liquid loading and deliquification

Low Pressure Gas Well

Deliverability Issues: Common

Loading Causes, Diagnostics

and Effective Deliquification

Practices

George E. King

Brownfields: Optimizing Mature Assets Conference,

September 19-20, 2005, Denver, Colorado.

www.GEKEngineering.com 1

May Add Energy to System

What’s New?

Technology - Cost, price?

What Technology Will Drive Deliquification?

Life Cycle of a Gas Well


US Mature Well Base (2001)

• 880,000 producing or temporarily

abandoned wells

• 320,000 gas wells (many at 5 to 15 mcf/d)

• Vast majority of these wells are low

pressure and low rate.


Gas Wells: Two Facts

• Potential: Very long life in some cases –

30 to over 70 years and large recovery for

every extra 10 psi drawdown.

• Challenge: Liquid loading from condensed

or connate fluids will kill or sharply reduce

the production.


Example: Oklahoma Gas Wells

Oklahoma Gas Production Per Well

0

50

100

150

200

250

1992 1994 1996 1998 2000Gas P

rod

ucti

on

Per

Well

mcf/

d

32,672 producing gas wells in 2001

Average Flow Per Well


Tubing Performance - Vertical P P

gas and

liquid

gas

Gas Well Oil Well

oil, water

and gas

oil

gas, oil

and water Water vapor

condenses as

gas rises and

expands.

Water must be

removed to

allow the well to

flow.

Water that

builds up holds

a backpressure

on the

formation.

DT


Turner Unloading Rate, Water

0

500

1000

1500

2000

2500

3000

0 100 200 300 400 500

Flowing Pressure, psi

Ga

s R

ate

(m

sc

f/d

)

4.5" (3.958" ID)

3.5" (2.992" ID)

2.875" (2.441" ID)

2.375" (1.995" ID)

2.0675" (1.751" ID)

Source – J. Lea, Texas Tech, Turner Correlations.

For pressures > 1000 psi


Minimum Critical Velocities

• Turner and Coleman Equations

• Estimate minimum gas flow velocity

needed to lift water droplets out of well.

• If flow velocity below critical, then water

droplets fall / build up in bottom of well.

• The well may or may not cease to flow

but production will be decreased.


Small Gas Well Example – Lift

Progression – 2-3/8” Tubing

Flow and Lift - 2-3/8" Tubing

0

200

400

600

800

1000

1200

1400

1600

1800

2000

0 20 40 60 80 100

Percent of Well Life

Ga

s F

low

Ra

te, M

SC

FD

Flow to here

then plunger

then ?

Source -

Bryan

Dotson


Pump Power (assumes 50% Efficiency and 200 psid friction drop)

0

1

2

3

4

5

6

7

8

9

1 5 10 25 50 100 150 200

BPD of Water

Pu

mp

HP

1000' depth

5000' depth

10000' depth

Low Pow er is 1-10 HP.

Micro Pow er is less than

2 HP.

We’ll have to put energy into

the well:


How Much Can We Pay?

1050

100200

$15,000

$70,000

$140,000

$280,000

$0

$50,000

$100,000

$150,000

$200,000

$250,000

$300,000

Incremental MSCFD

If plungers get us to 50 MSCFD, we can’t afford

too much..


System Requirements

• Low initial cost.

• Reasonable life: 3-5 years; more is better.

• Low cost energy.

• Handle gas gracefully.

• Automatic pump-off control.

• 180F to 280F, to 12000 feet.

• Handle solids and paraffin well.

• Resistant to CO2 and H2S corrosion.

• Works in highly deviated wells.

• Acid-resistant.

• Resistant to scale formation.


Monobore

High

Packer

Liner and

& Gap

Long

Monobore

& Tail Pipe

Small Tail

Pipe

Tapered

String and

Restrictions

V1

V2

V1

V2

V3

V1

V2

V3

V1

V2

V3

V4

V5

V6

V1+

The design

of the well

bore can

alter the

velocity.

Where is

critical rate

calculated?

Multiple

velocity

calculations

are needed

with gas in

compressed

state.


surface 14.7 psi (1 bar)

5000 ft 2150 psi (146 bar)

(1524m)

10000 ft 4300 psi (292 bar)

(3049m)

292 cm3

2 cm3

1 cm3

52887040.ppt

Gas Bubble Growth With Rise In A Water Column

Gas column is different – gas is low density at the top of a

column and higher density at bottom – so although rate is

constant, velocity is not. www.GEKEngineering.com 14

Liquids in Gas Wells

• Gas phase – condensing to a liquid

– Water – several bbls/mmcf, unusually fresh

– Condensate – can be much higher volume

• Connate Water

– Usually saltier than condensing water

– Often stays in bottom of the well.


Where is Critical Rate Calculated?

Surface or Bottom Hole? Pres: 400#

Temp: 60 deg F

Tbg: 1 ¼” CT

Rate: 200 mscfd

10,000’ 1 ¼” CT

Pres: 900#

Temp: 200 deg F

Wellhead

Critical Rate: 180 mscfd

Bottom of Tubing


Casing


Pres: 1100#

Temp: 200 deg F

10,500’ 3 ½” Csg to Perfs


Water Content of Wet Gas

0.01

0.10

1.00

10.00

100.00

1000.00

10000.00

50 100 150 200 250 300 350

Temperature (deg F)

ST

B/M

Mscf

14.7

100

200

500

1000

2000

3000

4000

5000

Pressure

How much potential water condensation are we facing? www.GEKEngineering.com 17

Condensation Drivers

• Loss of temperature

– Gas condenses to liquid phase

• Loss of Rate

– Slower velocity =>

• Poorer lift potential.

• Longer transit times, more heat loss, more

condensation opportunity.

– Less flowing mass => less total heat to loose

before water starts to condense.


Diagnostics: The production history of a well starting to load

up. There are usually many causes that lead to load-up.


0

500

1000

1500

2000

2500

3000

35004

/25

/20

00

5/2

/20

00

5/9

/20

00

5/1

6/2

00

0

5/2

3/2

00

0

5/3

0/2

00

0

6/6

/20

00

6/1

3/2

00

0

6/2

0/2

00

0

6/2

7/2

00

0

7/4

/20

00

7/1

1/2

00

0

7/1

8/2

00

0

7/2

5/2

00

0

8/1

/20

00

8/8

/20

00

8/1

5/2

00

0

8/2

2/2

00

0

8/2

9/2

00

0

9/5

/20

00

9/1

2/2

00

0

9/1

9/2

00

0

9/2

6/2

00

0

10

/3/2

00

0

10

/10

/20

00

10

/17

/20

00

10

/24

/20

00

10

/31

/20

00

Gas Rate (MCF/D) Line Pressure (PSI)

Typical Wamsutter New Well Decline

Champlin 242-C3 3-1/2” Production Casing


Liquid

holdup

from

declining

velocity

The liquid

holdup

applies a

backpress

ure to the

bottom

hole.

Rate is

decreased

Enough

liquid

finally

drops

down the

well to

reduce or

balance

formation

pressure.

Flow is

decreased

or the well

is dead.

Note pressures


An increase in

the differential

between casing

and tubing

pressure over

time indicates

loading.

No packer

example.

Time

Csg-tbg

pressure


Gradient survey to locate static liquid level.


Lift Selection Considerations

• Size of the prize?

• Cost of water prod?

• How much water?

• Source?

– Water control?

• Condensation cause?

• Condense location?

• Well limits?

• Safety valve?

• Power?

• Computer control?

• Well W/O costs?

• Well W/O risks?


Lift and Deliquification

• Natural Flow

• Intermitter

• Rocking

• Equalizing

• Venting

• Soaping

• Velocity String

• Compression

• Gas Lift

• Beam Lift

• Plunger

• ESP and HSP

• PCP

• Diaphragm Pump

• Jet Pump

• Eductor


What causes the short-lived increases

in rate when a well is started up after a

brief shut-in?

Q

Cumulative Production

Can it be used for

advantage?

What causes

the sharp

initial decline

when the

well is

brought on?


Why the increase after a shut-in?

1. Recharging of the near wellbore from the

formation away from the wellbore.

2. Cross flow from low permeability, higher

pressure zones to high permeability,

partly depleted zones (also recharging).

– High perm streaks

– Natural fractures

– Stimulated fractures


Most formations are

layered and often have

distinctly different

permeabilities in a

package of pay.

These layers flow as

individual units,

emptying the higher

perm units first before

the lower perm

reservoirs begin to flow.

When a well is shut in,

higher remaining

pressures in the low

perm layers cause flow

into the high perm, more

depleted streaks.

Natural cross flow!

fractured Fractured, high perm

shale shale

shale shale

10 md 10 md

1 md 1 md

10 md 10 md

Shutting in a Well at Surface Doesn’t Mean the Flow Stops Downhole!


Using Cross Flow

• Repressuring the higher permeability streaks

during a shut-in can lend a sharp, short lived

increase to flow and can help unload a well

without outside equipment or services.

• To use it effectively, the behavior of the well

such as how quickly it recharges, how quickly it

blows down and what happens to the water

during a shut-in must be understood.


Lift and Unloading Options

• At least 15 options of full time and part

time lift.

• The well design, conditions and

economics dictate the optimum method –

and remember – both can change with

decline.

• Another very important contributor is the

operator.


Well With A Plunger Installation

Installed Plunger


0

200

400

600

800

1000

1200

11/1

/199

6

11/1

5/199

6

11/2

9/199

6

12/1

3/199

6

12/2

7/199

6

1/10

/199

7

1/24

/199

7

2/7/

1997

2/21

/199

7

3/7/

1997

3/21

/199

7

4/4/

1997

4/18

/199

7

5/2/

1997

5/16

/199

7

5/30

/199

7

6/13

/199

7

6/27

/199

7

7/11

/199

7

7/25

/199

7

8/8/

1997

8/22

/199

7

9/5/

1997

9/19

/199

7

10/3

/199

7

10/1

7/199

7

10/3

1/199

7

MCFD

Tubing PSI

Casing PSI

Line PSI

Projection

Total Cost: $20,121

Average rate for 90 days prior to installation: 246 mcfd Average for last 30 days: 327 mcfd

Paid out in 3 months

Effective CT Velocity String – Champlin 149-B2

CT Installed

7” Casing 2-3/8” Tubing 1-1/4” CT


0

200

400

600

800

1000

1200

10

/1/1

99

9

10

/15

/19

99

10

/29

/19

99

11

/12

/19

99

11

/26

/19

99

12

/10

/19

99

12

/24

/19

99

1/7

/20

00

1/2

1/2

00

0

2/4

/20

00

2/1

8/2

00

0

3/3

/20

00

3/1

7/2

00

0

3/3

1/2

00

0

4/1

4/2

00

0

4/2

8/2

00

0

5/1

2/2

00

0

5/2

6/2

00

0

6/9

/20

00

6/2

3/2

00

0

7/7

/20

00

7/2

1/2

00

0

8/4

/20

00

8/1

8/2

00

0

9/1

/20

00

9/1

5/2

00

0

9/2

9/2

00

0

10

/13

/20

00

10

/27

/20

00

11

/10

/20

00

11

/24

/20

00

12

/8/2

00

0

12

/22

/20

00

MC

FD

-120

-100

-80

-60

-40

-20

0

MM

CF

MCFD Line PSI projection cumwedge

Gross Cost: $19905

Average rate for 90 days prior to installation: 911 mcfd Average rate for last 30 days: 539 mcfd

Ineffective CT Velocity String – Champlin 222-C2

5-1/2” Casing 2-3/8” Tubing 1-1/4” CT

CT Installed


0

200

400

600

800

1000

1200

1400

1600

1800

3/1/00

3/8/00

3/15

/00

3/22

/00

3/29

/00

4/5/00

4/12

/00

4/19

/00

4/26

/00

5/3/00

5/10

/00

5/17

/00

5/24

/00

5/31

/00

6/7/00

6/14

/00

6/21

/00

6/28

/00

7/5/00

7/12

/00

7/19

/00

7/26

/00

8/2/00

8/9/00

8/16

/00

8/23

/00

8/30

/00

9/6/00

9/13

/00

9/20

/00

9/27

/00

10/4/00

10/11/00

10/18/00

10/25/00

11/1/00

Gas R

ate

(M

CF

/D)

Soap Injection to Reduce Fluid Column Hydrostatic

Soap Injection

Venting to unload wellbore

CT Installed

CG Road 25-4 3-1/2” Casing 1-1/4” CT www.GEKEngineering.com 34

Conclusions

• Small increases in pressure drop can

make large gains in production.

– Every ft of liquid in a well holds nearly ½ psi in

backpressure on the formation.

– Water invading the pores of the rock during a

shut-in can be held on the formation and gas

cannot displace it.

– Water refluxing in a gas well is the largest

single source of corrosion.

– Liquid loaded wells may still produce but are

very erratic. www.GEKEngineering.com 35

Conclusions

• Tubng size is a legitimate and low cost

choice ONLY if GLR will allow the well to

be placed in mist flow.

• Lift consideration should include the limits

and well as the advantages.

• If Turner or Coleman correlations do not

work in your applications, develop your

own – Really, it’s OK!


Pressure

Effects of

Liquid

Loading


Jason Piggot, SPE 2002

Heating Gas – Downhole View During Gas Flow


0

100

200

300

400

500

600

700

800

900

1,000

A-9

4

D-9

4A-9

5A-9

5

D-9

5A-9

6A-9

6

D-9

6A-9

7A-9

7

D-9

7A-9

8A-9

8

D-9

8A-9

9A-9

9

MC

F/D

ay

Loading


Unstable Gas Well Flow Behavior, Followed by Loading



Heating Gas – Effects on Production

7000

6000

5000

4000

3000

2000

1000

0

0 20 40 60 80 100 120 140

Pressure, psig

Depth

Before Heating After Heatingwww.GEKEngineering.com 43

7000

6000

5000

4000

3000

2000

1000

0

60 70 80 90 100 110 120 130

Pressure, psia

Depth

Flowing Shut-in

Liquid Loading

Results in 30 PSI

Back-Pressure


Pressure Effects of Liquid Loading




0

100

200

300

400

500

600

700

May

-00

Jun-

00

Jul-0

0

Aug-0

0

Sep-0

0

Oct-0

0

Nov

-00

Dec

-00

Jan-

01

Feb-0

1

Mar

-01

Apr-0

1

May

-01

Jun-

01

Jul-0

1

Aug-0

1

Sep-0

1

Oct-0

1

Nov

-01

Dec

-01

Jan-

02

Feb-0

2

Mar

-02

MC

FD

Generator

Test

Shutdow n for 3 Phase

Pow er Installation

Cable Operational

3 Phase Pow er Installed

Line Restrictions Removed at Surface

Compressor Changed

Screw Compressor to 3 Stage

Current System Operational

Testing




0

100

200

300

400

500

600

1

11

21

31

41

51

61

71

81

91

101

111

121

131

141

151

161

171

181

191

201

211

221

231

241

251

261

271

281

291

301

311

321

331

341

351

361

371

381

391

401

411

Temperature, Deg. Fahrenheit Pressure, psig Rate, Mcf/Day

Tubing & Casing Flow

Compressor On

Cable On Casing Flow Only

Cable On

Compressor On

Compressor Dow n

Tubing Flow Only

Compressor On

Cable On

Compressor Dow n


Compressor On

Cable On


Compressor On

Cable Off



Heating Gas – Effects on Temperature Gradient

7,000

6,000

5,000

4,000

3,000

2,000

1,000

0

0 50 100 150 200 250 300

Temperature, F

De

pth

, ft.

After Heating Before Heating


Support Slides

• Lift Methods

• Deviated Wells

• Critical Flow Calculations


Lift Methods and Unloading

Options

• Most mechanical methods are build for oil

wells – that’s grossly over designed for

gas wells and much too expensive.

• A “dry” gas well may produce on 4 to 16

ounces per minute (100 to 500 cc/min).


Method Description Pros Cons

Natural

Flow

Flow of liquids up the

tubing propelled by

expanding gas bubbles.

Cheapest and

most steady

state flow

May not be

optimum flow.

Higher BHFP

than with lift.

Contin

uous

Gas Lift

Adding gas to the produced

fluid to assist upward flow

of liquids. 18% efficient.

Cheap. Most

widely used lift

offshore.

Still has high

BHFP. Req.

optimization.

ESP or

HSP

Electric submersible motor

driven pump. 38% efficient.

Or hydraulic driven pump

(req. power fluid path).

Can move v.

large volumes of

liquids.

Costly. Short

life. Probs. w/

gas, solids, and

heat.




Hydraul

ic

pump

Hydraulic power fluid

driven pump. 40% efficient.

Works deeper

than beam lift.

Less profile.

Req. power

fluid string and

larger wellbore.

Beam

Lift

Walking beam and rod

string operating a

downhole pump. Efficiency

just over 50%.

V. Common unit,

well understood,

Must separate

gas, limited on

depth and

pump rate.

Special

ty

pumps

Diaphram or other style of

pump.

Varies with

techniques.

New - sharp

learning curve.




Intermit

tent

Gas Lift

Uses gas injected usually at

one point to kick well off or

unload the well followed by

natural flow. 12% efficient.

Cheap and

doesn’t use the

gas volume of

continuous GL.

Does little to

reduce FBHP

past initial

kickoff.

Jet

pump

Uses a power fluid through

a jet to lift all fluids

Can lift any GOR

fluid.

Req. power

fluid string.

Probs with

solids.

PCP Progressive cavity pump. Can tolerate v.

large volumes of

solids and ultra

high visc. fluids.

Low rate,

costly, high

power

requirements.

Plunger A free traveling plunger

pushed by gas below to

mover a quantity of liquids

above the plunger.

Cheap, works on

low pressure

wells, control by

simple methods

Limited volume

of water moved,

cycles

backpressure.




Soap

Injection

Forms a foam with gas

from formation and water

to be lifted.

Does not require

downhole mods.

Costly in vol.

Low water flow.

Condensate is a

problem.

Compres

sion

Mechanical compressor

scavenges gas from well,

reducing column wt and

increasing velocity.

Does not require

downhole mods.

Cost for

compressor

and operation.

Limited to low

liquid vols.

Velocity

Strings

Inserts smaller string in

existing tbg to reduce flow

area and boost velocity

Relatively low

cost and easy

Higher friction,

corrosion and

less access.




Cycling /

Intermitt

er

Flow well until loading

starts, then shut in until

pressures build, then flow.

Cheap. Can be

effective if optm.

No DH mods.

Req. sufficient

pressure and

automation (?)

Equalizi

ng

Shuts in after loading.

Building pressure pushes

gas into well liquids and

liquids into the formation.

Will work if

higher perm and

pressure. No

downhole mods.

Takes long

time. May

damage

formation.

Rocking Pressure up annulus with

supply gas and then blow

tubing pressure down.

Inexpensive and

usually

successful.

Req. high press

supply gas.

Well has no

packer.

Venting

Blow down the well to

increase velocity and

decrease BHFP.

Cheap, simple,

no equipment

needed.

Not

environmentally

friendly.



Very Generalized Operating Ranges for Some Lift

Systems.

Note that some lift systems are depth limited and some are

volume limited. Almost all are limited to some extent by the

diameter of the wellbore. www.GEKEngineering.com 57

Deviated Wells

• About 30% of US produced gas comes

from offshore.

• Most offshore wells are deviated – Flow is

very different in deviated wells!


The liquid flow character can

change dramatically with depth

and deviation.

Severe liquid holdup by reflux

motion is common in the

Boycott Settling range of 30o to

60o.


In deviated wells, liquid holdup,

sometimes seen as a reflux or

percolation in sections of the

tubing, can account for large

volumes of water and significant

backpressure on the formation.

Liquid Holdup –

Driven By Density

Segregation In a vertical

well, the

falling liquid

droplet may

be lifted if

the rising

gas more

than offsets

the fall of the

liquid.


Oilfield Review


Oilfield Review

Note the flow

velocity

difference

between the

top and

bottom of the

pipe.


liquid loading and deliquification

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