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Development and Application of Foamers

to Enhance Oil and Gas Production

Baker Hughes Incorporated

Scott Lehrer, Saet Byul Debord

Scott Lehrer (presenter)

Outline

• Introduction

– Life cycle of a well

– Foamer theory

• Current foamer technology

– Benefits and gaps

– On-land application of aqueous foamers

– Offshore application of condensate foamers

• Development of crude oil foamers

– Potential benefits

– Experimental methods

– Successful field application results

• Conclusions

Challenges with Mature Wells

• Decrease in reservoir pressure over time

– Fluids accumulate, creating hydrostatic pressure

– Rapid production decline

– Wells become difficult to restart

• Sometimes alleviated by mechanical unloading

– Not always best option, depending on specific well

– Requires investment in capital equipment

– Requires available space and power

Liquid

Liquid

without

foamer

Liquid with foamer

Vc

Foam

Vc

Vc = 1.593[σ1/4(ρl - ρg)1/4] /(ρg)1/2

Foamers Lower Critical Velocity

• Foam – bubbles of gas surrounded by thin liquid layer

• Foamers lower surface tension

Existing Foamer Technology

• Aqueous foamers effective for brine-rich fluids

• Condensate foamers effective with high API fluids

• Current technology ineffective for crude oil

5

Brine cut,%

AP

I g

ravit

y Traditional water-

based foamers

20

Condensate

foamer

50 100

55

45

Gap in current

technology

25

Foamers Became an Emerging Solution for

Gas Wells

• Used a broad range of aqueous surfactants

• Economic and flexible solution for on-land gas wells

• Condensate foamers also used

– Applied successfully both on-land and offshore

• Little or no capital equipment requirements

Benefits of Foamer Application

• Foamers can increase production significantly by unloading well fluids

7

Daily Production - P Hopkins 4

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2005

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2005

Date

Dai

ly R

ate

DryVol

Oil

Water

Gas

Water

Oil

Aqueous Foamer Increased Production

((100 Mcf/D * $3.50 / Mcf) - $22.50 foamer cost/D)

* 365 * 100 wells= $12MM/y incremental revenue

Foamer Added

Offshore Condensate Foamer Application

• Synopsis from previous presentations (Mark Embrey, BHI)

– Gas Well Deliquification Workshop (Denver, 2010 & 2011)

• Offshore Thailand gas wells experience fluid loading

issues

– Reaches critical rate after 2 – 3 years

– Current solution – wells flow intermittently

– No artificial lift currently in place

– Wells shut in due to fluid loading

© 2011 Baker Hughes Incorporated. All Rights Reserved. 8

Challenges in Offshore Applications

Subsurface Safety Valve Requirement and

Surface Safety Valve Interference

• Offshore wells and on shore wells in Europe have a surface

safety valve and subsurface safety valve

• Capillary can not be hung from the top of a standard wellhead

like typical land wells installations

InjectSafe®

• Modified WRSCSSV

– Wireline retrievable surface controlled sub-surface safety valve

– Provides chemical flow path around flapper valve

– SCSSV still fully functional

– No workover required

• Wellhead Adapter

– Capillary hung below all tree valves

– Still have access to BPT

– Maintain full functionality of wellhead

Offshore Capillary Trials

• Performed trials on 3 wells in Gulf of Thailand in January

2009

• Ran capillary to set depth and pumped foamer while

flowing the well for several days

• Results were promising and led eventually to a permanent

installation

• Example presented is from Funan Field, Well #9

– Fluids produced > 80% condensate

Results of Condensate Foamer Application

© 2011 Baker Hughes Incorporated. All Rights Reserved. 12

• Adding condensate foamer increased gas production by unloading

well fluids

Drastic production

decrease before foamer

Potential Foamer Benefits in Oil Wells

• Increase production of flowing wells

– Alleviate liquid loading by reducing fluid density

– Increase oil and gas flow, reduce downtime

– Alleviate slugging

• Supplement gas lift when inadequate

– Insufficient gas supply to optimize gas lift

– Gas lift mandrels located well above end of tubing

• Restart wells shut in for maintenance

Oil Foamer Lab Test

• Fluids added to foam

column, sparged with gas

and preheated

• Fluid volume measured

• Fluids treated with foamer

• Foam volume measured

during test

Lab Test (cont’d)

• Foam can reach the top of

test column

• Foam overflow is captured

and weighed

New Oil Foamer Requirements

• Identify appropriate chemistry to foam crude oil

• Perform in a wide range of oils

• Have flexible application methods

– Capillary, batch, gas lift

• Stable in the well bore environment

• Resulting foam responsive to typical defoamers

• Has no impact on asset integrity

Two Oil Foamers Developed

* Oil foamer A passed “gunking” qualification test

Oil foamer A Oil foamer B

Gas lift

application? Yes * No

Capillary approved 300F 200F

Oil Foamers Evaluated in Multiple Fluids

• The recommended dosage is based on lab tests. The

dosage would be optimized during the field application.

Well # 1 2 3 4 5 6

BOPD 1630 600 850 50 340 315

BWPD 20 30 90 50 185 270

API gravity 30 33.5 32 40 34.5 36.3

Bottom hole

F 137 192 133 300 183 168

Via Gas lift? No Yes Yes No Yes Yes

Oil foamer

tested B A A A A A

ppm 5,000 2,000 1,000 1,500 2,500 500

Oil foamer

effective? Yes Yes Yes Yes Yes Yes

Foamer Technology Extended to Treat Crude

Oil

• Enhance production without water quality issues

• Effective in lab testing with crudes 25 to 40 API

• Water cuts 0% to 60%

Brine cut (%)

AP

I g

ravit

y Traditional water-

based foamers

20

Condensate

foamer

40 100

45

25

35 Novel Oil Foamer

Case Study:

EOG Resources South Texas Oil Well

Background

• Well depth: 10,000 ft (3048 m)

• Bottom hole temperature: 300°F (149°C)

• 50% brine / 50% oil; API 40°

• Aqueous foamer capillary applied to near bottom hole

• Retention time only 5 minutes due to small gas/liquid

separator

Production History

• Cycling production – 7 days on, 7 days off

• Historical production

– 250 Mcf/D gas, 40 BOPD, 40 BWPD

• 60 days before trial

– 122 Mcf/D gas, 13 BOPD, 9 BWPD

• Aqueous foamer unable to maintain production

Laboratory Results

• Baseline fluid contained 1500 ppm aqueous foamer

• Baseline fluid did not reach unloading threshold

• Unloading occurred with 1500 ppm crude oil foamer

0

200

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600

800

1000

1200

0 500 1000 1500 2000

Flu

id V

olu

me

(m

L)

Crude Oil Foamer (ppm)

Unloading

started

Unloading threshold

Field Trial Procedure

• Discontinued aqueous foamer and flushed capillary

• Applied 750 ppm oil foamer downhole via capillary

• Defoamer added upstream of separator

• Measured gas, oil, and water production

• Monitored foam carryover potential by “rag test”

• Collected water samples to evaluate emulsification

Field Trial Results –

Incumbent vs. Oil Foamer

• Production time extended to 11 days from 7 days

• Gas and oil production rates more than doubled

0

20

40

60

80

100

120

0

100

200

300

400

500

600

Mcf/

D

Gas

Oil

BO

PD

Oil Foamer

injected

Field Trial Results – Revenue Impact

0

1000

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7000

8000

9000

10000

Average Net Revenue /Day

$/D

ay

60 Day Incumbent 7 Day Trial

Based on $75/barrel crude, $4/Mcf

Field Trial Results – Water Quality

Produced Water Quality

w/ Aqueous Foamer

Produced Water Quality

w/ New Oil Foamer

Conclusions

• Foamer injection is a viable method to enable wells with liquid

loading issues to be returned to continuous flowing status

• Capillary injection systems are emerging as a viable option for

offshore applications

• Oil foamers developed effective in lab testing over a wide range

of crude oils

• Potential benefits of oil foamers identified include enhancing

flowing well production and restarting wells

• Oil foamers were formulated for multiple application methods

• Field trial confirmed oil foamers’ effectiveness

– Increased run length, oil & gas production

– No negative impact on water quality, oil/water separation

– Foam controlled with conventional defoamers

Acknowledgments

The authors would like to acknowledge Baker Hughes, Inc. for allowing

us to publish this paper

The authors thank Carlene Means for her contributions in

development of the crude oil foamer and Simon Crosby, Gus Fuentes,

Jeff Long, in Baker Hughes production operations for supporting the

field trial in south Texas

The authors thank Mark Embrey for his contributions to this

presentation

The authors also thank EOG Resources for providing a location to

field trial the new foamer technology and for their assistance during

the trial