scale formation.pdf

SPE DISTINGUISHED LECTURER SERIESis funded principally

through a grant of the

SPE FOUNDATIONThe Society gratefully acknowledges

those companies that support the programby allowing their professionals

to participate as Lecturers.

And special thanks to The American Institute of Mining, Metallurgical,and Petroleum Engineers (AIME) for their contribution to the program.

Oilfield Scale:A New Integrated Approach to Tackle an Old Foe

Dr Eric J. Mackay

Society of Petroleum EngineersDistinguished Lecturer 2007-08 Lecture Season

Flow Assurance and Scale Team (FAST)Institute of Petroleum EngineeringHeriot-Watt UniversityEdinburgh, [email protected]

of 40

Outline

1) The Old Foea) Definition of scaleb) Problems causedc) Common oilfield scalesd) Mechanisms of scale formation

2) The New Approacha) The new challengesb) Proactive rather than reactive scale managementc) Effect of reservoir processes

3) Conclusions

FormationWater (Ba)

Injection Water(SO4)

Ba2+ + SO42- BaSO4(s)

of 40

1a) Definition of Scale Scale is any crystalline

deposit (salt) resulting from the precipitation of mineral compounds present in water

Oilfield scales typically consist of one or more types of inorganic deposit along with other debris (organic precipitates, sand, corrosion products, etc.)

of 40

1b) Problems Caused Scale deposits

z formation damage (near wellbore)z blockages in perforations or gravel packz restrict/block flow linesz safety valve & choke failurez pump wearz corrosion underneath depositsz some scales are radioactive (NORM)

Suspended particlesz plug formation & filtration equipmentz reduce oil/water separator efficiency

of 40

Examples - Formation Damage

quartz grainsquartz grains

scale crystals block scale crystals block pore throatspore throats

of 40

Examples - Flow Restrictions

of 40

Examples - Facilities

separator scaled up

and aftercleaning

of 40

1c) Common Oilfield Scales

Iron Scales: Fe2O3, FeS, FeCO3

Some Other Scales

Sand GrainsHF solubleinsoluble2.65SiO2silicon dioxide

Exotic Scales: ZnS, PbS

(insoluble in HCl)357,0002.16NaClsodium chlorideacid soluble2,4102.32CaSO4.2H2Ocalcium sulphateacid soluble2,0902.96CaSO4calcium sulphate

slightly acid soluble1133.96SrSO4strontium sulphateacid soluble142.71CaCO3calcium carbonate

60 mg/l in 3% HCl2.24.50BaSO4barium sulphateCommon Scales

(mg/l)othercold waterGravity

SolubilitySpecificFormulaName

SPE 87459

of 40

1d) Mechanisms of Scale Formation

Carbonate scales precipitate due to P (and/or T)z wellbore & production facilities

Sulphate scales form due to mixing of incompatible brinesz injected (SO4) & formation (Ba, Sr and/or Ca)z near wellbore area, wellbore & production facilities

Concentration of salts due to dehydrationz wellbore & production facilities

Ca2+(aq) + 2HCO-3(aq) = CaCO3(s) + CO2(aq) + H2O(l)

Ba2+(aq) (Sr2+or Ca2+) + SO42-(aq) = BaSO4(s) (SrSO4 or CaSO4)

of 40

Outline

1) The Old Foea) Definition of scaleb) Problems causedc) Common oilfield scalesd) Mechanisms of scale formation

2) The New Approacha) The new challengesb) Proactive rather than reactive scale managementc) Effect of reservoir processes

3) Conclusions

FormationWater (Ba)

Injection Water(SO4)

Ba2+ + SO42- BaSO4(s)

of 40

2a) The New Challenges

Deepwater and other harsh environmentsz Low temperature and high pressurez Long residence timesz Access to well difficultz Compatibility with other production chemicals

Inhibitor placementz Complex wells (eg deviated, multiple pay zones)

Well value & scale management costs

of 40

Access to Well

Subsea wellsz difficult to monitor

brine chemistryz deferred oil during

squeezesz well interventions

expensive (rig hire)z squeeze

campaigns and/or pre-emptive squeezes

of 40

Inhibitor Placement in Complex Wells

Where is scaling brine being produced?

Can we get inhibitor where needed?z wellbore frictionz pressure zones

(layers / fault blocks)z damaged zones

Options:z Bullheadz bullhead + divertorz Coiled Tubing from rigz Inhibitor in proppant /

gravel pack / rat hole

Ptubing head

Fault

Shale

Pcomp 1

Pcomp N

Presv 1

Presv N

of 40

Well Value & Scale Management Costs

Deepwater wells costing US$10-100 million (eg GOM)

Interval Control Valves (ICVs) costing US$0.51 millioneach to installz good for inhibitor placement controlz susceptible to scale damage

Rig hire for treatments US$100-400 thousand / dayz necessary if using CTz deepwater may require 1-2 weeks / treatmentz cf. other typical treatment costs of US$50-150 thousand /

treatment

Sulphate Reduction Plant (SRP), installation and operation may cost US$20-100 million

of 40

0

1

2

3

4

5

6

7

8

9

10

11

1988

1989

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

Year

N

o

o

f

S

R

P

p

l

a

n

t

s

p

e

r

y

e

a

r

0

1,000,000

2,000,000

3,000,000

4,000,000

5,000,000

C

u

m

u

l

a

t

i

v

e

C

a

p

a

c

i

t

y

(

B

W

P

D

)

No of SRP plantsCumulative Capacity (BWPD)

Number of SRP per Year and Total Capacity

of 40

2b) Proactive Rather Than ReactiveScale Management

Scale management considered during CAPEX Absolute must:

good quality brine samples and analysis Predict

z water production history and profiles well by wellz brine chemistry evolution during well life cyclez impact of reservoir interactions on brine chemistryz ability to perform bullhead squeezes:

flow lines from surface facilities correct placement

Monitor and review strategy during OPEX

of 40

2c) Effect of Reservoir Processes

EXAMPLE 1 Management of waterflood leading to extended brine mixing at producers(increased scale risk)

EXAMPLE 2 In situ mixing and BaSO4 precipitation leading to barium stripping(reduced scale risk)

EXAMPLE 3 Ion exchange and CaSO4 precipitation leading to sulphate stripping(reduced scale risk)

of 40

SPE 80252

Extended Brine Mixing at Producers

EXAMPLE 1

of 40

SPE 80252

Field M (streamline model)

This well has been treated > 220 times!

Extended Brine Mixing at Producers

EXAMPLE 1

of 40

Barium Stripping (Field A)

% injection water

B

a

r

i

u

m

(

m

g

/

l

)

Dilution line

SPE 60193EXAMPLE 2

of 40

Barium Stripping (Theory)

Injection water (containing SO4) mixes with formation water (containing Ba) leading to BaSO4 precipitation in the reservoir

Minimal impact on permeability in the reservoir

Reduces BaSO4 scaling tendency at production wells

SPE 94052EXAMPLE 2

of 40


Ba2+

Rock

SO42-

1) Formation water (FW): [Ba2+] but negligible [SO42-]

FW

(hot)

EXAMPLE 2

of 40


Ba2+ SO42-

2) Waterflood: SO42- rich injection water displaces Ba2+ rich FW

Rock

FWIW

(cold) (hot)

EXAMPLE 2

of 40


Ba2+ SO42-

Rock

3) Reaction: In mixing zone Ba2+ + SO42- BaSO4

FWIW

(cold) (hot)

BaSO4

EXAMPLE 2

of 40


0

100

200

300

400

500

600

700

800

900

0 20 40 60 80 100seawater fraction (%)

[

B

a

]

(

m

g

/

l

)

0

500

1000

1500

2000

2500

3000

[

S

O

4

]

(

m

g

/

l

)

BaBa (mixing)SO4SO4 (mixing)

Large reduction in [Ba]

Small reduction in [SO4](SO4 in excess)

Typical behaviour observed in many fields

EXAMPLE 2

of 40

Barium Stripping (Model & Field Data)

0

10

20

30

40

50

60

70

80

90

0 20 40 60 80 100% seawater

b

a

r

i

u

m

c

o

n

c

e

n

t

r

a

t

i

o

n

(

p

p

m

)

Field A - actualField A - dilution lineField A - modelled

EXAMPLE 2

of 40

Sulphate Stripping (Theory)

Injection water (with high Mg/Ca ratio) mixes with formation water (with low Mg/Ca ratio) leading to Mg and Ca exchange with rock to re-equilibrate

Increase in Ca in Injection water leads to CaSO4 precipitation in hotter zones in reservoir

Minimal impact on permeability in the reservoir

Reduces BaSO4 scaling tendency at production wells

SPE 100516EXAMPLE 3

of 40

Ion Exchange

Ca

Mg

Ca

Mg

CC

0.50 CC =

FW: 0.077

IW: 3.2

Rock: 0.038

Mg on rockMg

Ca on rockCa

Mg in solutionCMg

Ca in solutionCCa2,325

30,185

Gyda FW (mg/l)

1,368426

IW (mg/l)

EXAMPLE 3

of 40


Ba2+

Rock

SO42- Ca2+ Mg2+

1) Formation water: [Ca2+] and [Mg2+] in equilibrium with rock

FW

(hot)

EXAMPLE 3

of 40


Ba2+ SO42- Ca2+ Mg2+

2) Waterflood: [Ca2+] and [Mg2+] no longer in equilibrium

Rock

FWIW

(cold) (hot)

EXAMPLE 3

of 40



3) Reaction 1: Ca2+ and Mg2+ ion exchange with rock

Rock

FWIW

(cold) (hot)

EXAMPLE 3

of 40



4) Reaction 2: In hotter zones Ca2+ + SO42- CaSO4

Rock

FWIW

(cold) (hot)

CaSO4

EXAMPLE 3

of 40

Modelling Prediction: [Ca] and [Mg]

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000


[

C

a

]

(

m

g

/

l

)

0

500

1,000

1,500

2,000

2,500

3,000

3,500

[

M

g

]

(

m

g

/

l

)

CaCa (mixing)MgMg (mixing)

Large reduction in [Mg]

No apparent change in [Ca]

EXAMPLE 3

of 40

Observed Field Data: [Ca] and [Mg]

Large reduction in [Mg]

No apparent change in [Ca]

EXAMPLE 3

0

5000

10000

15000

20000

25000

30000

35000

40000

0 20 40 60 80 100

seawater fraction (%)

[

C

a

]

(

m

g

/

l

)

0

1000

2000

3000

4000

5000

6000

7000

8000

[

M

g

]

(

m

g

/

l

)

CaCa (mixing)MglMg (mixing)

of 40

Modelling Prediction: [Ba] and [SO4]

0

100

200

300

400

500

600

700

800

900


[

B

a

]

(

m

g

/

l

)

0

500

1000

1500

2000

2500

3000

[

S

O

4

]

(

m

g

/

l

)

BaBa (mixing)SO4SO4 (mixing)

EXAMPLE 3

Small reduction in [Ba]

Large reduction in [SO4](No SO4 at < 40% SW)

of 40

Observed Field Data: [Ba] and [SO4]

Small reduction in [Ba]

Large reduction in [SO4](No SO4 at < 40% SW)

EXAMPLE 3

0

50

100

150

200

250

300

0 20 40 60 80 100

seawater fraction (%)

[

B

a

]

(

m

g

/

l

)

0

500

1000

1500

2000

2500

3000

[

S

O

4

]

(

m

g

/

l

)

BaBa (mixing)SO4lSO4 (mixing)

of 40

3) Conclusions

Modelling tools may assist with understanding of where scale is forming and what is best scale management optionz identify location and impact of scalingz evaluate feasibility of chemical options

thus providing input for economic model.

Particularly important in deepwater & harsh environments, where intervention may be difficult & expensive

But must be aware of uncertainties..z reservoir descriptionz numerical errorsz changes to production schedule, etc.

so monitoring essential.

of 40

Acknowledgements

Sponsors of Flow Assurance and Scale Team (FAST) at Heriot-Watt University:

of 40

Extra Slides

Barium stripping example (Field G) Placement example (Field X)

of 40

Barium Stripping (Field G)

a) water saturation b) mixing zone

c) BaSO4 deposition (lb/ft3)

SPE 80252

Field G (model)

EXAMPLE G

of 40


0

50

100

150

200

250

0 500 1000 1500 2000 2500

time (days)

b

a

r

i

u

m

c

o

n

c

e

n

t

r

a

t

i

o

n

(

p

p

m

)

0

500

1000

1500

2000

2500

3000

s

u

l

p

h

a

t

e

c

o

n

c

e

n

t

r

a

t

i

o

n

(

p

p

m

)

Ba Ba (no precip)SO4SO4 (no precip)

[Ba] at well when noreactions in reservoir

[Ba] at well when reactions in reservoir

Field G (model)

EXAMPLE G

of 40


0

50

100

150

200

250

0 20 40 60 80 100

% seawater

b

a

r

i

u

m

c

o

n

c

e

n

t

r

a

t

i

o

n

(

p

p

m

Field B - observedFiled B - dilution lineField B - modelled

deep reservoir + well/near well mixing

deep reservoir mixing

0

50

100

150

200

250

0 20 40 60 80 100

% seawater

b

a

r

i

u

m

c

o

n

c

e

n

t

r

a

t

i

o

n

(

p

p

m

Field B - observedFiled B - dilution lineField B - modelled

deep reservoir + well/near well mixingdeep reservoir + well/near well mixing

deep reservoir mixingdeep reservoir mixing

Field G (model & field data)

EXAMPLE G

of 40

Impact of Reservoir Pressures on Placement

Question for new subsea field under development:

Can adequate placement be achieved without using expensive rig operations?

EXAMPLE X

of 40

Placement (Field D)

-200

-100

0

100

200

300

400

500

0 200 400 600 800

well length (m)

f

l

o

w

r

a

t

e

(

m

3

/

d

) prior to squeezeshut-inINJ 1 bbl/mINJ 5 bbl/mINJ 10 bbl/m1 year after squeeze

production

injection(squeeze)

Good placement along length of well during treatment (> 5 bbls/min) Can squeeze this well

SPE 87459EXAMPLE X

of 40

Placement (Field D)production

injection(squeeze)

Cannot place into toe of well by bullhead treatment, even at 10 bbl/min Must use coiled tubing (from rig - cost), or sulphate removal

-600

-500

-400

-300

-200

-100

0

100

0 200 400 600 800

well length (m)

f

l

o

w

r

a

t

e

(

m

3

/

d

) prior to squeezeshut-inINJ 1 bbl/mINJ 5 bbl/mINJ 10 bbl/m1 year after squeeze

SPE 87459EXAMPLE X

Documents

scale formation.pdf