spe-dl slides ericmackayall

SPE DISTINGUISHED LECTURER SERIES is funded principally

through a grant of the

SPE FOUNDATION

The Society gratefully acknowledges

those companies that support the program

by 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 Engineers

Distinguished Lecturer 2006-07 Lecture Season

Flow Assurance and Scale Team (FAST)

Institute of Petroleum Engineering

Heriot-Watt University

Edinburgh, Scotland

[email protected]

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Outline

1) The Old Foe a) Definition of scale

b) Problems caused

c) Common oilfield scales

d) Mechanisms of scale formation

e) Location of scale deposition

2) The New Approach a) The new challenges

b) Proactive rather than reactive scale management

c) Effect of reservoir processes

3) Conclusions

Formation

Water (Ba)

• • • •

• • • • • • •

Sea Water

(SO4)

Ba2+ + SO42- BaSO4(s)

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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.)

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1b) Problems Caused

Scale deposits formation damage (near wellbore)

blockages in perforations or gravel pack

restrict/block flow lines

safety valve & choke failure

pump wear

corrosion underneath deposits

some scales are radioactive (NORM)

Suspended particles plug formation & filtration equipment

reduce oil/water separator efficiency

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Examples - Formation Damage

quartz grains

scale crystals block

pore throats

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Examples - Flow Restrictions

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Examples - Facilities

separator

scaled up

and after

cleaning

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1c) Common Oilfield Scales Name Formula Specific Solubility

Gravity cold water other

(mg/l)

Common Scales

barium sulphate BaSO4 4.50 2.2 60 mg/l in 3% HCl

calcium carbonate CaCO3 2.71 14 acid soluble

strontium sulphate SrSO4 3.96 113 slightly acid soluble

calcium sulphate CaSO4 2.96 2,090 acid soluble

calcium sulphate CaSO4.2H2O 2.32 2,410 acid soluble

sodium chloride NaCl 2.16 357,000 (insoluble in HCl)

Sand Grains

silicon dioxide SiO2 2.65 insoluble HF soluble

Some Other Scales

Iron Scales: Fe2O3, FeS, FeCO3

Exotic Scales: ZnS, PbS

SPE 87459

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1d) Mechanisms of Scale Formation

Carbonate scales precipitate due to DP

wellbore & production facilities

Sulphate scales form due to mixing of incompatible brines

injected (SO4) & formation (Ba, Sr and/or Ca)

near wellbore area, wellbore & production facilities

Concentration of salts due to dehydration

wellbore & production facilities

Ca2+(aq) + 2HCO-

3(aq) = CaCO3(s) + CO2(aq) + H2O(l)

Ba2+(aq) (Sr2+or Ca2+) + SO4

2-(aq) = BaSO4(s) (SrSO4 or CaSO4)

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seawater

formation brine

1e) Location of Scale Deposition

b c d e

f g

i

h

b

a

SPE 94052

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Outline

1) The Old Foe a) Definition of scale

b) Problems caused

c) Common oilfield scales

d) Mechanisms of scale formation

e) Location of scale deposition

2) The New Approach a) The new challenges

b) Proactive rather than reactive scale management

c) Effect of reservoir processes

3) Conclusions

Formation

Water (Ba)

• • • •

• • • • • • •

Sea Water

(SO4)

Ba2+ + SO42- BaSO4(s)

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2a) The New Challenges

Deepwater and other harsh environments Temperature and pressure

Residence times

Access to well

Production chemicals compatibility

Inhibitor placement Complex wells (eg deviated, multilateral)

Well value & scale management costs Deepwater

Downhole instrumentation

Rig hire vs Sulphate Reduction Plant

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Access to Well

Subsea wells

difficult to monitor

brine chemistry

deferred oil during

squeezes

well interventions

expensive (rig hire)

bullhead (placement)

squeeze campaigns

and/or pre-emptive

squeezes

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Inhibitor Placement in Complex Wells

Where is scaling brine being produced?

Can we get inhibitor where needed?

wellbore friction

pressure zones (layers / fault blocks)

damaged zones

Options:

bullhead (from platform / FPS via subsea chemical injection or test line)

bullhead + divertor

Coiled Tubing (CT) from rig

Combined stimulation / inhibitor treatments

Ptubing head

Fault

Shale

Pcomp 1

Pcomp N

Presv 1

Presv N

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Well Value & Scale Management Costs

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

Interval Control Valves (ICVs) costing US$0.5–1 million each to install

good for inhibitor placement control

susceptible to scale damage

Rig hire for treatments US$100-400 thousand / day

necessary if using CT

deepwater may require 1-2 weeks / treatment

cf. other typical treatment costs of US$50-150 thousand / treatment

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

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2b) Proactive Rather Than Reactive

Scale Management

Scale management considered during CAPEX

Absolute must: good quality brine samples and analysis

Predict water production history and profiles well by well

brine chemistry evolution during well life cycle

impact of reservoir interactions on brine chemistry

ability to perform bullhead squeezes:

• flow lines from surface facilities

• correct placement

Monitor and review strategy during OPEX

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2c) Effect of Reservoir Processes

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

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

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

EXAMPLE 4 Impact of reservoir pressures (correct / incorrect placement profiles)

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SPE 80252

Extended Brine Mixing at Producers

EXAMPLE 1

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SPE 80252

Field M (streamline model)

This well has been

treated > 220 times!

Extended Brine Mixing at Producers

EXAMPLE 1

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Barium Stripping (Field A)

% seawater

Bari

um

(m

g/l

)

Dilution line

SPE 60193 EXAMPLE 2

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Barium Stripping (Theory)

Seawater (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 94052 EXAMPLE 2

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Ba2+

Rock

SO42-

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

FW

(hot)

EXAMPLE 2

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Ba2+ SO42-

2) Waterflood: SO42- rich seawater displaces Ba2+ rich FW

Rock

FW SW

(cold) (hot)

EXAMPLE 2

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Ba2+ SO42-

Rock

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

FW SW

(cold) (hot)

BaSO4

EXAMPLE 2

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0

100

200

300

400

500

600

700

800

900

0 20 40 60 80 100

seawater fraction (%)

[Ba

] (m

g/l

)

0

500

1000

1500

2000

2500

3000

[SO

4]

(mg

/l)

Ba

Ba (mixing)

SO4

SO4 (mixing)

•Large reduction in

[Ba]

•Small reduction in

[SO4]

(SO4 in excess)

•Typical behaviour

observed in many

fields

EXAMPLE 2

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Barium Stripping (Model)

0

10

20

30

40

50

60

70

80

90

0 20 40 60 80 100

% seawater

ba

riu

m c

on

ce

ntr

atio

n (

pp

m)

Field A - actual

Field A - dilution line

Field A - modelled

EXAMPLE 2

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Barium Stripping (Field G)

a) water saturation b) mixing zone

c) BaSO4

deposition (lb/ft3)

SPE 80252

Field G (model)

EXAMPLE 2b

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0

50

100

150

200

250

0 500 1000 1500 2000 2500

time (days)

ba

riu

m c

on

ce

ntr

ati

on

(p

pm

)

0

500

1000

1500

2000

2500

3000

su

lph

ate

c

on

ce

ntr

ati

on

(p

pm

)

Ba

Ba (no precip)

SO4

SO4 (no precip)

[Ba] at well when no

reactions in reservoir

[Ba] at well when

reactions in reservoir

Field G (model)

EXAMPLE 2b

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0

50

100

150

200

250

0 20 40 60 80 100

% seawater

ba

riu

m c

on

ce

ntr

atio

n (

pp

m)

Field B - observed

Filed B - dilution line

Field B - modelled

deep reservoir + well/near

well mixing

deep reservoir mixing

0

50

100

150

200

250

0 20 40 60 80 100

% seawater

ba

riu

m c

on

ce

ntr

atio

n (

pp

m)

Field B - observed

Filed B - dilution line

Field B - modelled


well mixing


well mixing

deep reservoir mixingdeep reservoir mixing

Field G (model & field data)

EXAMPLE 2b

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Sulphate Stripping (Theory)

Seawater (with high Mg/Ca ratio) mixes with

formation water (with high Mg/Ca ratio)

leading to Mg and Ca exchange with rock to

re-equilibrate

Increase in Ca in seawater leads to CaSO4

precipitation in hotter zones in reservoir

Minimal impact on permeability in the

reservoir

Reduces BaSO4 scaling tendency at

production wells

SPE 100516 EXAMPLE 3

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Ion Exchange

Ca

Mg

Ca

Mg

C

C 0.50

C

C

FW: 0.077

SW: 3.2

Rock: 0.038

CCa Ca in solution

CMg Mg in solution

ĈCa Ca on rock

ĈMg Mg on rock

Gyda FW (mg/l)

30,185

2,325

SW (mg/l)

426

1,368

EXAMPLE 3

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Ba2+

Rock

SO42- Ca2+ Mg2+

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

FW

(hot)

EXAMPLE 3

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Ba2+ SO42- Ca2+ Mg2+

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

Rock

CW SW

(cold) (hot)

EXAMPLE 3

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

Rock

CW SW

(cold) (hot)

EXAMPLE 3

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

Rock

CW SW

(cold) (hot)

CaSO4

EXAMPLE 3

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Modelling: Ion Exchange

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

0 20 40 60 80 100


[Ca]

(mg

/l)

0

500

1,000

1,500

2,000

2,500

3,000

3,500

[Mg

] (m

g/l

)

Ca

Ca (mixing)

Mg

Mg (mixing)

As for field data:

•Large reduction

in [Mg]

•No apparent

change in [Ca]

EXAMPLE 3

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Modelling: Sulphate Stripping

0

100

200

300

400

500

600

700

800

900

0 20 40 60 80 100


[Ba

] (m

g/l

)

0

500

1000

1500

2000

2500

3000

[SO

4]

(mg

/l)

Ba

Ba (mixing)

SO4

SO4 (mixing)

As for field data:

•Small reduction

in [Ba]

•Large reduction

in [SO4]

(No SO4 at

< 40% SW)

EXAMPLE 3

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Impact of Reservoir Pressures on

Placement

Question for new subsea field under

development:

Can adequate placement be achieved

without using expensive rig

operations?

EXAMPLE 4

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Placement (Field D)

-200

-100

0

100

200

300

400

500

0 200 400 600 800

well length (m)

flo

w r

ate

(m

3/d

)

prior to squeeze

shut-in

INJ 1 bbl/m

INJ 5 bbl/m

INJ 10 bbl/m

1 year after squeeze

production

injection

(squeeze)

• Good placement along length of well during treatment (> 5 bbls/min)

• Can squeeze this well

SPE 87459 EXAMPLE 4

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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)

flo

w r

ate

(m

3/d

)

prior to squeeze

shut-in

INJ 1 bbl/m

INJ 5 bbl/m

INJ 10 bbl/m

1 year after squeeze

SPE 87459 EXAMPLE 4

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3) Conclusions

Modelling tools may assist with understanding of where scale is forming and what is best scale management option… identify location and impact of mixing

evaluate feasibility of squeeze option (placement)

calculate chemical requirements

… thus providing input for economic model.

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

But – must be aware of uncertainties….. reservoir description

numerical errors

changes to production schedule, etc.

… so monitoring essential.

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Acknowledgements

Sponsors of Flow Assurance and Scale

Team (FAST) at Heriot-Watt University:

Baker Petrolite, BG Group, BWA Water

Additives, BP, Champion Technologies,

Chevron, Clariant, ConocoPhillips,

Halliburton, M I Production Chemicals,

Nalco, Hydro Oil & Energy, Petrobras,

REP, Rhodia, Shell, Solutia, Statoil, Total

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