Gas Lift School Material

October 8, 2017 | Author: Mohanad Hussien | Category: Barrel (Unit), Petroleum Reservoir, Hydraulic Engineering, Pressure, Chemical Engineering
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Gas Lift School Material...

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        “PROJECT UR BUSINESS” 

                                                                                                                                                                                                                                       

 

 

                                         BINNING OIL TOOLS S.A   

     

GAS LIFT SCHOOL 2012 PETRO-ENERGY E&P , SUDAN

www.refineded.com

   

E:[email protected]

Gas Lift

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

Day 1 • • • • • •

Presentation Introduction to gas lift Gas Lift compared to other systems Gas Lift types and applications Standards Components

Day 2 • • • • • •

Gradients Reservoir Types Gas properties IP and IPR Valve types and mechanics Basic Design

Day 3 • Gas Lift Design – Continuous – Intermittent – PPO

• Troubleshooting and Optimization

Day 4 • Completion – Packer Types – Design Considerations

• Roundup and sample cases

Eduardo Tidball • • • • •

Sales manager BINNING OIL TOOLS S.A. 18 years in the industry CAMLOW SAIC CAMCO DE ARGENTINA SCHLUMBERGER

Wells in the World

Canada 48,200

US 500,0 00

Peru 4,500

North Sea 600 German y 1,000 Egypt Oman 1,100 2,300

Venezuel a 14,200

Nigeria 300

FSU 115,000 China 77,000 India Indonesia 9,500 3,000

Brazil 6,300 Argentin a13,500

World: 1,000,000 wells

Australi a 1,100

Artificial Lift Systems

ESP

PCP (Progressive Cavity Pump)

Beam Pump

Hydraulic Lift

Gas Lift What is Gas Lift?

2006 Artificial Lift Systems Distribution 72000 11% 42000 7%

443000 69%

15000 2%

Beam Pump PCPs Hydraulic Pumping

Gas-Lift ESP Others

61000 10% 8000 1%

Capacities by AL Method Typical Artificial Lift Application Range Ft./Lift 12,000 11,000 10,000 9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1,000 1,000

Rod Pumps

2,000

3,000

4,000

PC Pumps

5,000

6,000

7,000

Hydraulic Lift

8,000

9,000 10,000 20,000 30,000 40,000 50,000 BPD

Submersible Pump

Gas Lift

A Little History…. History….

• First completions were used for coal mine dewatering in the 18th century • First gas lift production wells: 1846 in the US • In the 1930 there were several gas lift valve designs • First patented gas lift valve: King Valve in 1944 • First patented wire line retrievable valve: 1954.

Gas Lift Advantages

• Low down hole equipment costs • Low operating costs • Simple completion designs • Flexible: from 3 to more than 50000 bbls/d • Directional wells, sand, scale, etc • Minimum intervention costs

Gas Lift Disadvantages

• 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)

Comparison of AL Methods Condition Wells

Specific Single 1 to 20 More than 20

Production

10000bpd

Well Depth

7500ft

Casing Size

4 ½” 5 ½” 7” >9 5/8”

Well Inclination

Vertical Deviated Horizontal

BP

PCP

Jet Pump

Hydraulic Lift

Gas-Lift

ESP

Comparison of AL Methods Condition

Specific

Dogleg Sever.

>3º/100ft 3 to 10º/100ft 250ºF 250 – 350ºF 100Cp 100-500Cp 100 BLPD > 15 m 3/D

< 300 BLPD < 50 m3 /D

PRODUCTIVITY INDEX

> 0,5 BLD/PSI > 0,1 m 3/D / KG Cm2

N/A

GLR.

< 1500 scf/bbl < 265 m3/ m3

N/A

Continuous Flow Control

CONTINUOUS FLOW WITH ADJUSTABLE CHOKE

CASING PRESSURE DURING STARTUP

INTERMITTENT WITH TIME/CYCLE CONTROLLER

CASING PRESSURE

Intermittent Lift Control

STANDING VALVE

INTERMITTENT WITH PILOT VALVE

CASING PRESSURE

Chamber Completions

ISO 9001:2000 

IT IS A SYSTEM BASED ON QUALITY MANAGMENT ISO 9001:2000.



THE ADVANTANGE OF A QUALITY MANAGMENT SYSTEM IS THAT IT ALLOWS TO KEEP A REGISTRY OF THE HISTORY OF THE PRODUCT THROUGH TRACEABILITY AND DOCUMENTATION EACH STEP OF THE PROCESS CAN BE IDENTIFIED.



THE STANDARD CAN BE APPLIED TO ANY PRODUCTION PROCESS

New API Standard API19G replaces API11V1

API19G Standards  STAMPING IS DONE FOLLOWING STANDARD REQUIREMENTS DEPENDING OF GRADE  ONLY TO BE APPLIED ON PRODUCTS UNDER STANDARD SCOPE

• 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 VI: chemical injection - chemical injection-spring loaded Group VII: Surface controlled-hydraulic – Surface controlledelectric – Smart – Group VIII: Liquid injection – Group IX: Other

OTHER API STANDARDS

• • • • • • •

API RP 11V2: Gas Lift valve testing & modelling API RP 11V5: Gas Lift Operations API RP 11V6: Continuous Flow Gas Lift Design API RP 11V7: Gas Lift Valve Reconditioning API RP 11V8: Gas Lift Systems API RP 11V9: Dual gas lift API RP 11V10: Intermittent gas lift

ISO STANDARDS

• ISO 17078 - 1: Side Pocket Mandrels • ISO 17078 – 2: Gas Lift Flow Control Devices (valves) • ISO 17078 – 3: Gas-Lift Running, Pulling, and Kick-Over Tools, and Latches • ISO 17078 – 4: Gas-Lift Guidelines and Practices

WEB INFORMATION Artificial Lift R&D Council Web Page

http://www.alrdc.com Web based discussion boards for gas-lift

Mandrels

Gas Lift Valve Types • IPO – 5/8” 1”, 1 ½” 1 ¾” • Bellows Operated • Spring Operated • Top Latch • Bottom Latch • PPO – 1”, 1 ½” • Spring Operated • Bellows Operated

• Retrievable, Non Retrievable

Valves

IPO Bottom Latch

Pilot Top Latch

IPO Top Latch

IPO Conventional

Other Valves • Chemical injection valves • Orifice Valves – Square Edged – Venturi

• • • •

Dummy Valves Dump/Kill Valves Circulation Valves Waterflood Regulators

Chemical Injection

Dummy Valve

Orifice Valve

Waterflood Regulators

Latches

RA

KE or BE

BoK

Flow Configuration Injection pressure Operated – Tubing Flow - CPO Valve

GAS Fluid & Gas Main Acting Force

CPO Valve

Flow Configuration Injection pressure Operated – Casing Flow - CPO Valve

GAS Fluid & Gas Main Acting Force

CPO Valve with Special Mandrel

Flow Configuration Production pressure Operated – Tubing Flow - PPO Valve

GAS Fluid & Gas Main Acting Force

PPO Valve

Flow Configuration Production pressure Operated – Casing Flow - PPO Valve

GAS Fluid & Gas Main Acting Force

PPO Valve with Special Mandrel

Flow Configuration Injection pressure Operated – Tubing Flow - CPO Valve Valve-- LT Mandrel

GAS Fluid & Gas Main Acting Force

Side Pocket Mandrel with Side Pipe and CPO Valve

Day 2

METRIC SYSTEM METRIC SYSTEM EQUIVALENCIES 1 METER = 3,281 FEET 1 CUBIC METER = 6,29 BARREL US = 35.3 CUBIC FEET 1 BARREL US = 42 GALLONS US = 5,61 CUBIC FEET 1 IMPERIAL GALLON = 1,2 GALLONS US 1 KG/CM2 = 14,22 PSI ( PSIG and PSIA) 1 ATMOSPHERE = 14,696 PSI 1 KILO = 2,205 POUNDS

METRIC SYSTEM •GAS/LIQUID RATIO 1 m3 /m3 . = 5.61 Ft3/ Bbl •GRADIENTS 1 PSI PER FOOT = 0,23 KG/CM2 PER FOOT 1 KG/CM2 PER METER = 4.36 PSI PER FOOT •PRODUCTIVITY INDEX 1 BLPD / PSI = 2.261 M3D / KG/CM2 1 M3D / KG/CM2 = 0,442 BLPD / PSI

Gradients Without gas-lift

Gas Injection

GAS LIFT DISADVANTAGES NOT ADEQUATE TO BE USED IN HIGH GLR WELLS PRESSURE (psig)

DEPTH (Feet)



Packer Depth

GAS LIFT DISADVANTAGES NOT ADEQUATE TO BE USED IN HIGH GLR WELLS

DEPTH (Feet)

PRESSURE (psig)

Packer Depth

GAS LIFT DISADVANTAGES NOT ADEQUATE TO BE USED IN HIGH GLR WELLS

PRESSURE(psig)

DEPTH (Feet)



Packer Depth

GAS LIFT DISADVANTAGES NOT ADEQUATE TO BE USED IN HIGH GLR WELLS

PRESSURE (psig)

Depth (Feet)



Packer Depth

GAS LIFT DESVENTAJAS NOT ADEQUATE TO BE USED IN HIGH GLR WELLS

Whp

PRESSURE (psig)

DEPTH (Feet)



Packer Depth

GRADIENTS AND CORRELATIONS

DEPTH ((Feet)

Wellhead Pressure

PRESURE (psig)

GRADIENTS

DEPTH ((Feet)

20

40

PRESSURE (psig)

Vertical Multiphase Gradients • • • • • • • • • •

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 Orkiszewski (Exxon composite)-1967 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

CORRELATIONS

GILBERT CURVES (1954)

CORRELACIONES BROWN GRADIENTES DE PRESION VERTICAL

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:

140°F

POETTMAN - CARPENTER VERTICAL GRADIENTS

o TUBING SIZE: o OIL GRAVITY: o GAS GRAVITY: o WATER GRAVITY: o TEMPERATURE: o RATE: 500BPD

2 ½ ” I.D. 35°API 0.65 1.074 190°F

POETTMAN - CARPENTER VERTICAL GRADIENTS

Exercise

Reservoir Types

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

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

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

Water Drive Reservoir

• • • • • • •

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

Depletion Type 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

Productivity Index Q= Rate (BPD)

Q

PI

PI=BPD/Psig

DD

DD=Difference between statid bottomhole pressure and flowing bottom hole pressure dinàmica de fondo Example: PI: 1.5 bpd/psig Pbhs: 900psig Pbhf: 600psi PI=Q/(Pbhs-Pbhf) Q=PI*(Pbhs-Pbhf) Q=1.5bpd/psi*(900psi-600psi) Q=1.5*300 Q=450bpd

IPR Curves

Productivity Index (IPR Example:

Find maximum potential (Qmax) when Pbhf=500psig Well Data: Pbhf: 600psig. Q1= 400Bpd Pbhs=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 3

Step 3

Step 4

Paso 4

Step 4

0.49

Soluciòn

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

Qmax = 816 Bpd

Parte 2

Part 2: Determine potential production when Pbhf=500psig. Step 7: Pbhf/Pbhs =500psig/900psig = 0.55

Ultimos pasos

Step 8

Step 9 0.65

Resultado final

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

Step 10: Q=816(from step 6) * 0.65 Q = 530Bpd

Exercise With same data as before, determine potential production with a Fbhp: 150psig

CPO FORCE BALANCE

PPO FORCE BALANCE

PILOT VALVE

STANDARD WIRE LINE TOOLS • KICKOVERS TO BE USED IN WELLS WITH DEVIATIONS LOWER THAN 30 30° ° •L (Camco (Camco)). TWO ARMS. TO BE USED IN 2 3/8 OR 2 7/8 TUBING *L2D (Camco (Camco)). TWO ARMS AND A SPRING. MAINLY USED IN 3 ½” TUBING. *R (Camco (Camco)). THREE ARMS. MODELS FOR 2 3/8, 2 7/8 AND 3 ½ TUBING •K (Camco (Camco)). WITH BOW SRPINGS. FOR SLIM HOLE 1 ½ AND 2 3/8 TUBING.

WIRE LINE TOOLS USED

WIRE LINE TOOLS USED

KICKOVERS FOR DEVIATED WELLS •OK OK--1 TO 7. USED IN MANDRELS EQUIPPED WITH AN ORIENTING SLEEVE. (1” VALVES) •OM OM--1 TO 5. 5. USED IN MANDRELS EQUIPPED WITH AN ORIENTING SLEEVE. 1 ½” VALVES

Wireline Tools to be used KICKOVERS FOR DEVIATED WELLS •OPERATING SEQUENCE OF OK AND OM

G Series Mandrels

WIRE LINE TOOLS USED PULLING TOOLS •CAMCO CAMCO,TYPE ,TYPE “JD” •OTIS / HALLIBURTON TYPE “S” •CAMLOW TYPE “ED”

CORE EXTENSION (“REACH” IS IDENTIFIED BY LAST LETTER)

FOR EXAMPLE: A TYPE R LATCH IS PULLED FROM A 1 ½” POCKET USING A 2” CAMCO “JDC “JDC” OR A 2” OTIS “SB “SB” NOTE: IF A JDS IS USED, THIS SHOWS A SHORT CORE EXTENSION, MEANING A LONGE REACH AND WILL NOT RETRIEVE THE VALVE. THE “JD” STANDS FOR JAR DOWN TO RELEASE. THIS MEANS THAT IN CASE OF STUCH VALVES, BY SIMPLY JARRING DOWN A SAFETY PIN IS SHEARED IN THE PULLING TOOL AND IT IS FREED FROM THE VALVE. ATTENTION MUST BE TAKEN TO USE THE ADEQUATE TOOLS TO PULL VALVES FROM MANDRELS IN THE CASE OF 1” VALVES WITH TOP LATCHES OR BOTTOM COLLET TYPE LATCHES, THEY ARE ALL RETRIEVED WITH A 1 ¼” JD SERIES PULLING TOOL. THE ONLY DIFFERENCE IS THE CORE EXTENSION (JDS OR JDC)

Gas Properties

NITROGEN • • • • •

NONE TOXIC NON CORROSIVE NON EXPLOSIVE READILY AVAILABLE KNOWN PHYSICAL PROPERTIES

Temperature Correction Factor For N2 Charged Valves °F 61 62 63 64 65

Ct 0.998 0.996 0.994 0.991 0.989

°F 101 102 103 104 105

Ct 0.919 0.917 0.915 0.914 0.912

°F 141 142 143 144 145

Ct 0.852 0.850 0.849 0.847 0.845

°F 181 182 183 184 185

Ct 0.794 0.792 0.791 0.790 0.788

°F 221 222 223 224 225

Ct 0.743 0.742 0.740 0.739 0.738

°F 261 262 263 264 265

Ct 0.698 0.697 0.696 0.695 0.694

66 67 68 69 70

0.987 0.985 0.983 0.981 0.979

106 107 108 109 110

0.910 0.908 0.906 0.905 0.903

146 147 148 149 150

0.844 0.842 0.841 0.839 0.838

186 187 188 189 190

0.787 0.786 0.784 0.783 0.782

226 227 228 229 230

0.737 0.736 0.735 0.733 0.732

266 267 268 269 270

0.693 0.692 0.691 0.690 0.689

71 72 73 74 75

0.977 0.975 0.973 0.971 0.969

111 112 113 114 115

0.901 0.899 0.898 0.896 0.894

151 152 153 154 155

0.836 0.835 0.833 0.832 0.830

191 192 193 194 195

0.780 0.779 0.778 0.776 0.775

231 232 233 234 235

0.731 0.730 0.729 0.728 0.727

271 272 273 274 275

0.688 0.687 0.686 0.685 0.684

76 77 78 79 80

0.967 0.965 0.963 0.961 0.959

116 117 118 119 120

0.893 0.891 0.889 0.887 0.886

156 157 158 159 160

0.829 0.827 0.826 0.825 0.823

196 197 198 199 200

0.774 0.772 0.771 0.770 0.769

236 237 238 239 240

0.725 0.724 0.723 0.722 0.721

276 277 278 279 280

0.683 0.682 0.681 0.680 0.679

81 82 83 84 85

0.957 0.955 0.953 0.951 0.949

121 122 123 124 125

0.884 0.882 0.881 0.879 0.877

161 162 163 164 165

0.822 0.820 0.819 0.817 0.816

201 202 203 204 205

0.767 0.766 0.765 0.764 0.762

241 242 243 244 245

0.720 0.719 0.718 0.717 0.715

281 282 283 284 285

0.678 0.677 0.676 0.675 0.674

86 87 88 89 90

0.947 0.945 0.943 0.941 0.939

126 127 128 129 130

0.876 0.874 0.872 0.871 0.869

166 167 168 169 170

0.814 0.813 0.812 0.810 0.809

206 207 208 209 210

0.761 0.760 0.759 0.757 0.756

246 247 248 249 250

0.714 0.713 0.712 0.711 0.710

286 287 288 289 290

0.673 0.672 0.671 0.670 0.669

91 92 93 94 95

0.938 0.936 0.934 0.932 0.930

131 132 133 134 135

0.868 0.866 0.864 0.863 0.861

171 172 173 174 175

0.807 0.806 0.805 0.803 0.802

211 212 213 214 215

0.755 0.754 0.752 0.751 0.750

251 252 253 254 255

0.709 0.708 0.707 0.706 0.705

291 292 293 294 295

0.668 0.667 0.666 0.665 0.664

96 97 98 99 100

0.928 0.926 0.924 0.923 0.921

136 137 138 139 140

0.860 0.858 0.856 0.855 0.853

176 177 178 179 180

0.800 0.799 0.798 0.796 0.795

216 217 218 219 220

0.749 0.748 0.746 0.745 0.744

256 257 258 259 260

0.704 0.702 0.701 0.700 0.699

296 297 298 299 300

0.663 0.662 0.662 0.661 0.660

Pb @ 60 º F = Pbt º Ct Ct = coef . =

Pb @ 60 º F Pb @ t º F

Formula to calculate Temperature Correction Factor

Ct = 1/(1+0.00215 * (Temp @ Depth – 60)

VALVE CALIBRATOR

PRESSURE RELIEF OR CHARGE

HIGH PRESSURE NITRIGEN NO BACK PRESSURE

GAS LIFT RULE OF THUMB Rule of thumb” Equation based on S.G. of 0.65, a geothermal gradient at 1.60F/100ft and a surface temperature of 700F

[email protected] = [email protected] + (2.3 x [email protected] x L ) 100 1000 Where:

[email protected] = Pressure at depth, psia [email protected] = Pressure at surface, psia L = Depth, feet

NOTE: THIS IS A QUICK REFERENCE NOT TO BE USED FOR IN DEPTH CALCULATIONS

GAS PRESSURE AT DEPTH S .G. × L [email protected] = [email protected] 〈 53.34 × T × Z 〉 Where:

e = 2.71828 [email protected] = Pressure at depth, psia [email protected] = 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

Pressure changes due to temperature in a confined space (Bellows) P2 = P1

X

Tc

Where: 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

CLOSED LOOP GAS LIFT SYSTEM MAKE UP GAS REQUIREMENTS

o 4% IN SYSTEMS WITH ELECTRIC COMPRESSORS o4% + 10 TO 12 SCF/HP WITH GAS OPERATED COMPRESSORS AS FUEL (NORMALLY RESULTS IN ABOUT 10% OF THE TOTAL GAS CIRCULATING)

DESIGN THEORY

TUBING EFFECT THEORY •

With valve closed – about to open

Pbtº (A b ) = Pg (A b − A v ) + Ptub (A v ) Pbtº = Popen (1 − Av Ab ) + Ptub Av Ab

Ab-Av

In test bench with Ptub= 0

Pbtº = Popen (1 − Av Ab )

or (1)

Popen =

Ab

Pbtº 1 − Av Ab

Av

And in the well with a certain Pwf:

(2) Popen

Where



 Av Ab  Pbtº = − Ptub  A  Av v 1 − Ab  1 − Ab 

 Av Ab     1 − Av A  b  

= TEF (TUBING EFFECT FACTOR)

With valve open about to close

Pbtº (A b ) = Pclose (A b )

(3) Pbelows_tº = Pclose

CONVENTIONAL VALVE this means, constant (at temperature T°

TRO VALVE CALIBRATION  CALIBRATION PRESSURE FOR VALVES AT 60º F To calculate valve setting pressure (calibration) as 60°F (TRO), use the fact that:

Pclose tº = P bellows tº = Pb tº Use Temperature v. Depth to determine t1 y t2, etc. To determine the Pb at 60°F, use the correct table for temperature correction coefficient at 60°F

Pb @ 60 º F = Pbt º Ct And from there,

Pb @ 60º F P. vo. = TRO = 1 − Av Ab

PPO Type valve calculation  Pbt Calculation

Pbt (Ab) = Pp (Ab-Ap) + Pi (Ap) Where : • Ab = Area of bellows •Pp = Production Pressure •Ap: Area of port •Pi: Injection Pressure at depth

Day 3

Designs

• Intermittent Design • Continuous Design • Ppo Design

Design Objectives • • • • • •

Inject as deep as possible Conserve injection pressure Ensure that upper valves remain closed Good gas passage (surface and bottomhole) Flexible design for dinamic conditions Avoid instability

Correct assumptions?? assumptions?? • We will always have some extra pressure. • Flow line pressure will always be lower than expected • Reduce the amount of mandrels to the minimum • Temperature is not important

Correct assumptions!!! assumptions!!! • Always assume there will be less pressure than informed • Back pressure will always be a little higher • Design for future conditions and use the necessary amount of mandrels. An extra mandrel is always cheaper than a workover!! • Temperature is one of the most important variables!!!

Max. Production with intermittent lift

• Important estimations: Fall Back = 5-7% every 1000ft • Time to complete a cycle: 3 minutes every 1000ft.

Example

• Operating valve: 6000ft. • Tubing: 2 ½” Capacity: 0.00579 bbl/ft. • Pt at the moment the valve opens: 500psi at 6000ft. (using dinamic gradient and P.I.) • Pressure above slug: 100psi • Static gradient of fluid: 0,4psi/ft.

Minimum time per cycle and maximum quantity per day

• Time to complete 1 cycle (3 min x 1000ft) = (3/1000)*(6000)= 18minutes • Maximum amount of cycles per day: Where 1440 is the amount of minutes in a day: 1440/18= 80 cycles per day

Estimating loss due to fall back

• Percentage of fall back = 5%/1000. (5%/1000) * (6000) = 30%

Cálculo del tamaño de Slug

• Initial Slug volume = slug height * tubing capacity = 500psi-100psi/0,4psi/ft x 0.00579bbl/ft= 5,8bbl/cycle

Maximum Obtainable Production

• Production per cycle= Initial slug volume – fall back = 5.8bbls/day – 30% = 4,1 bbls/day • Maximum Daily Production = maximum amount of cycles per day * volume produced per cycle = 4,1 bbls/cycle * 80 cycle/day= 328 BPD

Gas Consumption per day

• Fast Calculation: 350 SCF/bbl*1000ft 350 * 328 * 6= 574000scf/day

Daily gas consumption

• Detailed calculation: 1) Calculate slug height from previous example: 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 the surface: 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

Daily Gas Consumption 4) Determine from graph the necessary volume every 1000ft Qs/1000ft of tubing = 1000 SCFD/1000ft of tubing (considering 242psi and 2 ½”tubing) 5) Calculate initial slug height = Initial Slug Volume / tubing capacity = 5,8bbls/0,00579 bbl/ft. = 1002ft. 6) Calculate the required gas per cycle = (Gas volume every 1000ft x lenght 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 UNLOADING

INTERMITTENT GAS LIFT UNLOADING

INTERMITTENT GAS LIFT UNLOADING

VALVE SPACING IN INTERMITTENT WELLS DEPTH OF FIRST VALVE: (A)

(B)

Kickoff Pressure − Separator Pressure Depth = Gs (Kill Fluid Gradient )

Static Fluid Level = Total Depth. −

PStatic Bottomhole Gs

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

VALVE SPACING IN INTERMITTENT WELLS Depth of First Valve (upper) EXAMPLE:

(A)

750 − 50 Depth = = 1521.74 0.46

(B)

Static Fluid Level = 6000 feet −

1500 = 2739.13 0.46

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

VALVE SPACING IN INTERMITTENT WELLS Considering force balance to valve 2 (point X) Pclose1 + ∆P1−2 = Presseparator+ Depth1 (MistGradient) + Depth1−2StaticGradient. Mist Gradient = SF (Spacing Factor)

And assuming that ∆P1−2 (Injection pressure increase between point 1 and 2) is only necessary to ensure gas flow and that we can ignore it, the result is:

Depth 1− 2 =

Pclose1 − Pres separator − Depth1 SF Gs

x

Intermittent Gas Lift Spacing Factors Spacing Factor (SF) in psi/ft

0.16 0.14

1.61"ID

0.12

1.995"ID 2.441"ID

0.1

2.992"ID

0.08 0.06 0.04 0.02 0

100

200

300

Rate in BPD

400

500

VALVE SPACING IN INTERMITTENT WELLS Depth for second valve: (A) A closing pressure of 100psi less than available injection pressure in asigned to the first valve. (B) If there is not enough injection pressure available:

The first valve closing pressure is

A Pclose = Pres kickoff 1 − v  Ab  

Then,

Distance between 1 − 2 =

Pclose1 − Psep. − SF (Depth 1 ) Gs

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

VALVE SPACING IN INTERMITTENT WELLS Second Valve Depth EXAMPLE:

Distancebetween valvula1 and valvule2 =

650 − 50 − 0.04 (2739) 600 − 110 = =1065 0,46 0,46

Depth.2= 2739 + 1065 = 3804

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 . 640 − 50 − 0.04(3804) = 952 0.46 Depth.3 = 3804 + 952 = 4756 Distance between2 − 3 =

And so on…….

CALIBRATION OF TRO VALVES FOR INTERMITTENT LIFT  CALIBRATION PRESSURE AT 60º F To calculate the calibration pressure at 60°F use the fact that:

Pclose tº = P bellows tº = Pb tº Use pressure and temperature graph to determine t1 and t2, etc. To determine Pb at 60°use the Ct table:

Pb @ 60 º F = Pbt º Ct And then,

Opening pressure in calibrator. = TRO =

Pb @ 60º F 1 − Av Ab

TYPICAL INJECTION PRESSURE VALVES WITH CHARGED NITROGEN BELLOWS VALVE OD

Ab

PORT

(MONEL)

Ap/Ab

Ap/Ab

BELLOWS

SIZE

SIZE

RATIO

(1-Ap/Ab)

(IN)

(IN^2)

(IN)

(1/64")

Mfg

PPEF

-------

-------

-------

-------

(MONEL)

(MONEL)

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

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

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

1"

142

Continuous Flow Unloading Sequence

Gas Lift continuo terminado.exe Aplicación

Continuous Unloading INCRUSTAR FLASH

Continuous Unloading

Gas Lift well startup • 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!

Typical Curves TU BINGPERTubing FORMANCE(O UTFLOW) CURVES

Pwf: BH Flowing Tubing Pressure (PSIG) Thousands

DESCARGA DE FOR 10,000UN FTWELLPOZO W/ 1000GLR&CONTINUO 50%CUT . 5 1.995" 2.441"

4

2.992" 3.467"

Pwf 3 in 1000 2 psi

3.958"

1 0

1

2

Rate in

3 Thousands 1000 BFPD RATE(BFPD)

4

5

Tubing vs Flow Rate guide 1.995” ID=200 to 1000 bfpd 2.441” ID= 500 to 1500 bfpd 2.992” ID=1000 to 3000 bfpd 3.958” 3.958” ID=> 3000 bfpd 5” ID => 5000 bfpd

CONTINUOUS DESIGN PRESSURE (psig)

Depth (feet)

Flowing Pressure

Packer Depth

Continuous Design Well Head Pressure

PRESSURE(psig)

Depth (feet)



Packer Depth

Continuous Design Well Head pressure

PRESSURE (psig)

Depth (feet)



Packer Depth

Continuous Design Well Head Pressure

PRESSURE(psig)

Flow Assurance Pressure

Depth (feet)



50



Packer Depth

Continuous Design Well Head Pressure

Depth (feet)



PRESSURE (psig)

Pmin 1

Flow Assurance

Pmax 1

50



Packer Depth

Continuous Design Well Head Pressure

Pmin 1



Depth (feet)

PRESSURE(psig)

Flow Assurance

Pmax 1



50



*

(*)

= TEF (Pmax1 – Pmin 1) Packer Depth

Continuous Design

PROFUNDIDAD (pies)

Well Head Pressure

PRESSURE (psig)

Pmin 1



Pmax 1

Pmin 2



Flow Assurance



Pmax 2

50

*



* *

(*) (*)

= TEF (Pmax1 – Pmin 1) = TEF (Pmax2 – Pmin 2 Packer Depth

Continuous Design Using PPO Valves Whp

Datum

PRESSURE (psig)

Depth (feet feet)

25% of (P. Injec. – Whp)

Profundidad del packer

Kickoff Pressure.

Continuous Design Using PPO Valves Datum

PRESSURE (psig)

Depth (feet feet)

Whp

Packer Depth

150 PSIG

Continous Design Using PPO Valves Datum

PRESSURE (psig)

Depth (feet feet)

Whp

Packer Depth

150 PSIG

DISEÑO CONTINUO DE VÁLVULAS OPERADAS POR FLUIDO (PPO) Datum

PRESION (psig)

PROFUNDIDAD (pies)

Whp

Profundidad del packer

150 PSIG

Opening Pressure Calculation Pb= Pt (Ap) + Pc(Ab - Ap) Where: Pb: Pressure in Bellows Pt: Pressure in tubing Pc: Pressure in casing

PROPORTIONAL RESPONSE Calibration Curves

Q

P cierre

PRESSURE (psig)

PROPORTIONAL RESPONSE Calibration Curves

Q

P closing

PRESSURE (psig)

THORNHILL – CRAVER TABLE Gas Passage through Orifices

Intermittent Design BINNING OIL TOOLS Compania:......................................EJEMPLO Yacimiento:....................540 PSI INYECCION Pozo No.:....................................................XX

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

Profundidad de Perforacion (pies):..........7063 Profundidad de Packer (pies):.................6812 Tuberia OD (pulg.) (selecion):.........2-7/8 inch Diam. del Casing (pulg.) (selecion):......7" 23# Produccion deseada (blpd):........................60 % Agua (100=todo agua):............................3 Razon Gas/Liq. de Formation (scf/bbl):...2244 Temp.de Reservorio (Grado F):................167 Presion deReservorio (psig):.....................995 Gradiente de Temp. (Grado F/100 pies):...1.6 Nivel de Fluido de pozo Ahogado (pies):.4511 Gravedad del Petroleo (Grado API):...........37

Indice de Productividad (bbpd/psi):.............05 Presion de Separador (psig):....................100 Factor de espaciamiento (Entrar 0 par calc.):0 Temp. Boca de pozo Fluyente (Grado F):...68 Pres.de Arranque de Gas Inyect. (psig):...525 Pres.de Operacion de gas Inyect. (psig):..525 Gravedad de Gas Inyectado (aire=1.0):......65 Gradiente del Fluido de Ahogo (psi/pie):.....39 Gravedad Especifica del Agua:................1.05 Caida Pres.en Superf. entre Vlvs.(psig):.....10 Tipo de Valvula BOT (selecion):.........N10-RC I.D. del Asiento (pulg. - selecion):.............5/16

Calculated Spacing Factor = ,04 Valve # 7 6 5 4 3 2 1

Depth (ft) Depth (M) 4512 4952 5337 5714 6080 6436 6782

1375,5 1509,7 1627,2 1741,9 1853,7 1962,3 2067,7

P bt

Temp

Ct

T.R.O.

Sur.Close

484 479 474 469 464 459 453

131 137 143 148 153 158 163

,867 ,857 ,849 ,841 ,833 ,826 ,819

563 552 541 530 519 508 498

425 415 405 395 385 375 365

An estimated gas requirement is: 148323

Continuous Design

Continuous Design

Troubleshooting

Intermittent Gas Lift Well Optimization Gas Injection Requirements

Only for Intermittent gas lift wells, the GLR should be between 200 to 400 SCF/BBL for every 100 feet of depth. Usually 350 Scf/bbl/1000ft is an acceptable quantity In metric: 200m3/m3/1000m. NOTE: Marginal well (less than 5 BPD) will require a higher GLR to reduce loss of production. In those cases the usual amount is 700 to 1000scf/BBL/1000ft In metric: 400m3/m3/1000m.

Continuous Lift Optimization Gas Requirements Only for continuous gas lift wells, total gas liquid ratio is that required to obtain the minimum gradient (least Flowing Bottom Hole Pressure). In this case formation GLR is also considered in the equation :  Total GLR = injected gas + formation gas Thus gas injection requirement = total GLR-formation 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 minimum gradient. (this is a basic calculation and GLR needs is dependant on several factors In 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). We get a minimum gradient of 3000 scf/bbl at 12000ft according to Kermit and Brown. If the reservoir is 450 scf/bbl, we will need to inject : 700*(3000-450= 1.785.000 scf per dayU Note: We talk about RGL and GOR

In metric System • Example: A well producing 100 m3/d at 2000 meters with 400psi wellhead pressure (Equivalent to1220 meters more depth) . According to Kermit and Brown our minimum gradient is achieved with 500m3/m3. If formation GLR is 100m3/m3 the total gas to be injected is: 100*(500-100)=40.000m3/d.

Reducing Gas Injection Needs Intermittent Wells using excessive gas

Closed Systems In this case the objective is to reduce the volume of gas circulating in the system, thus reducing pressure in the battery and maintaining injection pressure constant. 1) It is important to prolong times between injection cycles almost simultanously 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 system should be noted. 2) At this point compressor input pressure should be reduced until desired system pressure is reestablished 3) Proceed to increase cycles in desired wells

Reducing Gas Injection Needs Intermittent Wells using excessive gas In closed systems 4) Verify that there has been no production loss in none of the wells. If so increase cycle frequency in affected wells 5) Reduce separator pressure as much as possible without affecting compressor operation. As this is an intermittent system is is necessary to maintain enough gas in the system keeping some differential between separator pressure and compressor intake pressure

System Capacity (in Scf.) =

14.65 x vol gas (aprox, in Scf.) ∆P (in psi)

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

Reducing Gas Injection Needs Intermittent Wells using excessive gas

In Open Systems

a) Injection cycles are decreased in one well at a time until a loss in production is detected. b) Injection cycles are slowly increased until production is reestabilished

PRESSURE CHARTS NORMAL OPERATION

PRESSURE CHARTS Leak in downhole valve

PRESSURE CHARTS Moto valve seat leaking

PRESSURE CHARTS Insufficient Injection Time

PRESSURE CHARTS Intermittent With Pilot Valve.

PRESSURE CHARTS Normal Operation Continuous Gas Lift Well

PRESSURE CHARTS Intermittent Well using a bottom hole orifice

CARTAS DE PRESION POZO INTERMITENTE CON FUGA EN TUBERIA

CARTAS DE PRESION POZO INTERMITENTE CON ALTA CONTRAPRESIÓN

Troubleshooting

$$

Q de producción

UNSTABLE Inyección degas inestable

Q de gas teoricamente optimo

Q de gas optimizado al sistema

Caudal de inyección

Troublesshooting Following data should be monitored regularly:

Injection pressure (Annular or tubing) Injection Rate Flowing Pressure 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 and comissioning

Troubleshooting Injection Pressure: On of the most important variables:  Indicates operating valves  Indicates operating depth A sudden change in pressure can mean: x Restriction in the injection system 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

Troubleshooting

Gas injection Rate: Has a great influence in fluid production The inability to inject gas usually indicates a mechanical failure

If gas injection rate diminishes, this could indicate: x An increase in watercut x Operating through an unloading valve

Troubleshoot

Well tests Real production and watercut controls Multi rate tests to better understand well behaviour x Water Cut: If erratic indicates an unstable well

Troubleshooting 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 x

A change of injection point Increase in watercut

An increase in well head pressure may indicate: x x

Too much gas being injected Will affect casing pressure

Tubing instability may be caused by: x x

Casing instability (multipointing or too large an orifice) A tubing too large

Troubleshooting

Temperature

Injection Problems

x x x x x x x x

Choke too large Choke too small Casing pressure too low Casing pressure too high Verify instruments No enough gas volume Too much gas Unstable compression system

Problemas en descarga

x Restricciones en las vàlvulas x Contrapresiòn elevada x Presiòn de trabajo del separador

Down hole problems

x x x x x x x

Leak in tubing/valve out of pocket Well circulating gas Well does not take gas Well Slugging Valves open Excessive valve spacing Well will not unload

Troubleshooting Severe slugging in continuous gas lift well

Day 4 Completions

Packer Types • Mechanical Set – Retrievable – Permanent – Semi Permanent • Tension Set • Compression Set • With Hydrulic hold downs

Packer Types • Hydraulic Set – Retrievable – Semi Permanent – With slips – Without Slips

Factors Affecting Completion Equipment Selection • • • • • •

Well Environment Depth Temperature Dog leg severity Amount of isolation zones Well type (open hole, Cased Hole, multilateral, etc) • Future operations

Force Considerations • When we are designing a completion ALWAYS think ahead. Will stimulations be carried out for ex (pressures may be a lot higher than during production).

Forces Affecting Our Completion • Mechanical – Tension – Slack Off

• • • •

Buckling Balooning Piston Effect Temperature

Mechanical Defined by Hooks Law where: L=Change in Length L = Length of tubing (inches) F = Force (lbs) E = Elasticity coefficient As= Area of tubing (in2)

Mechanical

Slack Off • Defined by a combination of Hooke and slack-off laws: Where: L=Change in Length L = Length of tubing (inches) F = Force (lbs) E = Elasticity coefficient As= Area of tubing (in2) r = Radial tolerance between casing and tubing I = momentum of inertia (in4) W = weight of tubing in fluid (lbs)

Slack Off

Piston Effect • Mainly influenced by pressure changes and differentials as related to packer seal areas

Where: Ap: internal seal bore of packer Ai: tubing internal area Ao: tubing external area Pi: change in tubing pressure at packer depth Po: change in annular pressure at packer depth

Piston effect according to packer configuration

Buckling • Tubing movement caused by pressure

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

Ballooning • Once again effect caused by pressure

Where: µ = 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

Temperature Effect • Caused by changes in temperature in wells operation

Where: As = Transversal tubing section area t =Average temperature change L = Initial tubing lenght B = thermal expansion coefficient

Temperature Effect

Overall effect • The sum of these different effects all add up what work in different directions some times. • It is important to consider all these variables at the time we design a completion not only in actual conditions but plan for potential future conditions

Exercises

New Developments

Comments? • Thank You!

Exclusive Representative for Sudan • REFINED ENGINEERING DIMENSIONS(RED) – – – –

P.O BOX 50 KRT-SUDAN Omer K.Sharfy (00249)-9-12348700 [email protected]

BINNING OIL TOOLS S.A.

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