HARBISON-FISCHER PLUNGER LIFT - Shale Tec, LLC · HARBISON-FSCHER Prior % of ALARM A B C Group Well...
Transcript of HARBISON-FISCHER PLUNGER LIFT - Shale Tec, LLC · HARBISON-FSCHER Prior % of ALARM A B C Group Well...
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DEVELOPING UNCONVENTIONAL GAS
TECHNICAL WORKSHOP
MARCH 29 , 2010
HOW TO MAKE MORE
PRODUCTION
WITH PLUNGER LIFT
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PLUNGER LIFT BENEFITS WITH TELEMETRY
HOW TO OPTIMIZE PRODUCTION
TROUBLESHOOT AND IMPROVE
CONTENTS
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PLUNGER LIFT SYSTEM
PLUNGERS
MOTOR
VALVE
CONTROLLERBluetooth on Site
Cell Phone Modem
Licensed or SS Radio
Satellite
LUBRICATOR
FLOW METER
(EFM or MVT)
ARRIVAL
SENSORBH SPRING
SOLAR
PANEL
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Increase Production
Can work on high water producing wells (200 bbls/d)
Lifting cost is significantly less than gas lift
Retards decline curve
Typical payback is 2 weeks to 60 days
Decrease unplanned downtime
Decrease drive time and vehicle costs
Decrease OT and contract labor
Decrease equipment failures
BENEFITS WITH TELEMETRY
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Decrease lost gas due to venting
Detection of some EFM calibration issues
Environmentally responsible
Improve site safety
BENEFITS WITH TELEMETRY
Ref:
American Gas Stars Partner Program (Oct 2003)
American Oil and Gas Reporter (Oct 2005)
HF Opti-MISER Case Studies (2009-2010)
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WELL MCF/D BBLS/D LINE
PRESSURE
LIFT
PRESSURE
Well # 1 550 204 135 500
Well # 2 550 94 180 500
Well # 3 300 61 140 720
Well # 4 550 56 60 540
Well # 5 480 54 70 400
Well # 6 600 50 180 500
Well # 7 200 35 320 540
Well # 8 477 30 140 300
Well # 9 460 27 130 300
BENEFITS WITH TELEMETRY
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BENEFITS WITH TELEMETRY
0
200
400
600
800
1000
1200
16-J
an-0
9
16-F
eb-0
9
16-M
ar-0
9
16-A
pr-0
9
16-M
ay-0
9
16-J
un-0
9
16-J
ul-0
9
16-A
ug-0
9
16-S
ep-0
9
16-O
ct-0
9
16-N
ov-0
9
16-D
ec-0
9
16-J
an-1
0
0
50
100
150
200
250
PRODUCTION LEVELED
and STABILIZED !
Free Flowing Well
Production
Line Pressure
HF OPTI-MISER installed
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BENEFITS WITH TELEMETRY
0
200
400
600
800
1000
1200
1400
1600
1800
19-A
pr-0
9
3-M
ay-0
9
17-M
ay-0
9
31-M
ay-0
9
14-J
un-0
9
28-J
un-0
9
12-J
ul-0
9
26-J
ul-0
9
9-A
ug-0
9
23-A
ug-0
9
6-S
ep-0
9
20-S
ep-0
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4-O
ct-0
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18-O
ct-0
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1-N
ov-0
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15-N
ov-0
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29-N
ov-0
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13-D
ec-0
9
27-D
ec-0
9
0
50
100
150
200
250
PRODUCTION LEVELED
and STABILIZED !
Free Flowing Well
Production
Line Pressure
HF OPTI-MISER installed
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HOW TO OPTIMIZE PRODUCTION
TUBING
5000 ft
1. PREVENT or QUICKLY DETECT
UNPLANNED DOWNTIME
2. ELIMINATE FLOW RESTRICTIONS
3. USE RELIABLE HARDWARE
4. USE TELEMETRY WITH CRY-OUT
5. OPERATE AT LOWEST POSSIBLE
FBHP (Cycle Frequently!)
6. OPTIMIZE PRODUCTION,
OBSERVE PLUNGER VELOCITY
1. Fluid in Tubing (CP-TP)
2. Lift Pressure (CP-LP)
CAUSE
1. Plunger Velocity
2. Production
EFFECT
REAL TIME E-MAIL ALERT
Station Name: Well # 42
Alarm Text: Low Sales PressTime Logged: March 19, 2010, 11:19PM
Value: 23.0
Set Point: 25.0
CASING
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HOW TO OPTIMIZE PRODUCTION
Well # 27
Well # 29
Well # 28
Well # 26
Well # 25
Well # 24
Well # 23
Well # 20
Well # 22
Well # 21
Well # 19
Well # 18
Well # 17
Well # 16
Well # 15
Well # 12
Well # 14
Well # 13
Well # 11
Well # 10
Well # 9
Well # 8
Well # 7
Well # 6
Well # 5
Well # 4
Well # 3
Well # 2
Well # 1
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HOW TO OPTIMIZE PRODUCTION
FOCUS ON PRODUCTION !
LOOK AT TRENDS
LINE PRESSURE
GAS PRODUCTION
~ E-Mail Alert ~
Low Line Pressure
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HOW TO OPTIMIZE PRODUCTION
CP TP
LP
Flow
Rate
Lift Pressure
Liquid Load
Well
Closes
Well Opens
Head Gas Produced
Plunger Arrives
Lateral leg unloading
Don’t shut-in too early
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1. Open on Lift Pressure
2. Be at Open Lift Pressure when plunger hits bottom
3. Use a rapid fall plunger if pressure builds fast
4. Allow only small amount of liquid to enter the
tubing so that # 2 can be achieved
5. Flow long enough to unload lateral line
6. Adjust settings, review production
7. Implement preventative maintenance program
Plunger velocities of 200 – 300 fpm are not uncommon
If needed, use a standing valve
HOW TO OPTIMIZE PRODUCTION
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HOW TO OPTIMIZE PRODUCTION
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TROUBLESHOOT AND IMPROVE
0
200
400
600
800
1000
1200
1-O
ct-0
9
8-O
ct-0
9
15-O
ct-0
9
22-O
ct-0
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29-O
ct-0
9
5-N
ov-0
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12-N
ov-0
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19-N
ov-0
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ov-0
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3-D
ec-0
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ec-0
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17-D
ec-0
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24-D
ec-0
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31-D
ec-0
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7-Ja
n-10
14-J
an-1
0
0
50
100
150
200
250
Production
Line Pressure
HF OPTI-MISER installed
17%
AVG 196 Mcf OPEN on
PRESSURE
OPEN on TIME
AVG 167 Mcf
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TROUBLESHOOT AND IMPROVE
Production
Line Pressure
29%
AVG 172 Mcf
OPEN on
PRESSUREOPEN on TIME
AVG 133 Mcf
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TROUBLESHOOT AND IMPROVE
Production
Line Pressure
39%
By Pass Plunger replaced Dual
Row Pad. Cycles more frequently.
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TROUBLESHOOT AND IMPROVE
Motor Valve Leaks. TP
declines when well is closed
Motor Valve Leaks or EFM
calibration issue. Flow
when well is closed.
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TROUBLESHOOT AND IMPROVE
TP is pushing fluid out.
Possible candidate for a
standing valve.
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TROUBLESHOOT AND IMPROVE
Well is closing when
flow rate is increasing.
Flow longer.
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TROUBLESHOOT AND IMPROVE
LP declines when well
is closed. Unplanned
venting to tank.
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TROUBLESHOOT AND IMPROVE
Added Standing Valve.
Shorter Fall Time.
Increased afterflow.
103%
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TROUBLESHOOT AND IMPROVE
Added Standing Valve
20%
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A SYSTEM THAT
ALLOWS
OPERATORS
TO INCREASE PROFITS
HF OPTI-MISER WELL CONTROL SYSTEM
HARBISON-FSCHER
Prior % of ALARM A B C
Group Well # Date Time AOF 24 hr AOF mcf % of Act CSG TBG SALES STATUS Prod Tank Chem
A Billy Bob # 2 14-May-06 10:32 AM 100 65 65% 75 115% 250 230 45 OPEN CLOSE CLOSE
A Billy Bob # 3 14-May-06 11:15 AM 59 47 80% 65 138% 125 110 35 OPEN CLOSE CLOSE
A Sally Sue # 1 14-May-06 2:00 PM 45 32 71% 28 88% 175 185 40 CLOSE CLOSE CLOSE
A Hank's Praire # 5 1-Apr-06 8:00 AM 15 12 80% 8 67% 225 205 45 CLOSE CLOSE CLOSE
A Treasure Trove # 1 14-May-06 9:35 PM 53 47 89% 30 64% 90 95 110 OPEN CLOSE CLOSE
A Bluebonnet 5 14-May-06 12:52 AM 75 32 43% 25 78% 193 187 25 OPEN CLOSE CLOSE
B Exxon 88-Z3456 14-May-06 10:32 AM 100 65 65% 75 115% 250 230 45 OPEN CLOSE CLOSE
B Macky's 2E4 14-May-06 11:15 AM 59 47 80% 65 138% 125 110 35 OPEN CLOSE CLOSE
B Smith BR549 14-May-06 2:00 PM 45 32 71% 28 88% 175 185 95 CLOSE CLOSE CLOSE
B Henry's Gander 1-Apr-06 8:00 AM 15 12 80% 8 67% 225 205 45 CLOSE CLOSE CLOSE
B Rainbow 6 14-May-06 9:35 PM 53 47 89% 30 64% 90 95 35 OPEN CLOSE CLOSE
B Willow Root 4 14-May-06 12:52 AM 75 32 43% 25 78% 193 187 25 OPEN CLOSE CLOSE
C GPS 40:56:75 14-May-06 10:32 AM 100 65 65% 75 115% 250 230 45 OPEN CLOSE CLOSE
C Conoco 87-692 14-May-06 11:15 AM 59 47 80% 65 138% 125 110 35 OPEN CLOSE CLOSE
C Conoco 87-719 14-May-06 2:00 PM 45 32 71% 28 88% 175 185 40 CLOSE CLOSE CLOSE
C Charlie's Back 40 1-Apr-06 8:00 AM 15 12 80% 8 67% 225 205 45 CLOSE CLOSE CLOSE
C Treasure Trove # 1 14-May-06 9:35 PM 53 47 89% 30 64% 90 95 110 OPEN CLOSE CLOSE
C Bluebonnet 5 14-May-06 12:52 AM 75 32 43% 25 78% 193 187 25 OPEN CLOSE CLOSE
D Sedona 1 14-May-06 10:32 AM 100 65 65% 75 115% 250 230 45 OPEN CLOSE CLOSE
D Casper 06-1492 14-May-06 11:15 AM 59 47 80% 65 138% 125 110 35 OPEN CLOSE CLOSE
D Michigan by 4 14-May-06 2:00 PM 45 32 71% 28 88% 175 185 40 CLOSE CLOSE CLOSE
D Full House, Ace's Hi 1-Apr-06 8:00 AM 15 12 80% 8 67% 225 205 45 CLOSE CLOSE CLOSE
D BP 05-B1476 14-May-06 9:35 PM 53 47 89% 30 64% 90 95 110 OPEN CLOSE CLOSE
D BP 06-A1348 14-May-06 12:52 AM 75 32 43% 25 78% 193 187 25 OPEN CLOSE CLOSE
1) AOF = Absolute Open flow
2) Group's could be Engineer's Name or Other Designation.
3) Allow sorting by any column
4) Provide a variety of column headings from which customer can choose to show, and choose the order.
NOTES:
POLLED
PRESSURES
COLEMAN
LAST VALVE STATUS
(psi)
FLOW RATE (mcfd)
DATA ACTIONABLE
INFORMATION
Phone
BookAvailable
Tee Times
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W E L L R E Q U I R E M E N T S F O R P L U N G E R L I F T
F L U I D V O L U M E V S F L U I D H E I G H T I N T U B I N G
F L U I D V O L U M E V S T U B I N G D I AM E T E R
C AS I N G P R E S S U R E R E Q U I R E D ( F O S S AN D G AU L )
ADENDUM
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WELL REQUIREMENTS FOR PLUNGER LIFT
IS FLUID IN THE
TUBING?(Over 90% of US Gas Wells)
FLUID SLUGS ON GAS CHARTS
DECLINE CURVE ANALYSIS
CRITICAL FLOW RATE
IS GAS VOLUME
SUFFICIENT ?
YES
IS GAS PRESSURE
SUFFICIENT ?
YES
300 SCF / BBL / 1,000 FT OF LIFT
LIFT PRESSURE at Least
DOUBLE FLUID LOAD
LIFT PRESSURE = (CP- LP)
FLUID LOAD = (CP – TP)
(Shortly after Shut-In)
LOAD
FACTOR
PACKER
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Fluid Volume in Tubing (Barrels) FV = 0.002242 X (CP-TP) X (ID
2)/SG
CP=Casing Pressure; TP=Tubing Pressure
ID=Tubing Inner Diameter (inches)
SG = Specific Gravity = 1.0 for Water
Fluid Height in Tubing (Feet) FH = (CP-TP) / (0.433 psi/ft X SG)
0.433 psi/ft = Pressure gradient of water
SG = Specific Gravity = 1.0 for Water
If 20% of the fluid column is liquid, then divide the above results by 20% to get the actual height of the fluid column
FLUID VOLUME VS FLUID HEIGHT
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FLUID VOLUME VS TUBING SIZE
1.90”, 3.73 lb/ft Tubing (1.500” ID)
FV = 0.002242 X (CP-TP) X (ID2)/SG
FV = 0.002242 X (216.5 psi) X 1.502
FV = 1.09 Bbls
2 3/8”, 4.70 lb/ft Tubing (1.995” ID)
FV = 0.002242 X (CP-TP) X (ID2)/SG
FV = 0.002242 X (216.5 psi) X 1.9952
FV = 1.93 Bbls
2 7/8”, 6.50 lb/ft Tubing (2.441” ID)
FV = 0.002242 X (CP-TP) X (ID2)/SG
FV = 0.002242 X (216.5 psi) X 2.4412
FV = 2.89 Bbls
BACKPRESSURE
FH = (CP-TP) / (0.433 PSI/FT X SG)
500 FEET = (CP-TP) / (0.433 PSI/FT)
(CP-TP)= 216.5 PSI
FLUID VOLUME
vs TUBING SIZE
500 feet
Casing
Tubing
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FLUID VOLUME VS TUBING SIZE
• Foss and Gaul (CP Required to Lift Plunger)
– CPreq’d = CPmin X {(Aann + Atbg) / Aann}
– CPmin = {SLP + Pp + PcFV} X {1 + D/K}
• CP = Casing Pressure; SLP = Sales Line Pressure
• Aann = Area Annulus; Atbg = Area Tubing
• Pp = Pressure required to lift just the plunger
• Pc = Pressure Required to lift 1 bbl of fluid and overcome
friction
• FV = Fluid Volume above the Plunger
• K = Constant accounting for gas friction below the plunger
• D = Depth of the PlungerK Pc
33,500 165
45,000 102
57,600 673
2 7/8
2 3/8
Tubing