Well Deliquification

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?

© 2006 Weatherford. All rights reserved.

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


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


TIME

Liquid Loading Example • Erratic Flow Pattern


Gas Well Liquid Loading…. How Can We Predict When it Will Occur?


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


CAPILLARY STRINGS & FOAMERS


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


Capillary Injection Job Sequence Photos

+/- 2.5 hrs elapsed time for Complete Installation at 10,000 feet Injection Depth


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’


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


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


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


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


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


0.03250

4.6800

608.80

252.1


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


0.04220

6.0768

790.30

327.2


0.08550

12.3120

1,600.80

662.8


0.06372

9.1757

1,193.70

494.2


Installation Pictures and Production Data


Installation Photos 1. Installation Technician 2. Capillary Spooling Unit 3. Sheave in Derrick


1

2

3

Installation Photos 1. CVR Assembly in Elevators 2. ¼” Capillary String @ Valve 3. Stainless Bands


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


Example Well A


Example Well B


Example Well C


Example Well D: Redefine the Decline Curve!


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


Xtra-Lift Extended Perforation Gas Lift


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.

Well Deliquification

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