Deliquification Solutions Overview November, 2008
T. Scott Campbell Global Business Development Manager Deliquification Solutions
Artificial Lift Systems: Only company offering all forms of artificial lift worldwide
Electric Submersible Pumping (ESP)
Plunger Lift
Reciprocating Rod lift
Gas Lift
Foam Lift (Capillary)
Hydraulic Lift
Our “Toolbox” – The Best in The Industry © 2006 Weatherford. All rights reserved.
Progressing Cavity Pumping (PCP)
The Unloading Thought Process Versus Cost
HYD Lift
Do Not Forget About Area Reduction or Compression!!!!!
$ $
MOST “Lifted” GAS WELLS
RRP Lift
$
are either..
PCP Lift
PLUNGER LIFTED FOAM LIFTED OR ROD PUMPED
ESP Lift
$ $ Gas Lift $ FOAM Lift $
Plunger Lift
The Unloading ExpertsTM © 2006 Weatherford. All rights reserved.
Generally, Cost of LIFTING GAS WELLS INCREASES
Gas Well DeliquificationWhat is Liquid Loading?
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Common Signs of Liquid Loading • Tubing and Casing Pressure Differential (Packerless Completion) • Pressure Spikes • Liquid Slugging • Fluctuating Gas Production • Variance From Predicted Production Decline Curve • Liquid Production Stops All Together
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History of a Gas Well Surface Condition
Stable Flow
Unstable Flow
Stable Flow
Initial Production
RATE
Well Dead
Decreasing Gas Rate with Decreasing Reservoir Pressure
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TIME
Liquid Loading Example • Erratic Flow Pattern
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Gas Well Liquid Loading…. How Can We Predict When it Will Occur?
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Liquid Loading: Coleman Equation Lower pressures P < 1,000 psi Vc = 1.593
σ1/4(ρLiquid-ρGas)1/4 ρGas1/2
Standard Assumptions that “Simplify” Turner Equation: Water Droplet Gravity
• • • • • •
60 dynes/cm surface tension for water 20 dynes/cm surface tension for condensate 67 lbm/ft3 water density 45 lbm/ft3 condensate density 0.6 gas gravity 120 of gas temperature
“Simplified” Turner Equation: (ρLiquid-0.0031p)1/4
Gas Flow
Vc = C
(0.0031p)1/2
C = 5.321, water C= 4.043, condensate, p>=1,000 psi. © 2006 Weatherford. All rights reserved.
Critical Velocity to Critical Flow Rate
“Critical Flow Rate” can be calculated once we have “Critical Velocity”
Q(MMCFPD) = P Vc A T Z
3.06PVcA Tz
Flowing Tubing Pressure Critical Velocity X-Area Tubular Flow Path Flowing Temp oR Z Factor
Critical Flow Rate Equation
Critical Flow rate is the flowing gas rate (volume) necessary to maintain Critical Velocity © 2006 Weatherford. All rights reserved.
The Turner Equation Helps Us Predict Liquid Loading
Critical Velocity for API Tubing (OD/ID) 1600
1400
Flow Rate (MSCFD)
1200
1000
800
600
400
200
0 0
100
200
300
400
500
600
700
Pressure (Psi) © 2006 Weatherford. All rights reserved.
1.90/1.61
2 1/16"/1.75
2 3/8"/1.995
2 7/8"/2.441
3.5"/2.867
800
900
1000
Adding Foamer • Reduces surface tension and density of the produced water. • Reduces the required gas velocity needed to lift water. • Most common means of treating with soap: – Soap Sticks – short term impact- good test – Batch Treatments – short term impact- good test – Continuous Backside Injection • Needs Packerless completion • Only effective to the end of the production tubing – Capillary Injection – Continuous Pin Point Injection © 2006 Weatherford. All rights reserved.
Foam Assisted Critical Flow Rates – +/- 2/3 Reduction
Foamer Reduces Critical Velocity By: • Altering the Properties of the Produced Water • Reducing Surface Tension • Reducing Density
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CAPILLARY STRINGS & FOAMERS
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14
Capillary Injection System Overview Gas Well Applications
Chemical Foamer Delivery System Foamer Reduces Water Surface Tension/Density 50% to 66% Reduction in Critical Velocity Surface Control Rate of Injection Combination Chemical Options – Foamer/Inhibitors
Gas Well Challenges Oil / Water Cuts Soap Injection Volume Capillary Injection String Plugging Metallurgy Selection Only Effective to Point of Injection
Our Heritage: Built for Purpose/Built from Scratch
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Capillary Injection Job Sequence Photos
+/- 2.5 hrs elapsed time for Complete Installation at 10,000 feet Injection Depth
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Capillary Tubing Data Most Common Metallurgy • 2205 • 825 • 625 Average Injection Volumes ¼”- 80 gallons per day* 3/8”- 150 gallons per day* *Depth/Pressure Dependent
Dimensions and Strengths - Capillary Coiled Tubing
Property
Duplex 2205 Tubing 0.250" X 0.035" 0.250 0.035 80.6
0.375" X 0.049" 0.375 0.049 171.0
Capacity (gal/1,000 FT)
1.3225
3.1300
Tensile Strength (Mpsi) Yield Strength (Mpsi) Working Pressure (psi) Burst Pressure (psi)
120-125 90-100 8,400 25,000
120-125 90-100 8,400 25,000
23,500
23,500
OD (inches) WT (inches) Weight (lbs/FT) Per 1000’
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Collapse Pressure (psi)
Weatherford “Smart Soap” System Supply Gas to Controller
• Flow Rate Controlled Soap Injection • Reduced Soap Injection Volumes
Flow Rate Above Critical Velocity Pump Stays OFF
3.Differential Transducer
Capillary Injection String
Flow Rate Below Critical Velocity Pump Turns ON
A Valve Supply Gas Lines
1. NO Valve
• Can Be Used With: • Capillary Injection • Continuous Backside Injection
4.Orifice Union Assembly B Valve Supply Gas Lines High Volume Supply
• CEO III or IV Controller Multiple Uses
2. NC Valve SUPPLY GAS
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Plunger Lift Systems
Plunger Lift System Overview Solar Panel Controller
Lubricator Catcher
Gas Well Applications Usually Your First Choice Lowest Cost Solution
Uses Well’s Own Energy to Lift Liquids Specifically Designed for Dewatering Gas Wells Ideal for Isolated Areas Dual “T” Pad Plunger
Gas Well Challenges Velocities – High or Low Gas Liquid Ratios – Must Have Gas…. Optimization / Maintenance Only Effective to the End of Tubing Impacted by Tubing Placement
Bumper Spring
Our Heritage: McMurry Oil Tools
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CVR System Critical Velocity Reduction Combination of Area Reduction, Capillary Injection Foamer and Plunger Lift to Reduce Required Critical Velocity
21 © 2006 Weatherford. All rights reserved.
Example Completion: 2 3/8” Production Tubing 4 ½” Casing 11.6# Casing 200 PSI Line Pressure Extended Perforation Interval
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Critical Flow Rates 4,000
3,500
1.00-in. OD/0.826-in. ID CT 1.00"/0.826" 1.25-in. OD/1.076-in. ID CT 1.25"/1.076" 3,000
1.50-in. OD/1.310-in. ID CT 1.50"/1.310"
F lo w R ate (m cf/d )
2.00-in. OD/1.780-in. ID CT 2.0"/1.78" 1.90-in. OD/1.610-in. ID API Tubing 1.90/1.61
2,500
1/16-in. OD/1.750-in. ID API Tubing 221/16"/1.75 3/8-in. OD/1.995-in. ID API Tubing 223/8"/1.995
2,000
7/8-in. OD/2.441-in. ID API Tubing 227/8"/2.441 3.50-in. OD/2.867-in. ID API Tubing 3.5"/2.867 1,500
4.5-in., Casing 4.5 11.6 11.6-lb/ft lb/ft 5.5-in., 20-lb/ft Casing 5.5 20 lb/ft 7-in., 7.0" 2626-lb/ft lb./ft Casing
1,000
4.5-in. Casing 7/8-in./ Tubing 4.5" Casing w / w/2 2 3/8" Tubing 5.5-in. Casing 7/8-in./ Tubing 5.5" Casing w / w/2 2 7/8" Tubing 500
7.0-in. Casing 1/2-in./ Tubing 7.0" Casing w / w/3 3 1/2" Tubing
0 0
100
200
300
400
500
600
Wellhead Pressure (psi)
700
800
900
1,000
Typical Completion • Production String: 2-3/8”, 4.7 lb/ft
200 psi A
B
2 3/8” tubing
• Casing: 4-1/2”, 11.6 lb.ft
– 4.000-in. ID
4 ½” casing
– 3.875-in. drift – Flow area: 12.5683 in.2 Critical flow requirements assuming 200-psi WHBP(FTP): CFR for 2-3/8” = 406 mcf/d CFR for 4-1/2” = 1.63 MMcf/d
Extended perforation interval
4 ½” Casing, 2 7/8” Dead String
200 psi 2 3/8” tubing
• Production String: 2 3/8” • Dead String: 2 7/8” ULTRA FLUSH – NO couplings = 2 7/8” = 2.875” OD
• Casing: 4-1/2”, 11.6 lb/ft – Flow area: 12.5683 in.2 • Annular flow area, 2-7/8” inside 4-1/2”
4 ½”., 11.6-lb/ft casing
2 3/8” X-LOC nipple 2 3/8” perforated sub 36- ¾” holes
2 3/8” X-nipple w/ retrievable plug
Shear-out safety jt. 2 3/8” X 2 7/8” crossover
– Flow area: 6.0768 in.2 Critical flow requirements assuming 200-psi WHBP: CFR for 2-3/8” = 406 mcf/d CFR for 4-1/2” x 2 7/8” annulus = 790 mcf/d (was 1.63 MMcf/d with open 4 ½” casing)
2 7/8” tubing “dead string”
4 ½” Casing, 2 7/8” Tubing Casing Size O.D.= 4 ½” I.D. = 4.00”
Tubing Size O.D.= 2 7/8” I.D. = 2.441”
Annulus Area, in2 6.0768
Creating the Dead String Effect
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4 ½” Casing, 2 7/8” Dead String with Capillary String for Foamer Injection
• Casing: 4 ½”, 11.6-lb/ft casing
200 psi 2 3/8” tubing
¼” capillary injection string
– Flow area: 12.5683 in.2 • Annular Flow Area: 2-7/8” inside 4-1/2” – Flow area: 6.0768
2 3/8” perforated sub 36- ¾” holes
in.2
2 3/8” X-nipple w/ retrievable plug
Critical flow requirements assuming 200-psi WHBP: injection valve and mandrel
2 3/8” = 168 mcf/d with foam
Shear-out sub
(was 406 mcf/d without foam) 2 3/8” X 2 7/8” crossover
4 ½” x 2 7/8” annulus = 327 mcf/d with foam 2 7/8” dead string
(was 790 mcf/d without foam) (was 1.63 MMcf/d without Dead String)
Patented System
4 ½” casing
New Wellbore Configuration 2 7/8-in. “Dead String” below 2 3/8-in. Tubing With Foamer and Scale Inhibitor Injection
Patented System
“Dead String” © 2006 Weatherford. All rights reserved.
THREE ARTIFICIAL LIFT SYSTEMS WORKING TOGETHER:
– Area Reduction (Dead String) – Surface Tension and Density Reduction (Foamer) – Plunger Lift (Mechanical Interface)
Patented System
Perforation Interval
Internal fishing neck
Top sub w/ WX 1.875” profile
Heavy-Wall Flow Sub with Isolation Sleeve WX-LOK dogs Seal ring packing Kobe knockout equalization plug
Pressure equalization knockout plug
Isolation Sleeve OD = 1.75” ID = 0.98”
Heavy-Duty Flow Sub 2 3/8” tubing, 36 ¾” holes OD = 3.063” ID = 1.995”
Seal ring packing
1.875” polished bore
Over 5 times the flow area of 2 3/8” tubing
FWHP = 200 PSI Flow Pattern
Flow Area 2
(ft )
Flow Area
CV with Water,
CV with Foam,
CFR with Water
CFR with Foam
(in.2 )
(ft /sec)
(ft /sec)
(mcf/d)
(mcf/d)
2 3/8-in., 4.7-lb/ft tubing
0.02171
3.1262
406.70
168.4
2 7/8-in., 6.5-lb/ft tubing
0.03250
4.6800
608.80
252.1
3 1/2-in., 9.20-lb/ft tubing
0.04883
7.0315
914.70
378.8
4 1/2-in., 11.6-lb/ft casing
0.08728
12.5683
1,634.90
676.9
5 1/2-in., 17-lb/ft casing
0.13054
18.7978
2,445.40
1,012.5
15.70
6.50
2 3/8-in.tubing and 4 1/2-in. casing
0.05650
8.1360
1,058.50
438.3
2 3/8-in. tubing and 5 1/2-in. casing
0.09978
14.3683
1,869.00
773.9
2 7/8-in. tubing and 4 1/2-in. casing
0.04220
6.0768
790.30
327.2
2 7/8-in. tubing and 5 1/2-in. casing
0.08550
12.3120
1,600.80
662.8
3 1/2-in. tubing and 5 1/2-in. casing
0.06372
9.1757
1,193.70
494.2
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Installation Pictures and Production Data
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Installation Photos 1. Installation Technician 2. Capillary Spooling Unit 3. Sheave in Derrick
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1
2
3
Installation Photos 1. CVR Assembly in Elevators 2. ¼” Capillary String @ Valve 3. Stainless Bands
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1
2
3
Installation Photos 1. BOP and Hydril 2. Ultra Flush Box and Pin 3. Ultra Flush Connection 4. Extended Neck Tubing Hanger 5. Adapter Flange
4
1
2
3
5
Splicing the Externally Banded Capillary String
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Example Well A
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Example Well B
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Example Well C
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Example Well D: Redefine the Decline Curve!
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Potential CVR Candidates • Candidate wells are identified by: – Reviewing decline curve – Identifying the liquid loading point with existing flow areas and tubing placement – Identify produced fluids oil/water cut and ability to be foam lifted • If flow area, surface tension and density reduction are not enough: – XtraLift- Extended Perforation Interval Gas Lift
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Xtra-Lift Extended Perforation Gas Lift
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Optional ¼” Cap String Externally Banded
iCVR Drawing
iCVR Advantages over CVR
Capillary Injection String
Wet connect piece
• No Top Kill Required - Entire Assembly Can Be Snubbed In • No Wellhead Modifications Needed • No Stainless or Other Clamps Required • Cap String Can Be Pulled If Plugged
• Loose the Ability to Run Plunger Lift without Pulling Cap String Injection valve
Patented System © 2006 Weatherford. All rights reserved.
Deliquification Final Thoughts….. • Daily positive production from your well, does not mean that the well is “FLOWING”……. – The Real Question is…..Are they UNLOADED? – Field Automation is a major technical advance. But you can miss the REST OF THE STORY…… – Daily Automation Gas Rate = 200mcf/d….Is that all it can make?
• Gas wells do not get stronger over time………... • Proactive Solutions • Use the Tools You Have Been Given • Soap Sticks Work….. …….ONLY When YOU Work!!! • Please call Weatherford for Assistance © 2006 Weatherford. All rights reserved.
Local Tulsa Contacts for Weatherford • Dan Eshom – 918-605-6416 • David Hottel – 918-592-0210
• Scott Campbell – Houston – 281-260-1953
Thank You For Attending Today….
Questions? © 2006 Weatherford. All rights reserved.