De Liquification

8/21/2019 De Liquification

1/62

Low Pressure Gas Well

Deliverability Issues: CommonLoading Causes, Diagnostics

and Effective DeliquificationPractices

George E. KingBrownfields: Optimizing Mature Assets Conference,

September 19-20, 2005, Denver, Colorado.

www.GEKEngineering.com 1


2/62

May Add Energy

to System

Whats New?

Technology -Cost, price?

What Technology Will Drive Deliquification?

Life Cycle of a Gas Well



3/62

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.



4/62

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.



5/62

Example: Oklahoma Gas Wells

Oklahoma Gas Production Per Well

0

50

100

150

200

250

1992 1994 1996 1998 2000

Gas

Pro

duc

tion

Per

Well

mc

f/d

32,672 producing gas wells in 2001

Average Flow Per Well



6/62

Tubing Performance - Vertical

P P

gas and

liquid

gas

Gas WellOil Well

oil, water

and gas

oil

gas, oil

and waterWater vapor

condenses as

gas rises and

expands.

Water must be

removed to

allow the well to

flow.

Water thatbuilds up holds

a backpressure

on the

formation.

T



7/62

Turner Unloading Rate, Water

0

500

1000

1500

2000

2500

3000

0 100 200 300 400 500

Flowing Pressure, psi

GasRate(mscf/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)

SourceJ. Lea, Texas Tech, Turner Correlations.

For pressures > 1000 psi



8/62

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.



9/62

Small Gas Well ExampleLift

Progression2-3/8 Tubing

Flow and Lift - 2-3/8" Tubing

0

200

400600

800

1000

1200

14001600

1800

2000

0 20 40 60 80 100

Percent of Well Life

GasF

low

Ra

te,

MSCFD

Flow to here

then plunger

then ?

Source -Bryan

Dotson


W ll h i


10/62

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

Pump

HP

1000' depth

5000' depth

10000' depth

Low Pow er is 1-10 HP.

Micro Pow er is less than

2 HP.

Well have to put energy into

the well:



11/62

How Much Can We Pay?

10 50100

200

$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 cant afford

too much



12/62

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.www.GEKEngineering.com 12


13/62

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 wellbore can

alter the

velocity.

Where is

critical ratecalculated?

Multiple

velocity

calculations

are needed

with gas in

compressed

state.


G B bbl G th With Ri


14/62

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 RiseIn A Water Column

Gas column is differentgas is low density at the top of a

column and higher density at bottomso although rate isconstant, velocity is not.www.GEKEngineering.com 14


15/62

Liquids in Gas Wells

Gas phasecondensing to a liquid

Waterseveral bbls/mmcf, unusually fresh

Condensatecan be much higher volume

Connate Water

Usually saltier than condensing water

Often stays in bottom of the well.



16/62

Where is Critical Rate Calculated?

Surface or Bottom Hole?Pres: 400#

Temp: 60 deg F

Tbg: 1 CT

Rate: 200 mscfd

10,000 1 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 Csg to Perfs



17/62

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)

STB/MMscf

14.7

100

200

500

1000

2000

3000

4000

5000

Pressure

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


18/62

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.


Di ti Th d ti hi t f ll t ti t l d


19/62

Diagnostics: The production history of a well starting to load

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



20/62

0

500

1000

1500

2000

2500

3000

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10/17/2000

10/24/2000

10/31/2000

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

Typical Wamsutter New Well Decline

Champlin 242-C3 3-1/2 Production Casing


Note pressures


21/62

Liquid

holdup

from

decliningvelocity

The liquid

holdup

applies a

backpressure to the

bottom

hole.

Rate is

decreased

Enough

liquid

finally

dropsdown the

well to

reduce or

balance

formation

pressure.

Flow is

decreased

or the well

is dead.

Note pressures



22/62

An increase in

the differential

between casingand tubing

pressure over

time indicatesloading.

No packerexample.

Time

Csg-tbg

pressure


G di t t l t t ti li id l l


23/62

Gradient survey to locate static liquid level.



24/62

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?



25/62

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



26/62

What causes the short-lived increases

in rate when a well is started up after abrief shut-in?

Q

Cumulative Production

Can it be used for

advantage?

What causes

the sharp

initial decline

when the

well is

brought on?



27/62

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


Shutting in a Well at Surface Doesnt Mean the Flow Stops Downhole!


28/62

Most formations are

layered and often have

distinctly differentpermeabilities in a

package of pay.

These layers flow as

individual units,

emptying the higherperm 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

shaleshale

shale shale

10 md10 md

1 md 1 md

10 md 10 md

Shutting in a Well at Surface Doesn t Mean the Flow Stops Downhole!



29/62

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.



30/62

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 rememberboth can change with

decline.

Another very important contributor is the

operator.



31/62

Well With A Plunger Installation

Installed Plunger



32/62

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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 StringChamplin 149-B2

CT Installed

7 Casing 2-3/8 Tubing 1-1/4 CT



33/62

0

200

400

600

800

1000

1200

10/1/1999

10/15/1999

10/29/1999

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10/27/2000

11/10/2000

11/24/2000

12/8/2000

12/22/2000

MCFD

-120

-100

-80

-60

-40

-20

0

MMCF

MCFD Line PSI projection cumwedge

Gross Cost: $19905

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

Ineffective CT Velocity StringChamplin 222-C2

5-1/2 Casing 2-3/8 Tubing 1-1/4 CT

CT Installed



34/62

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10/4/00

10/11/00

10/18/00

10/25/00

11/1/00

GasRate

(MCF/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



35/62

Conclusions

Small increases in pressure drop can

make large gains in production.

Every ft of liquid in a well holds nearly 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


36/62

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 yourownReally, its OK!


Pressure


37/62

Pressure

Effects of

Liquid

Loading


Heating Gas Downhole View During Gas Flow


38/62

Jason Piggot, SPE 2002

Heating GasDownhole View During Gas Flow


Heating Gas

Downhole View During Gas Flow


39/62


Heating Gas



Heating Gas



40/62


Heating Gas



Heating Gas



41/62


Heating Gas




42/62

0

100

200

300

400

500

600

700

800

900

1,000

A-94

D-94

A-95

A-95

D-95

A-96

A-96

D-96

A-97

A-97

D-97

A-98

A-98

D-98

A-99

A-99

MCF/Day

Loading


Unstable Gas Well Flow Behavior, Followed by Loading


Heating GasEffects on Production


43/62


g

7000

6000

5000

4000

3000

2000

1000

0

0 20 40 60 80 100 120 140

Pressure, psig

Dept

h

Before Heating After Heatingwww.GEKEngineering.com 43

Pressure Effects of Liquid Loading


44/62

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


q g




45/62


g

0

100

200

300

400

500

600

700

May-00

Jun-0

0Jul-00

Aug-00

Sep-00

Oct-0

0

Nov-0

0

Dec-00

Jan-0

1

Feb-01

Mar-0

1

Apr-0

1

May-01

Jun-0

1Jul-0

1

Aug-01

Sep-01

Oct-0

1

Nov-0

1

Dec-01

Jan-0

2

Feb-02

Mar-0

2

MC

FD

Generator

Test

Shutdown f or 3 Phase

Power Installation

Cable Operational

3 Phase Power Installed

Line Restrictions Removed at Surface

Compressor ChangedScrew Compressor to 3 Stage

Current System Operational

Testing




46/62


g

0

100

200

300

400

500

600

111

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 OnlyCable On

Compressor On

Compressor Dow n

Tubing Flow Only

Compressor On

Cable On

Compressor Down


Compressor On

Cable On


Compressor On

Cable Off


Heating GasEffects on Temperature Gradient


47/62


g

p

7,000

6,000

5,000

4,000

3,000

2,000

1,000

0

0 50 100 150 200 250 300

Temperature, F

Depth,

ft.

After Heating Before Heating


Heating GasDownhole View During Gas Flow


48/62


g

g


Heating Gas



49/62


g g



50/62

Support Slides

Lift Methods

Deviated Wells

Critical Flow Calculations


Lift M th d d U l di


51/62

Lift Methods and Unloading

Options

Most mechanical methods are build for oil

wellsthats 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).




52/62

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.

Continuous

Gas Lift

Adding gas to the producedfluid to assist upward flow

of liquids. 18% efficient.

Cheap. Mostwidely used lift

offshore.

Still has highBHFP. 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 ofliquids.

Costly. Short

life. Probs. w/gas, solids, and

heat.





53/62


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

typumps

Diaphram or other style of

pump.

Varies with

techniques.

New - sharp

learning curve.





54/62


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

doesnt use the

gas volume of

continuous GL.

Does little to

reduce FBHP

past initial

kickoff.

Jetpump Uses a power fluid througha jet to lift all fluids Can lift any GORfluid. Req. powerfluid string.

Probs with

solids.

PCP Progressive cavity pump. Can tolerate v.

large volumes ofsolids and ultra

high visc. fluids.

Low rate,

costly, highpower

requirements.

Plunger A free traveling plunger

pushed by gas below to

mover a quantity of liquidsabove the plunger.

Cheap, works on

low pressure

wells, control bysimple methods

Limited volume

of water moved,

cyclesbackpressure.





55/62


SoapInjection

Forms a foam with gasfrom formation and water

to be lifted.

Does not requiredownhole 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

compressorand operation.

Limited to low

liquid vols.

Velocity

Strings

Inserts smaller string in

existing tbg to reduce flowarea and boost velocity

Relatively low

cost and easy

Higher friction,

corrosion andless access.





56/62


Cycling /Intermitt

er

Flow well until loadingstarts, then shut in until

pressures build, then flow.

Cheap. Can beeffective if optm.

No DH mods.

Req. sufficientpressure and

automation (?)

Equalizi

ng

Shuts in after loading.

Building pressure pushes

gas into well liquids andliquids into the formation.

Will work if

higher perm and

pressure. Nodownhole mods.

Takes long

time. May

damageformation.

Rocking Pressure up annulus with

supply gas and then blow

tubing pressure down.

Inexpensive and

usually

successful.

Req. high press

supply gas.

Well has nopacker.

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


57/62

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


58/62

Deviated Wells

About 30% of US produced gas comes

from offshore.

Most offshore wells are deviatedFlow is

very different in deviated wells!


The liquid flow character can


59/62

The liquid flow character can

change dramatically with depth

and deviation.

Severe liquid holdup by refluxmotion is common in the

Boycott Settling range of 30oto

60o.


Liquid Holdup


60/62

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.

q p

Driven By Density

Segregation

In a verticalwell, the

falling liquid

droplet may

be lifted if

the risinggas more

than offsets

the fall of the

liquid.



61/62

Oilfield Reviewwww.GEKEngineering.com 61

Note the flow


62/62

Oilfield Review

Note the flow

velocity

difference

between thetop and

bottom of the

pipe.

De Liquification

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