Gas Lift School Material

8/10/2019 Gas Lift School Material

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PROJECT UR BUSINESS BINNING OIL TOOLS S.A

www.refineded.com E:[email protected]

GAS LIFT SCHOOL 2012

PETRO-ENERGY E&P , SUDAN


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Gas Lift


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Gas Lift and Completions

Seminar Gas Lift

What is gas Lift Types and applications

Tools

Design options

Troubleshooting and optimization

Completion

Packer Types

Forces to be considered


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Day 1 Presentation

Introduction to gas lift

Gas Lift compared to other systems

Gas Lift types and applications Standards

Components


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Day 2 Gradients

Reservoir Types

Gas properties

IP and IPR Valve types and mechanics

Basic Design


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Day 3 Gas Lift Design

Continuous

Intermittent

Troubleshooting and Optimization


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Day 4 Completion

Packer Types

Design Considerations

Roundup and sample cases


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Eduardo Tidball Sales manager BINNING OIL TOOLS S.A.

18 years in the industry CAMLOW SAIC

SCHLUMBERGER


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Wells inWells in thethe WorldWorld

Canada48,200

US

FSU115,000

E tChina

North Sea600

Germany 1,000

World: 1,000,000 wells

500,000

Argentina13,500

Indonesia9,500

Venezuela 14,200

Brazil

6,300

Peru

4,500

Nigeria300

1,100

2,300

,

India3,000

Australia 1,100


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ArtificialArtificial LiftLift SystemsSystems


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ESP


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PCP (Progressive Cavity Pump)


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Beam Pump


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Hydraulic Lift


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Gas Lift

What is Gas Lift?


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2006 Artificial2006 Artificial LiftLift SystemsSystems DistributionDistribution

72000

11%

61000

443000

69%

42000

7%

80001%

15000

2%

Beam Pump Gas-LiftPCPs ESP

Hydraulic Pumping Others


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Ft./Lift

12,00011,000

10,000

9,000

8,000

Typical Artificial Lift Application Range

Capacities by AL Method

7,000

6,000

5,000

4,000

3,000

2,000

1,000

1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 20,000 30,000 40,000 50,000 BPD

Rod Pumps PC Pumps Hydraulic Lift Submersible Pump Gas Lift


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A LittleA Little HistoryHistory..

First completions were used for coal mine de-

watering in the 18th century First gas lift production wells: 1846 in the US

In the 1930 there were several gas lift valve

es gns First patented gas lift valve: King Valve in 1944

First patented wire line retrievable valve: 1954.


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GasGas LiftLift AdvantagesAdvantages

Low down hole equipment costs

Low operating costs

mp e comp e on es gns

Flexible: from 3 to more than 50000 bbls/d

Directional wells, sand, scale, etc

Minimum intervention costs


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GasGas LiftLift DisadvantagesDisadvantages

High pressure gas source needed

Imported from other fields

Produced

Startup costs might be high

Modify existing platforms

Compressor stations design

Limited by reservoir pressure (cannot

produce to depletion)


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ComparisonComparison of ALof AL MethodsMethods

Condition Specific BP PCP Jet Pump Hydraulic Lift Gas-Lift ESPWells Single

1 to 20

More than 20

Production 10000bpd

2500 a 7500ft

>7500ft

Casing Size 4

5

7>9 5/8

Well Inclination Vertical

Deviated

Horizontal


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Condition Specific BP PCP Jet Pump Hydraulic Lift Gas-Lift ESPDogleg Sever. >3/100ft

3 to 10/100ft

250F

250 350F


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ComparsionComparsion of ALof AL MethodsMethods

Condition Specific BP PCP Jet Pump Hydraulic Lift Gas-Lift ESPStability Stable

Variable

Production Primary

Secondary

Tertiary

Water Cut Low

Properties of produced fluids

Medium

High

Viscosity >100Cp

100-500Cp


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Condition Specific BP PCP Jet Pump Hydraulic Lift Gas-Lift ESPGOR 2000scf/Stb

Treatments Scale

Corrosion

Solvents

Acids

Location On-Shore

Off Shore

Remota

Intervention Workover

Pulling

Coiled Tubing

Snubbing

Wireline


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GAS LIFT CLOSED SYSTEMGAS LIFT CLOSED SYSTEM


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GAS LIFTGAS LIFTApplicationApplication RangesRanges

CONTINUOUS INTERMITTENT

PRODUCTION>100 BLPD

> 15 m 3/D

< 300 BLPD

< 50 m3/D

PRODUCTIVITYINDEX

> 0,5 BLD/PSI

> 0,1 m 3/D / KG Cm2N/A

GLR. < 1500 scf/bbl< 265 m3/ m3

N/A


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Continuous Flow Control


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CONTINUOUS FLOW WITH ADJUSTABLE CHOKECONTINUOUS FLOW WITH ADJUSTABLE CHOKE

CASING PRESSUREDURING STARTUP


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INTERMITTENT WITH TIME/CYCLE CONTROLLERINTERMITTENT WITH TIME/CYCLE CONTROLLER

CASING PRESSURE


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Intermittent Lift Control


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STANDING VALVE


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INTERMITTENT WITH PILOT VALVEINTERMITTENT WITH PILOT VALVE

CASING PRESSURE


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ChamberChamber CompletionsCompletions


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ISO 9001 2000ISO 9001 2000


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ISO 9001:2000ISO 9001:2000

IT IS A SYSTEM BASED ON QUALITYMANAGMENT ISO 9001:2000.

THE ADVANTANGE OF A QUALITY MANAGMENTSYSTEM IS THAT IT ALLOWS TO KEEP A

THROUGH TRACEABILITY ANDDOCUMENTATION EACH STEP OF THEPROCESS CAN BE IDENTIFIED.

THE STANDARD CAN BE APPLIED TO ANYPRODUCTION PROCESS


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New API Standard

API19G replaces API11V1

API19GAPI19G StandardsStandards


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API19GAPI19G StandardsStandards

STAMPING IS DONE FOLLOWING STANDARDREQUIREMENTS DEPENDING OF GRADE

ONLY TO BE APPLIED ON PRODUCTS UNDERSTANDARD SCOPE

API19G V l G


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API19G Valve Groups

Group I: IPO balanced IPO y IPO with choke

Group II: PPO PPO with choke

Group III: Pilot differential Group IV: Orifice Nozzle venturi shear orifice Dump/Kill

Group V: Dummy

- -

Group VII: Surface controlled-hydraulic Surface controlled-electric Smart

Group VIII: Liquid injection

Group IX: Other

OTHER API STANDARDSOTHER API STANDARDS


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API RP 11V2: Gas Lift valve testing & modelling

API RP 11V5: Gas Lift Operations API RP 11V6: Continuous Flow Gas Lift Design

OTHER API STANDARDSOTHER API STANDARDS

API RP 11V8: Gas Lift Systems

API RP 11V9: Dual gas lift

API RP 11V10: Intermittent gas lift

ISO STANDARDSISO STANDARDS


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ISO 17078 - 1: Side Pocket Mandrels

ISO 17078 2: Gas Lift Flow ControlDevices (valves)

ISO STANDARDSISO STANDARDS

: as- t unn ng,Pulling, and Kick-Over Tools, andLatches

ISO 17078 4: Gas-Lift Guidelines andPractices

WEB INFORMATIONWEB INFORMATION


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WEB INFORMATIONWEB INFORMATION

http://www.alrdc.com

Artificial Lift R&D Council Web Page

Web based discussion boardsfor gas-lift

MandrelsMandrels


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MandrelsMandrels


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Gas Lift Valve Types IPO

5/8 1, 1 1

Bellows Operated

Spring Operated

Top Latch

Bottom Latch

PPO

1, 1

Spring Operated Bellows Operated

Retrievable, Non Retrievable

ValvesValves


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ValvesValves

IPO Bottom

Latch

Pilot Top

Latch

IPO Top

Latch

IPO

Conventional


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Other Valves Chemical injection valves

Orifice Valves Square Edged

entur

Dummy Valves

Dump/Kill Valves

Circulation Valves

Waterflood Regulators


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Chemical Injection Dummy Valve Orifice Valve


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Waterflood Regulators

LatchesLatches


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LatchesLatches

RA KE or BE B o K

Flow ConfigurationFlow Configuration


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Flow ConfigurationFlow ConfigurationInjection pressure OperatedInjection pressure Operated Tubing FlowTubing Flow -- CPO ValveCPO Valve

GAS

Fluid & Gas

CPO Valve

Main Acting Force



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Flow ConfigurationFlow ConfigurationInjection pressure OperatedInjection pressure Operated Casing FlowCasing Flow -- CPO ValveCPO Valve

GAS

Fluid & Gas

CPO Valve withSpecial

Mandrel

Main Acting Force



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Flow ConfigurationFlow ConfigurationProduction pressure OperatedProduction pressure Operated Tubing FlowTubing Flow -- PPO ValvePPO Valve

GAS

Fluid & Gas

PPO Valve

Main Acting Force



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Flow ConfigurationFlow ConfigurationProduction pressure OperatedProduction pressure Operated Casing FlowCasing Flow -- PPO ValvePPO Valve

GAS

Fluid & Gas

PPO Valve withSpecial

Mandrel

Main Acting Force



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Flow ConfigurationFlow ConfigurationInjection pressure OperatedInjection pressure Operated Tubing FlowTubing Flow -- CPO ValveCPO Valve-- LT MandrelLT Mandrel

GAS

Fluid & Gas

Main Acting Force

Side Pocket Mandrelwith Side Pipe and

CPO Valve


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METRIC SYSTEMMETRIC SYSTEM


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METRIC SYSTEMMETRIC SYSTEMEQUIVALENCIES

1 METER = 3,281 FEET

1 CUBIC METER = 6,29 BARREL US= 35.3 CUBIC FEET

=

= 5,61 CUBIC FEET1 IMPERIAL GALLON = 1,2 GALLONS US1 KG/CM2 = 14,22 PSI ( PSIG and PSIA)1 ATMOSPHERE = 14,696 PSI

1 KILO = 2,205 POUNDS

METRIC SYSTEMMETRIC SYSTEM


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GAS/LIQUID RATIO

1 m3 /m3 . = 5.61 Ft3/ Bbl

GRADIENTS

= ,

1 KG/CM2 PER METER = 4.36 PSI PER FOOT

PRODUCTIVITY INDEX

1 BLPD / PSI = 2.261 M3D / KG/CM21 M3D / KG/CM2 = 0,442 BLPD / PSI

Gradients


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GradientsWithout gas-lift Gas Injection

GAS LIFTGAS LIFT


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NOT ADEQUATE TO BE USED IN HIGH GLR WELLSDISADVANTAGESDISADVANTAGES

PRESSURE (psig)

DEPTH

(Feet)

Packer Depth

GAS LIFTGAS LIFT


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NOT ADEQUATE TO BE USED IN HIGH GLR WELLSDISADVANTAGESDISADVANTAGES

PRESSURE (psig)

DEPTH

(Feet)

Packer Depth

GAS LIFTGAS LIFT


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DISADVANTAGESDISADVANTAGES

PRESSURE(psig)

NOT ADEQUATE TO BE USED IN HIGH GLR WELLS

DEPTH

(Feet)

Packer Depth

GAS LIFTGAS LIFT


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DISADVANTAGESDISADVANTAGES

PRESSURE (psig)


Depth(Fe

et)

Packer Depth

GAS LIFTGAS LIFT


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DESVENTAJASDESVENTAJAS

PRESSURE (psig)Whp


DEPTH

(Feet)

Packer Depth


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Vertical Multiphase Gradients


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Empirical Models Gilbert (CA oil wells)-developed 1940 to1950 but published in 1954

Poettmann & Carpenter (no slip) -1952

Baxendell & Thomas (high rate extension of P&C)-1961

Duns & Ros (lab data)-1961 Ros & Gray (improved D&R)-1964

Hagedorn & Brown (most used--slip?)-1964

r szews xxon compos e -

Beggs & Brill (incline flow)--1973 MMSM ( Moreland-Mobil-Shell-Method)-1976

Mechanistic Models Aziz, Grover & Fogarasi-1972

OLGA Norwegian- 1986 Ansari. Et al. 1990

Choksi, Schmidt & Doty-1996

Brill, et al-ongoing*

Shell : Zabaras-1990

CORRELATIONSCORRELATIONS


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GILBERTCURVES

(1954)

CORRELACIONES BROWNCORRELACIONES BROWNGRADIENTES DE PRESION VERTICALGRADIENTES DE PRESION VERTICAL


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o PRODUCTION: 600 BLSD

o TUBING: 2.875 O.D.

o WATER CUT: 50%

o OIL GRAVITY: 0.85

o GAS GRAVITY:0.65

o WATER GRAVITY: 1.074

o TEMPERATURE: 140F

POETTMANPOETTMAN -- CARPENTERCARPENTERVERTICAL GRADIENTSVERTICAL GRADIENTS


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o TUBING SIZE: 2 I.D.

o OIL GRAVITY: 35APIo GAS GRAVITY: 0.65o WATER GRAVITY: 1.074o TEMPERATURE: 190Fo RATE: 500BPD

POETTMANPOETTMAN -- CARPENTERCARPENTERVERTICAL GRADIENTSVERTICAL GRADIENTS


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Exercise


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DissolvedDissolved SolutionSolution Gas DriveGas Drive


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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

GasGas CapCap DriveDrive


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Gas from solution will form gas cap With production gas cap increasesrovidin drive

Excessive drawdown can cause coning PI usually not linear GOR constant except near depletion Circa 25% recovery

WaterWater DriveDrive ReservoirReservoir


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Not constant volume Reservoir pressure more constant - expansion

PI more constant GOR more constant|

Combination of water drive & gas capexpansion

Often supplemented by water injection

Most efficient with upto 50% recovery

DepletionDepletion TypeType DriveDrive


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Small isolated pockets

No pressure support Hi h rates initiall

Very quick depletion May use several artificial lift methods Natural flow initially

Continuous gas lift Intermittent gas lift

ProductivityProductivity IndexIndex


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Q

PI DD

Q= Rate (BPD)

PI=BPD/Psig

DD=Difference between statid

bottomhole pressure and flowing bottomhole pressure dinmica de fondo

Example:

PI: 1.5 bpd/psigPbhs: 900psig

Pbhf: 600psi

PI=Q/(Pbhs-Pbhf)

Q=PI*(Pbhs-Pbhf)

Q=1.5bpd/psi*(900psi-600psi)

Q=1.5*300

Q=450bpd

IPR CurvesIPR Curves


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ProductivityProductivity IndexIndex (IPR(IPR


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Example:

Find maximum potential (Qmax) when Pbhf=500psig

Well Data:

Pbhf: 600psig.

Q1= 400BpdPbhs=900psig

Part 1:

Solution:

Parte1: Determine when Pbhf=0

Step 1: Pbhf=600psig and Q1=400Bpd

Step 2: Pbhf/Pbhs= 600/900=0.67

Paso 3Paso 3


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Step 3

Step 4


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SolucinSolucin


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Step 6: Qmax = Q1/(qo/qmax) = 400/0.49

Qmax = 816 Bpd

Parte 2Parte 2


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Part 2:

Determine potential production whenPbhf=500psig.

Step 7: Pbhf/Pbhs =500psig/900psig = 0.55


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Resultado finalResultado final


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From the graph we can determine thatthe Qo/Qmax is 0.65

Step 10: Q=816(from step 6) * 0.65

Q = 530Bpd

Exercise


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Exercise

With same data as before,determine potential production


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PPO FORCE BALANCEPPO FORCE BALANCE


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PILOT VALVEPILOT VALVE


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STANDARD WIRE LINE TOOLSSTANDARD WIRE LINE TOOLS

KICKOVERSKICKOVERS TO BE USED IN WELLS WITH DEVIATIONS LOWER THAN 30TO BE USED IN WELLS WITH DEVIATIONS LOWER THAN 30


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KICKOVERSKICKOVERS TO BE USED IN WELLS WITH DEVIATIONS LOWER THAN 30TO BE USED IN WELLS WITH DEVIATIONS LOWER THAN 30

L (L (CamcoCamco)).. TWO ARMS. TO BE USED INTWO ARMS. TO BE USED IN 2 3/82 3/8 OROR 22 7/8 TUBING7/8 TUBING

*L2D (*L2D (CamcoCamco)).. TWO ARMS AND A SPRING. MAINLY USED IN 3 TUBING.TWO ARMS AND A SPRING. MAINLY USED IN 3 TUBING.

*R (*R (CamcoCamco)).. THREE ARMS. MODELS FORTHREE ARMS. MODELS FOR 2 3/8,2 3/8,

K (K (CamcoCamco)).. WITH BOW SRPINGS. FOR SLIM HOLEWITH BOW SRPINGS. FOR SLIM HOLE 11 AND AND 22 3/8 TUBING.3/8 TUBING.

WIRE LINE TOOLS USEDWIRE LINE TOOLS USED


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KICKOVERSKICKOVERS FOR DEVIATED WELLSFOR DEVIATED WELLS

OKOK--11 TOTO 77.. USED IN MANDRELS EQUIPPED WITH AN ORIENTINGUSED IN MANDRELS EQUIPPED WITH AN ORIENTING

SLEEVE. (1 VALVES)SLEEVE. (1 VALVES)OMOM--1 TO 51 TO 5. USED IN MANDRELS EQUIPPED WITH AN ORIENTING. USED IN MANDRELS EQUIPPED WITH AN ORIENTINGSLEEVE. 1 VALVESSLEEVE. 1 VALVES


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G Series Mandrels


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G Series Mandrels


PULLING TOOLSPULLING TOOLS


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CAMCOCAMCO,TYPE,TYPE JDJDOTIS / HALLIBURTONOTIS / HALLIBURTON TYPETYPE SS

CAMLOWCAMLOW TYPETYPE EDED

CORE EXTENSION (REACH ISCORE EXTENSION (REACH ISIDENTIFIED BY LAST LETTER)IDENTIFIED BY LAST LETTER)

FOR EXAMPLE:FOR EXAMPLE: A TYPE R LATCH IS PULLED FROM A 1 POCKET USING A 2A TYPE R LATCH IS PULLED FROM A 1 POCKET USING A 2CAMCO JDCAMCO JDCC OR A 2 OTIS S OR A 2 OTIS SBB

NOTE:NOTE: IF A JDS IS USED, THIS SHOWS A SHORT CORE EXTENSION, MEANING AIF A JDS IS USED, THIS SHOWS A SHORT CORE EXTENSION, MEANING A

LONGE REACH AND WILL NOT RETRIEVE THE VALVE. THE JD STANDS FOR JARLONGE REACH AND WILL NOT RETRIEVE THE VALVE. THE JD STANDS FOR JARDOWN TO RELEASE. THIS MEANS THAT IN CASE OF STUCH VALVES, BY SIMPLYDOWN TO RELEASE. THIS MEANS THAT IN CASE OF STUCH VALVES, BY SIMPLYJARRING DOWN A SAFETY PIN IS SHEARED IN THE PULLING TOOL AND IT ISJARRING DOWN A SAFETY PIN IS SHEARED IN THE PULLING TOOL AND IT ISFREED FROM THE VALVE. ATTENTION MUST BE TAKEN TO USE THE ADEQUATEFREED FROM THE VALVE. ATTENTION MUST BE TAKEN TO USE THE ADEQUATETOOLS TO PULL VALVES FROM MANDRELSTOOLS TO PULL VALVES FROM MANDRELS

IN THE CASE OF 1 VALVES WITH TOP LATCHES OR BOTTOM COLLET TYPEIN THE CASE OF 1 VALVES WITH TOP LATCHES OR BOTTOM COLLET TYPELATCHES, THEY ARE ALL RETRIEVED WITH A 1 JD SERIES PULLING TOOL. THELATCHES, THEY ARE ALL RETRIEVED WITH A 1 JD SERIES PULLING TOOL. THEONLY DIFFERENCE IS THE CORE EXTENSION (JDS OR JDC)ONLY DIFFERENCE IS THE CORE EXTENSION (JDS OR JDC)


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GasGas PropertiesProperties

NITROGEN


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NONE TOXIC

NON CORROSIVE NON EXPLOSIVE

READILY AVAILABLE

KNOWN PHYSICAL PROPERTIES

TemperatureTemperature CorrectionCorrection FactorFactorForFor N2N2 ChargedCharged ValvesValves

F Ct F Ct F Ct F Ct F Ct F Ct

61 0.998 101 0.919 141 0.852 181 0.794 221 0.743 261 0.69862 0.996 102 0.917 142 0.850 182 0.792 222 0.742 262 0.697

63 0.994 103 0.915 143 0.849 183 0.791 223 0.740 263 0.696

64 0.991 104 0.914 144 0.847 184 0.790 224 0.739 264 0.695


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64 0.991 104 0.914 144 0.847 184 0.790 224 0.739 264 0.695

65 0.989 105 0.912 145 0.845 185 0.788 225 0.738 265 0.694

66 0.987 106 0.910 146 0.844 186 0.787 226 0.737 266 0.693

67 0.985 107 0.908 147 0.842 187 0.786 227 0.736 267 0.692

68 0.983 108 0.906 148 0.841 188 0.784 228 0.735 268 0.691

69 0.981 109 0.905 149 0.839 189 0.783 229 0.733 269 0.690

70 0.979 110 0.903 150 0.838 190 0.782 230 0.732 270 0.689

71 0.977 111 0.901 151 0.836 191 0.780 231 0.731 271 0.688

72 0.975 112 0.899 152 0.835 192 0.779 232 0.730 272 0.687

73 0.973 113 0.898 153 0.833 193 0.778 233 0.729 273 0.686

74 0.971 114 0.896 154 0.832 194 0.776 234 0.728 274 0.685

75 0.969 115 0.894 155 0.830 195 0.775 235 0.727 275 0.684

76 0.967 116 0.893 156 0.829 196 0.774 236 0.725 276 0.683 Fb

tFb

P

CtPbP

60@

60@

=

77 0.965 117 0.891 157 0.827 197 0.772 237 0.724 277 0.682

78 0.963 118 0.889 158 0.826 198 0.771 238 0.723 278 0.681

79 0.961 119 0.887 159 0.825 199 0.770 239 0.722 279 0.680

80 0.959 120 0.886 160 0.823 200 0.769 240 0.721 280 0.679

81 0.957 121 0.884 161 0.822 201 0.767 241 0.720 281 0.678

82 0.955 122 0.882 162 0.820 202 0.766 242 0.719 282 0.677

83 0.953 123 0.881 163 0.819 203 0.765 243 0.718 283 0.676

84 0.951 124 0.879 164 0.817 204 0.764 244 0.717 284 0.675

85 0.949 125 0.877 165 0.816 205 0.762 245 0.715 285 0.674

86 0.947 126 0.876 166 0.814 206 0.761 246 0.714 286 0.673

87 0.945 127 0.874 167 0.813 207 0.760 247 0.713 287 0.672

88 0.943 128 0.872 168 0.812 208 0.759 248 0.712 288 0.671

89 0.941 129 0.871 169 0.810 209 0.757 249 0.711 289 0.670

90 0.939 130 0.869 170 0.809 210 0.756 250 0.710 290 0.669

91 0.938 131 0.868 171 0.807 211 0.755 251 0.709 291 0.668

92 0.936 132 0.866 172 0.806 212 0.754 252 0.708 292 0.667

93 0.934 133 0.864 173 0.805 213 0.752 253 0.707 293 0.666

94 0.932 134 0.863 174 0.803 214 0.751 254 0.706 294 0.665

95 0.930 135 0.861 175 0.802 215 0.750 255 0.705 295 0.664

96 0.928 136 0.860 176 0.800 216 0.749 256 0.704 296 0.663

97 0.926 137 0.858 177 0.799 217 0.748 257 0.702 297 0.662

98 0.924 138 0.856 178 0.798 218 0.746 258 0.701 298 0.662

99 0.923 139 0.855 179 0.796 219 0.745 259 0.700 299 0.661

100 0.921 140 0.853 180 0.795 220 0.744 260 0.699 300 0.660

FtbPcoe

@

. ==

FormulaFormula toto calculatecalculate TemperatureTemperatureCorrectionCorrection FactorFactor


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Ct = 1/(1+0.00215 * (Temp

VALVE CALIBRATORVALVE CALIBRATOR


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PRESSURE RELIEF ORCHARGE

NO BACK PRESSURE

HIGH PRESSURENITRIGEN

GAS LIFTGAS LIFTRULE OF THUMBRULE OF THUMB

Rule of thumb Equation based on S.G. of 0.65,a geothermal gradient at 1.60F/100ft and a surface


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a geothermal gradient at 1.6 F/100ft and a surfacetemperature of 700F

P@L = P@S + (2.3 x P@S x L )

100 1000

NOTE: THIS IS A QUICK REFERENCE NOT TO BE USED

FOR IN DEPTH CALCULATIONS

= ,P@S = Pressure at surface, psiaL = Depth, feet

GAS PRESSURE AT DEPTH

P@L = P@Se LGS ..


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P@L = P@Se

ZT34.53

Where: e = 2.71828= ,

P@S = Pressure at surface, psia

S.G. = Gas Specific GravityL = Depth, feetT = Average Temp Degrees RZ = Average Compressibility for T

and average pressure

P2 = P1 X Tc

Pressure changes due to temperature in aconfined space (Bellows)


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2 1 X c

Where:P1 = Pressure at initial temperatureP2 = 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 FT2 = Present temperature, Deg F

CLOSED LOOP GAS LIFT SYSTEMCLOSED LOOP GAS LIFT SYSTEMMAKE UP GAS REQUIREMENTSMAKE UP GAS REQUIREMENTS


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o 4% IN SYSTEMS WITH ELECTRIC COMPRESSORS

o4% + 10 TO 12 SCF/HP WITH GAS OPERATEDCOMPRESSORS AS FUEL (NORMALLY RESULTS INABOUT 10% OF THE TOTAL GAS CIRCULATING)


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DESIGN THEORYDESIGN THEORY

TUBING EFFECT THEORYTUBING EFFECT THEORY With valve closed about to open

( ) ( ) ( )

( ) bvbv AA

AA

o tubpenbt

vtubvbgbbt

P1PP

APAAPAP

+=

+=

I b h i h P 0

Ab-Av


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In test bench with Ptub= 0

or(1)

( )b

vA

A= 1PP openbt

b

vA

A

btP

=1

Popen

Ab

Av

And in the well with a certain Pwf:

(2)

Where

b

v

b

v

AA

AA

1 = TEF (TUBING EFFECT FACTOR)

With valve open about to close

(3)( ) ( )

constantmeans,thisPP

APAP

closebelows_t

bclosebbt

=

=

(at temperature T

=b

v

b

v

b

vA

A

AA

tubA

A

bt

P

P

11Popen

CONVENTIONAL VALVE

TRO VALVE CALIBRATIONTRO VALVE CALIBRATION

CALIBRATION PRESSURE FOR VALVES AT 60 F


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To calculate valve setting pressure (calibration) as 60F (TRO), usethe fact that:

ttt PbbellowsPPclose ==

And from there,

Use Temperature v. Depth to determine t1 y t2, etc.

To determine the Pb at 60F, use the correct table for temperaturecorrection coefficient at 60F

CtPbP tFb 60@ =

AbAv

FPbTROvoP

==

1

60@..

PPOPPO TypeType valvevalve calculationcalculation

Pbt Calculation


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Pbt (Ab) = Pp (Ab-Ap) + Pi (Ap)

Where :

Ab = Area of bellowsPp = Production Pressure

Ap: Area of portPi: Injection Pressure at depth


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Day 3

DesignsDesigns

Intermittent Design


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Intermittent Design

Continuous Design Ppo Design


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CorrectCorrect assumptionsassumptions????

We will always have some extra pressure


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We will always have some extra pressure.

Flow line pressure will always be lower than

expected

Temperature is not important

CorrectCorrect assumptionsassumptions!!!!!!

Always assume there will be less pressure than


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Always assume there will be less pressure thaninformed

Back pressure will always be a little higher

necessary amount of mandrels. An extra

mandrel is always cheaper than a workover!!

Temperature is one of the most importantvariables!!!


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ExampleExample

Operating valve: 6000ft. Tubing: 2 Capacity: 0 00579 bbl/ft


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Tubing: 2 Capacity: 0.00579 bbl/ft.

Pt at the moment the valve opens: 500psiat 6000ft. (using dinamic gradient and P.I.)

Pressure above slug: 100psi

Static gradient of fluid: 0,4psi/ft.

MinimumMinimum time pertime per cyclecycle andand maximummaximum

quantityquantity perper dayday

Time to complete 1 cycle (3 min x 1000ft)(3/1000)*(6000) 18 i t


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= (3/1000)*(6000)= 18minutes

Where 1440 is the amount of minutes in aday:

1440/18= 80 cycles per day


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Clculo del tamao deClculo del tamao de SlugSlug

Initial Slug volume = slug height * tubingcapacity =


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p y

500psi-100psi/0,4psi/ft x 0.00579bbl/ft=, cyc e

MaximumMaximum ObtainableObtainable ProductionProduction

Production per cycle= Initial slug volume fall back = 5.8bbls/day 30% = 4,1


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ybbls/day

ax mum a y ro uc on = max mum

amount of cycles per day * volumeproduced per cycle =

4,1 bbls/cycle * 80 cycle/day= 328 BPD

GasGas ConsumptionConsumption perper dayday

Fast Calculation:


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350 SCF/bbl*1000ft

350 * 328 * 6= 574000scf/day

DailyDaily gasgas consumptionconsumption

Detailed calculation:1) Calculate slug height from previous example:

P d d Sl L th P d d Sl V l / it f t bi


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Produced Slug Length = Produced Slug Volume/capacity of tubing =

4,1bbls/0,00579bbl/ft = 701 feet.

2) Theoretical pressure under the slug at the time it reaches thesurface: Pus= Pwh + weight of slug = 100psig + (703ft * 0,4psi/ft) =383psig

Pus= Pressure Under Slug

3) Average pressure in tubing at the moment the slug reaches the

surface = (pressure under the slug+ wellhead pressure)/2 =Pavg = (383psig + 100psig) /2 = 242psig

DailyDaily GasGas ConsumptionConsumption

4) Determine from graph the necessary volume every 1000ft

Qs/1000ft of tubing = 1000 SCFD/1000ft of tubing (considering 242psi


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g g ( g pand 2 tubing)

5) Calculate initial slug height = Initial Slug Volume / tubing capacity

, , . .

6) Calculate the required gas per cycle = (Gas volume every 1000ft xlenght of tubing filled with injected gas) = 1000 cu.ft/1000ft * (6000ft 10002ft) = 4998cu.ft ciclo

7) Total gas need: 4998 cu.ft * 80 cycles/day = 399840 (399MCF)

INTERMITTENT GAS LIFT UNLOADINGINTERMITTENT GAS LIFT UNLOADING


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DEPTH OF FIRST VALVE:

( )G di tFl idKillG

PressureSeparatorPressureKickoff =Depth(A)

VALVE SPACING IN INTERMITTENT WELLSVALVE SPACING IN INTERMITTENT WELLS


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( )GradientFluidKillGs

P

Gs

ept .otaeveutat c =

First valve is set in whichever is deeper (A or B)

Depth of First Valve (upper)

EXAMPLE:



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(A) 1521.740.46

50075Depth =

=

(B)

We use the deepest, in this case, static fluid level = 2739 feet.

13.273946.0

1500

0006LevelFluidStatic == feet


( ) GradienStaticDepthGradientMistDepthPres 211s211 ++=+ eparatorclose PP

Considering force balance to valve 2 (point X)


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( ) pp 211s211 eparatorclose

Mist Gradient = SF (Spacing Factor)

And assuming that 21P (Injection pressure increase between

point 1 and 2) is only necessary to ensure gas flow and that we can

ignore it, the result is:

Gs

P eparatorclose SFDepthPresDepth

1s1

21

=

x

0.14

0.16

si/ft

1.61"ID

Intermittent Gas LiftSpacing Factors


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0.1

0.12

(SF)inps

1.995"ID2.441"ID

0 100 200 300 400 500

0.02

0.04

0.06

0.08

Rate in BPD

S

pacingFa

ctor

2.992"ID

Depth for second valve:

(A) A closing pressure of 100psi less than available injectionpressure in asigned to the first valve.



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p g

(B) If there is not enough injection pressure available:

The first valve closing pressure is

=

b

vclose A

AP 1Pres kickoff

Then,

Gs

PP sep )Depth(SF21betweenDistance

1.close1 =

Where S.F = Spacing Factor, that depends on tubing size and flow rate.Normally between 0.04 and 0.08

Second Valve Depth

EXAMPLE:

( )1065

110600273904.0506502valvuleand1valvulabetweenDistance



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( )

380410652739Depth.2

106546,046,0

2valvuleand1valvulabetweenDistance

=+=

===

For the next valves, keep on using a closing pressure 10 psi less that the

one inmediately before until the bottom of the well is reached .

47569523804Depth.3

95246.0

)3804(04.0506403between2Distance

=+=

=

=

And so on.

CALIBRATION OF TRO VALVES FOR INTERMITTENTCALIBRATION OF TRO VALVES FOR INTERMITTENTLIFTLIFT

CALIBRATION PRESSURE AT 60 F

To calculate the calibration pressure at 60F use the fact that:


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To calculate the calibration pressure at 60 F use the fact that:

ttt PbbellowsPPclose ==

And then,

Use pressure and temperature graph to determine t1 and t2, etc.

To determine Pb at 60use the Ct table:

CtPbP tFb 60@ =

AbAv

FPbTROcalibratorinpressureOpening

==

1

60@.

TYPICAL INJECTION PRESSURE VALVES WITH CHARGED NITROGEN BELLOWS

VALVE Ab PORT (MONEL) Ap/Ab Ap/Ab

OD BELLOWS SIZE SIZE RATIO (1-Ap/Ab)

(IN) (IN^2) (IN) (1/64") Mfg PPEF

------- ------- ------- ------- (MONEL) (MONEL)


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1 1/2" 0,77" 0,1875 12 0,0380 0,0395

0,77" 0,2500 16 0,0670 0,0718

0,77" 0,3125 20 0,1040 0,1161

142

0,77" 0,3750 24 0,1480 0,1737

0,77" 0,4375 28 0,2010 0,2516

0,77" 0,5000 32 0,2620 0,3550

1" 0,31" 0,1250 8 0,0430 0,0449

0,31" 0,1875 12 0,0940 0,1038

0,31" 0,2500 16 0,1640 0,1962

0,31" 0,2813 18 0,2070 0,2610

0,31" 0,3125 20 0,2550 0,3423

0,31" 0,3750 24 0,3650 0,5748

Continuous Flow Unloading

Sequence


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Aplicacin

Gas Lift continuo terminado.exe

ContinuousContinuous UnloadingUnloading

INCRUSTAR FLASH


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ContinuousContinuous UnloadingUnloading


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Gas Lift well startup

Unload well carefully50 - 100 psi (3.5 bar) per 10 min


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p p

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!

DESCARGA DE UN POZO CONTINUODESCARGA DE UN POZO CONTINUO

.

4

5

ssure(P

SIG)

1.995"

2.441"

TUBING PERFORMANCE (OUTFLOW) CURVESFOR10,000 FT WELL W/ 1000 GLR& 50%CUT

Typical Tubing Curves


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4

sands

ingP

re

2.992"

3.467"

0 1 2 3 4 5

1

2

Thousands

Thou

RATE(BFPD)

Pwf

:BHFlowin

gTu

.

Rate in 1000 BFPD

in

1000psi

Tubing vs Flow Rate guide

1.995 ID=200 to 1000 bfpd2 441 ID= 500 to 1500 bfpd


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2.441 ID= 500 to 1500 bfpd2.992 ID=1000 to 3000 bfpd

3.958 ID=> 3000 bfpd

5 ID => 5000 bfpd


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PRESSURE (psig)Flowing Pressure

CONTINUOUS DESIGNCONTINUOUS DESIGN


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(feet)

Depth

Packer Depth

PRESSURE(psig)Well Head Pressure

1

ContinuousContinuous DesignDesign


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(feet)

1

Depth

Packer Depth


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1

Flow Assurance Pressure



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(feet)

1

Depth

Packer Depth

502

PRESSURE (psig)Well Head Pressure

1

Flow Assurance

Pmin 1 Pmax 1



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(feet)

1

Depth

Packer Depth

502


1

Flow Assurance

Pmin 1 Pmax 1



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(feet)

Depth

Packer Depth

502

= TEF (Pmax1 Pmin 1)

*

(*)

3

PRESSURE (psig)

es)

Well Head Pressure

1

Flow Assurance

Pmin 1 Pmax 1



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AD(p

ie

PROF

UNDI

Packer Depth

502

= TEF (Pmax1 Pmin 1)

*

(*)

3

4

Pmin 2 Pmax 2

**

= TEF (Pmax2 Pmin 2(*)

PRESSURE (psig)Whp

ContinuousContinuous DesignDesignUsingUsing PPOPPO ValvesValves

Datum Kickoff Pressure.

25% of (P. Injec. Whp)


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et)

Depth(fe

Profundidad del packer

PRESSURE (psig)Whp

ContinuousContinuous DesignDesignUsingUsing PPOPPO ValvesValves

Datum


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et)

Depth(fe

Packer Depth150 PSIG

PRESSURE (psig)Whp

ContinousContinous DesignDesignUsingUsing PPOPPO ValvesValves

Datum


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et)

Depth(fe

Packer Depth150 PSIG

PRESION (psig)

s)

Whp

DISEO CONTINUODISEO CONTINUODE VLVULAS OPERADAS POR FLUIDO (PPO)DE VLVULAS OPERADAS POR FLUIDO (PPO)

Datum


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D

(pies

PROFUN

DIDA

Profundidad del packer150 PSIG

Opening Pressure Calculation

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


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p p

Where:

Pb: Pressure in Bellows

Pt: Pressure in tubing

Pc: Pressure in casing

PROPORTIONAL RESPONSEPROPORTIONAL RESPONSECalibrationCalibration CurvesCurves


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Q

PRESSURE (psig)P cierre

PROPORTIONAL RESPONSEPROPORTIONAL RESPONSECalibrationCalibration CurvesCurves


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Q

PRESSURE (psig)P closing

THORNHILLTHORNHILL CRAVER TABLECRAVER TABLEGasGas PassagePassage throughthrough OrificesOrifices


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Compania:......................................EJEMPLOYacimiento:....................540 PSI INYECCIONPozo No.:....................................................XX

Fecha:.................................21 - Marzo - 2005Representative:...............................................Locacion:.........................................................

Profundidad de Perforacion (pies):..........7063Profundidad de Packer (pies):.................6812Tuberia OD (pulg ) (selecion): 2-7/8 inch

Indice de Productividad (bbpd/psi):.............05Presion de Separador (psig):....................100Factor de espaciamiento (Entrar 0 par calc ):0

B I N N I N G O I L T O O L S

IntermittentIntermittent DesignDesign


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Tuberia OD (pulg.) (selecion):.........2 7/8 inchDiam. del Casing (pulg.) (selecion):......7" 23#Produccion deseada (blpd):........................60% Agua (100=todo agua):............................3

Factor de espaciamiento (Entrar 0 par calc.):0Temp. Boca de pozo Fluyente (Grado F):...68Pres.de Arranque de Gas Inyect. (psig):...525Pres.de Operacion de gas Inyect. (psig):..525

. ...Temp.de Reservorio (Grado F):................167Presion deReservorio (psig):.....................995Gradiente de Temp. (Grado F/100 pies):...1.6

Nivel de Fluido de pozo Ahogado (pies):.4511Gravedad del Petroleo (Grado API):...........37

= . ......Gradiente del Fluido de Ahogo (psi/pie):.....39Gravedad Especifica del Agua:................1.05Caida Pres.en Superf. entre Vlvs.(psig):.....10

Tipo de Valvula BOT (selecion):.........N10-RCI.D. del Asiento (pulg. - selecion):.............5/16

Calculated Spacing Factor = ,04

Valve # Depth (ft) Depth (M) P bt Temp Ct T.R.O. Sur.Close

7 4512 1375,5 484 131 ,867 563 425

6 4952 1509,7 479 137 ,857 552 4155 5337 1627,2 474 143 ,849 541 4054 5714 1741,9 469 148 ,841 530 3953 6080 1853,7 464 153 ,833 519 3852 6436 1962,3 459 158 ,826 508 3751 6782 2067,7 453 163 ,819 498 365

An estimated gas requirement is: 148323



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TroubleshootingTroubleshooting

IntermittentIntermittent GasGas LiftLift WellWell OptimizationOptimizationGasGas InjectionInjection RequirementsRequirements

Only for Intermittent gas lift wells, the GLR should be between 200 to400 SCF/BBL for every 100 feet of depth. Usually 350 Scf/bbl/1000ft is anacceptable quantity


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In metric: 200m3/m3/1000m.

NOTE: Marginal well (less than 5 BPD) will require a higher GLR toreduce loss of production. In those cases the usual amount is 700 to

1000scf/BBL/1000ft

In metric: 400m3/m3/1000m.

ContinuousContinuous LiftLift OptimizationOptimizationGasGas RequirementsRequirements

Only for continuous gas lift wells, total gas liquid ratio is thatrequired to obtain the minimum gradient (least Flowing Bottom HolePressure). In this case formation GLR is also considered in theequation :


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Total GLR = injected gas + formation gas

us gas n ec on requ remen = o a - orma on gas

Note: to do a fast field analysis of a continuous gas lift well, 2500 to 3000 scf/bbl

per barrel as total GLR (injected + formation) can be used to obtain minimumgradient. (this is a basic calculation and GLR needs is dependant on severalfactorsIn metric system: 450 to 500m3/m3 are used.

EXAMPLE: A well with a production of 700 Bpd of fluid at 8000ft with 400psig wellhead

pressure (due to this assume the well is actually 4000ft deeper to use gradient curves). Weget a minimum gradient of 3000 scf/bbl at 12000ft according to Kermit and Brown. If thereservoir is 450 scf/bbl, we will need to inject : 700*(3000-450= 1.785.000 scf per dayUNote: We talk about RGL and GOR

In metric System

Example: A well producing 100 m3/d at 2000 meters


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with 400psi wellhead pressure (Equivalent to1220meters more depth) . According to Kermit and Brown.

formation GLR is 100m3/m3 the total gas to be

injected is: 100*(500-100)=40.000m3/d.

ReducingReducing GasGas InjectionInjection NeedsNeedsIntermittentIntermittent WellsWells usingusing excessiveexcessive gasgas

Closed SystemsIn this case the objective is to reduce the volume of gas circulating in thesystem, thus reducing pressure in the battery and maintaining injection


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pressure constant.

1) It is important to prolong times between injection cycles almostsimultanously in all wells, thus avoiding that any gas saved in one well

be injected in the others. At this point a pressure increase in the systemshould be noted.

2) At this point compressor input pressure should be reduced untildesired system pressure is reestablished

3) Proceed to increase cycles in desired wells

In closed systems4) Verify that there has been no production loss in none of the wells. Ifso increase cycle frequency in affected wells

5) R d h ibl i h ff i



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5) Reduce separator pressure as much as possible without affectingcompressor operation. As this is an intermittent system is is necessary

o ma n a n enoug gas n e sys em eep ng some eren abetween separator pressure and compressor intake pressure

6) Review all wells remembering the minimum slug travel time tiensure avoiding or reducing interference.

psi)(inPScf.)in(aprox,gasx vol14.65Scf.)(inCapacitySystem

=


In Open Systems


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a) Injection cycles are decreased in one well at a time until aloss in production is detected.

b) Injection cycles are slowly increased until production isreestabilished

NORMAL OPERATION

PRESSURE CHARTSPRESSURE CHARTS


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Insufficient Injection Time



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Intermittent With Pilot Valve.



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Normal Operation Continuous Gas Lift Well



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Intermittent Well using a bottom hole orifice



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POZO INTERMITENTE CON FUGA EN TUBERIA

CARTAS DE PRESIONCARTAS DE PRESION


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POZO INTERMITENTE CON ALTA CONTRAPRESIN

CARTAS DE PRESIONCARTAS DE PRESION


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Q de gas teoricamente optimoUNSTABLE Inyeccin degas inestable

cin


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cc

Caudal de inyeccin

Q de gas optimizado al sistema

Qdeprod

TroublesshootingTroublesshooting

Following data should be monitored regularly:

Injection pressure (Annular or tubing)

Injection Rate

Flowing Pressure


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Well tests (pressure, temperature, etc)

Total production

Watercut

Temperature

Stability: if a system is unstable inmediate action must be carried out.

Please not that gas lift wells are normally unstable during startup andcomissioning


Injection Pressure:

On of the most important variables:

Indicates operating valves

Indicates operating depth

A sudden change in pressure can mean:


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sudde c a ge p essu e ca ea

x es r c on n e n ec on sys em

x Opening of an unloading valve

x Change in tubing pressure at depth (change in WC)x Obstruction in operating valve

x Operating valve has been damaged

x Leak in tubing or injection system

Gas injection Rate:

Has a great influence in fluid production

The inability to inject gas usually indicates a mechanical failure



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If gas injection rate diminishes, this could indicate:

x An increase in watercut

x Operating through an unloading valve

Well tests

Real production and watercut controls

Multi rate tests to better understand well

TroubleshootTroubleshoot


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Multi rate tests to better understand wellbehaviour

x Water Cut: If erratic indicates an unstable

well

Tubing Pressure:The wellhead pressure and temperature are a clear indication that a well is flowing.A Reduction in wellhead pressurecan indicate a loss of production because of:

x A change of injection point

x Increase in watercut

An increase in well head pressure may indicate:



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x Too much gas being injected

x Will affect casing pressure

Tubing instability may be caused by:

x Casing instability (multipointing or too large an orifice)

x A tubing too large

Temperature



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x Choke too large

x Choke too small

x Casing pressure too low

x Casing pressure too high

InjectionInjection ProblemsProblems


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g p gx er y ns rumen s

x No enough gas volumex Too much gas

x Unstable compression system

x Restricciones en las vlvulas

x Contrapresin elevada

Problemas en descargaProblemas en descarga


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p

x Presin de trabajo del separador

x Leak in tubing/valve out of pocket

x Well circulating gas

x Well does not take gas

DownDown holehole problemsproblems


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x Well Slugging

x Valves openx Excessive valve spacing

x Well will not unload


Severe slugging in continuous gas lift well


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Day 4


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y

Completions

Packer Types

Mechanical Set

Retrievable

Permanent


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Tension Set

Compression Set

With Hydrulic hold downs

Packer Types

Hydraulic Set

Retrievable

Semi Permanent


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Without Slips

Factors Affecting CompletionEquipment Selection

Well Environment

Depth

Temperature


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Dog leg severity

Amount of isolation zones Well type (open hole, Cased Hole,

multilateral, etc)

Future operations


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Forces Affecting OurCompletion

Mechanical

Tension

Slack Off uc ng


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uc ng

Balooning Piston Effect

Temperature

Mechanical

Defined by Hooks Law

where:

L=Change in Length

L L h f bi (i h )


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L = Length of tubing (inches)

F = Force (lbs)E = Elasticity coefficient

As= Area of tubing (in2)

Mechanical


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Slack Off


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Piston effect according topacker configuration


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Buckling

Tubing movement caused by pressure


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Where:

Ap = Internal seal bore area of packer

r = Radial tolerance between casing and tubing

Pi: Tubing pressure change at packer depth

Po: Annular pressure change at packer depth

Buckling


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Ballooning

Once again effect caused by pressure


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Where:

= Poisson Coefficient (usually 0,3 for steel)

r = Radial tolerance between casing and tubing

Pi: Tubing pressure change at packer depth

Po: Annular pressure change at packer depth

Ballooning


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Temperature Effect

Caused by changes in temperature inwells operation


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Where:

As = Transversal tubing section area

t =Average temperature change

L = Initial tubing lenghtB = thermal expansion coefficient

Temperature Effect


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Exercises


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Comments?

Thank You!


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Exclusive Representative for

Sudan

REFINED ENGINEERING DIMENSIONS(RED)

P.O BOX 50 KRT-SUDAN

Omer K.Sharfy

(00249)-9-12348700


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(00 9) 9 3 8 00

[email protected]

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