“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
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
NOTE: THIS IS A QUICK REFERENCE NOT TO BE USED FOR IN DEPTH CALCULATIONS
GAS PRESSURE AT DEPTH S .G. × L P@L = P@Se 〈 53.34 × T × Z 〉 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
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)
1º
Packer Depth
Continuous Design Well Head pressure
PRESSURE (psig)
Depth (feet)
1º
Packer Depth
Continuous Design Well Head Pressure
PRESSURE(psig)
Flow Assurance Pressure
Depth (feet)
1º
50
2º
Packer Depth
Continuous Design Well Head Pressure
Depth (feet)
1º
PRESSURE (psig)
Pmin 1
Flow Assurance
Pmax 1
50
2º
Packer Depth
Continuous Design Well Head Pressure
Pmin 1
1º
Depth (feet)
PRESSURE(psig)
Flow Assurance
Pmax 1
2º
50
3º
*
(*)
= TEF (Pmax1 – Pmin 1) Packer Depth
Continuous Design
PROFUNDIDAD (pies)
Well Head Pressure
PRESSURE (psig)
Pmin 1
1º
Pmax 1
Pmin 2
2º
Flow Assurance
3º
Pmax 2
50
*
4º
* *
(*) (*)
= 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.
