.0940 .0940 .0940

.9060 .9060 .9060

32 55 77

971 995 1020

139 147 158

.855 .842 .826

912 957 1001 N/A

1065 1071 1075 N/A

Closed Closed Closed Open

Figure 8

© Schlumberger, 2001

CASE #2 SUMMARY & CONCLUSIONS • As figure 5 illustrates, the well has unloaded to the orifice in mandrel #4. • Figure 6 is a 2-pen chart showing both tubing and casing heading, typical of multi-point injection and/or un-regulated gas passage due to communication. • The flowing survey in figure 7 indicates gas passage through valves # 1,2,3 & 4.

© Schlumberger, 2001

CASE #2 SUMMARY & CONCLUSIONS • The casing pressure analysis in figure 8 shows that all unloading valves should be closed at the given pressures and temperatures. • Well appears to be multi-point injecting through leaking or cut-out valves. • Appears to be error in bottom three survey points. © Schlumberger, 2001

CASE #2 SUMMARY & CONCLUSIONS • Valves were sent to shop and replaced. The seats in each of the unloading valves were confirmed to be cut out • After replacing cut-out valves, well was returned to production. Total fluid rate increased by over 150 bbls/d (60 BOPD). • 4 training sessions were then scheduled for field personnel to better inform them about proper unloading / operating procedures. © Schlumberger, 2001

CASE #3 • Well is believed to be under-performing. • Significant fluctuations in casing pressure observed. • Well was observed to be surging.

© Schlumberger, 2001

CASE #3: Inflow Performance

Figure 1 - Inflow performance. The above IPR curves were generated to represent conditions at present and at the time of the last pressure survey (11/98). Based on the estimated IPR, the current Pwf would have to be approximately 2627 psi to correspond with the current production rate of 5204 bbls/d. © Schlumberger, 2001

CASE #3: Casing Pressure Analysis

Figure 2 - Gas passage. The above curves show that the gas passage of valves 1 & 2 roughly total what is currently being injected. © Schlumberger, 2001

CASE #3: Gradient Plot

Figure 3 - Gradient plot. The above gradient plot shows that the well can not inject deeper than the 2nd mandrel under current conditions. © Schlumberger, 2001

CASE #3: Gas Passage Analysis Gas Passage Curves for Well D-8 1600

Qgi, MSCFD

1400 1200 1000 800

Valve #1 Valve #2

600 400 200 0 0

200

400

600

800

1000

Pdwn, psia Figure 4 - Gas Passage. The above gas passage curves show that the combined gas passage of the top two unloading valves is less than the current gas injection rate. This indicates that the well may be injecting through a hole in the tubing or a valve which is leaking or out of pocket.

© Schlumberger, 2001

CASE #3: System Deliverability

Figure 5 - System deliverability. The above performance curve shows that the well is over-injecting at present. Note: this performance curve assumes single-point injection at the 2nd mandrel and is only an estimate. Because the well is multi-point injecting and / or unstable, the actual performance capability of the well may actually be greater than is shown above. However, the general trend should be similar to that shown above.

© Schlumberger, 2001

CASE #3 SUMMARY & CONCLUSIONS • Casing pressure analysis indicates all valves should be closed. • Gradient analysis indicates only valves #1 & 2 have sufficient differential to inject. • Gas passage analysis indicates that current injection rate exceeds combined capacity of top 2 valves. • Well suspected to be injecting through hole in tubing – this was confirmed by bleeding down casing. • If communication can be repaired, gain of approximately 360 bopd may be achieved.

© Schlumberger, 2001

Example Flowing Gradient Surveys

© Schlumberger, 2001

© Schlumberger, 2001

© Schlumberger, 2001

© Schlumberger, 2001

© Schlumberger, 2001

HEADING / INSTABILITIES / SLUGGING • TUBING HEADING PHENOMENON • CASING HEADING PHENOMENON • INSTABILITY / SLUGGING ON START UP • VALVE PROBLEMS

© Schlumberger, 2001

INJECTION PRESSURE OR PRODUCTION ANNULUS SLUGGING (HEADING) CAN INDICATE • • •

INSUFFICIENT GAS INJECTION RATES INCORRECTLY SIZED CIRCULATING VALVE FOR THE GAS INJECTION RATE THE WELL COULD BE MULTI-POINTING

© Schlumberger, 2001

© Schlumberger, 2001

CONSTANT FLOW GAS LIFT WELL

PRODUCED FLUID

0

INJECTION GAS

PRESSURE (PSI) 1000

2000

0

1000 CASING PRESSURE WHEN WELL IS BEING GAS LIFTED

3000

4000

5000

OPERATING GAS LIFT VALVE

6000

SIBHP

DEPTH (FT TVD)

2000

7000

© Schlumberger, 2001 FBHP

INSTABILITY - The perpetuation of slugging (whilst sub-critical flow across the operating valve)

Fluctuation in Tubing pressure

Decreased fluid density

Decrease TBG pressure

Slight decrease in CSG pressure until drop in gas inj. rate

Increased gas inj. rate

Decreased gas inj. rate

Slight increase in CSG pressure until sufficient to increase gas inj. rate

Increase TBG pressure

Increased fluid density

© Schlumberger, 2001

GAS INJECTION RATE (MMSCF/D)

SUB-CRITICAL FLOW

CRITICAL FLOW

CRITICAL FLOW

PTUBING = 55%

PRESSURE (PSI)

P©CASING Schlumberger, 2001

STABLE & OPTIMUM POINT OF INJECTION

PRODUCTION RATE (Qrate)

UNSTABLE GAS INJ. RATE

THEORETICAL OPTIMUM GAS INJ. RATE

OPTIMUM GAS INJ. RATE WITH SYSTEM CONSTRAINTS

GAS INJECTION RATE (Qg)

© Schlumberger, 2001

STABILITY CHECK Criteria for Gas Lift Stability*

INFLOW Well

Name

A5.xls A6.xls A7.xls B1.xls B2.xls B4.xls C7.xls Total

Casing

Wellhead

Flowing

Total

Gas

Productivity

Injection Port

Pressure (psig)

Pressure (psig)

Pressure psi

Liquid BPD

Lift Mmscf/d

Index

Size in

1800.00 1397.80 0.00 0.00 2070.00 2060.00 1016.45

552.45 390.05 0.00 0.00 379.90 410.35 427.75

4262.00 1761.00 0.00 0.00 3608.50 2747.20 1548.10

26414.19 9987.05 0.00 0.00 21365.00 17834.73 3955.02

3.30 4.40 0.00 0.00 4.70 6.10 3.50

29.00 8.20 0.00 0.00 27.00 27.00 4.60

0.1875 0.375 0.375 0.4375 0.3125 0.4375 0.5

79556

22.00

Stability Criteria*

RESPONSE Predicted Behavior

Well status

3.449808242 1.146643372 #DIV/0! #DIV/0! 2.899782728 2.985449297 0.578114879

Stable Stable #DIV/0! #DIV/0! Stable Stable Unstable

Gas Lift Gas Lift Shut down Shut down Gas Lift Gas Lift Gas Lift

Comments

PLEASE NOTE THAT ABOVE STABILITY CRITERIA WERE CALCULATED BY USING WELL TEST DATA ONLY!

© Schlumberger, 2001

STANDARD APPROACH TO REDUCING INSTABILITY • CHOKE WELL : DAMPENS TUBING SLUGS LOSS OF PRODUCTION

• INCREASE GAS INJECTION RATE : FORCE ORIFICE INTO CRITICAL FLOW NORMALLY INJECTION RATE EXCEEDS ECONOMIC INJECTION RATE ADDITIONAL LOAD ON COMPRESSOR

• REDUCE ORIFICE SIZE INCREASE UPSTREAM PRESSURE FOR SAME INJECTION RATE (ADDITIONAL LOAD ON COMPRESSOR = REDUCE COMPRESSOR THROUGHPUT)

© Schlumberger, 2001

NOVA VALVE

© Schlumberger, 2001

GAS INJECTION RATE (MMSCF/D)

SUB-CRITICAL FLOW

CRITICAL FLOW

CRITICAL FLOW

PTUBING = 55%

PRESSURE (PSI)

PTUBING = 90%

P©CASING Schlumberger, 2001

OPERATING PRINCIPLE OF THE VENTURI 200 180

Flow Rate (MCF/d)

160

CHARACTERISTICS OF A SQUARE-EDGED ORIFICE

140 120

The Square-edged orifice performance curve

100 80 60

•

Large sub-critical flow regime

•

Gas passage dependent on downstream pressure until 40 - 50% pressure lost

•

Poor pressure recovery = large pressure drop & large energy loss

40 20 0

0

100

200

300

400

500

600

Tubing Pressure

© Schlumberger, 2001

OPERATING PRINCIPLE OF THE VENTURI THE VENTURI DESIGN ALLOWS THE FOLLOWING : • • • •

BETTER PRESSURE & ENERGY RECOVERY LOWER DISCHARGE COEFFICIENT DRASTICALLY REDUCED SUB-CRITICAL FLOW REGIME CRITICAL VELOCITY (VELOCITY OF PRESSURE TRANSMISSION/SONIC VELOCITY) ATTAINED WITHIN 10% PRESSURE DROP REDUCES INFLUENCE OF DOWNSTREAM PRESSURE ON GAS PASSAGE = REDUCED RISK TO PROPAGATING INSTABILITY

•

Nozzle-Venturi Gas Lift Valve Project Pressure vs. Flow Rate Summary 4000 1400 psi Upstream

Flow Rate (Mcf/d)

3500 3000

Improved Orifice Valve

2500 2000

Conventional Orifice Valve

900 psi Upstream

1500 1000

400 psi Upstream

500 0 0

200

400

600

800

Downstream Pressure (psi) Data shown is from actual flow tests

1000

1200

1400

© Schlumberger, 2001

COMPUTER – AIDED GL DESIGN AND ANALYSIS KEY LEARNING OBJECTIVES

UPON COMPLETION OF THIS SEGMENT, YOU SHOULD BE ABLE TO:

• Explain the basic principles of nodal analysis. • Use nodal analysis techniques to estimate the optimal injection point and injection rates for a gas lift well. • Use nodal analysis programs to aid in a gas lift design. • Use computer-based analysis tools to aid in trouble-shooting a gas lift well.

© Schlumberger, 2001

COMPUTER GAS LIFT DESIGN WELL MODEL CONSTRUCTION WELL PERFORMANCE ANALYSIS FOR LIFE OF WELL OPTIMISED GAS LIFT DESIGN FOR LIFE OF WELL

© Schlumberger, 2001

COMPUTER PROGRAMS “DON‟T DO GAS LIFT DESIGNS!”

© Schlumberger, 2001

COMPUTER GAS LIFT DESIGN THE EQUILIBRIUM CURVE CONCEPT LENDS ITSELF PARTICULARLY WELL TO MODELING ON THE COMPUTER, WHERE A LARGE NUMBER OF PARAMETERS CAN BE INVESTIGATED RAPIDLY.

© Schlumberger, 2001

COMPUTER PROGRAMS • • • • • •

PETROLEUM EXPERTS EDINBURGH PETROLEUM SERVICES BAKER JARDINE SSI SIMSCI NUMEROUS OTHERS

© Schlumberger, 2001

INFLOW AND OUTFLOW PERFORMANCE Pressure, psig 0 1000 2000 3000

5200

4000 5000

FBHP, psig

Depth, feet

5000 6000 7000

4800 4600

8000

4400

9000

4200

10000

0

1000

2000

3000

Rate, bbls/d

11000 12000 13000 14000 0

1000

2000

3000

4000

5000

© Schlumberger, 2001

© Schlumberger, 2001

© Schlumberger, 2001

© Schlumberger, 2001

© Schlumberger, 2001

COURSE SUMMARY

• Overview of student objectives. • Overview of course objectives. • Q&A

© Schlumberger, 2001