SPE-DL slides EricMackayALL

SPE DISTINGUISHED LECTURER SERIES
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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
Eric.Mackay@pet.hw.ac.uk

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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+ + SO4
2-  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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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
Barium(mg/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
SO4
2-
1) Formation water (FW): [Ba2+] but negligible [SO4
2-]
FW
(hot)
EXAMPLE 2

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Ba2+
SO4
2-
2) Waterflood: SO4
2- rich seawater displaces Ba2+ rich FW
Rock
FWSW
(cold) (hot)
EXAMPLE 2

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Ba2+
SO4
2-
Rock
3) Reaction: In mixing zone Ba2+ + SO4
2- → BaSO4
FWSW
(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](mg/l)
0
500
1000
1500
2000
2500
3000
[SO4](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
bariumconcentration(ppm)
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)
0
500
1000
1500
2000
2500
3000
sulphateconcentration(ppm)
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
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
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
Cˆ
Cˆ

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
SO4
2- Ca2+ Mg2+
1) Formation water: [Ca2+] and [Mg2+] in equilibrium with rock
FW
(hot)
EXAMPLE 3

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Ba2+
SO4
2- Ca2+ Mg2+
2) Waterflood: [Ca2+] and [Mg2+] no longer in equilibrium
Rock
CWSW
(cold) (hot)
EXAMPLE 3

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Ba2+
SO4
2- Ca2+ Mg2+
3) Reaction 1: Ca2+ and Mg2+ ion exchange with rock
Rock
CWSW
(cold) (hot)
EXAMPLE 3

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Ba2+
SO4
2- Ca2+ Mg2+
4) Reaction 2: In hotter zones Ca2+ + SO4
2- → CaSO4
Rock
CWSW
(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](mg/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](mg/l)
0
500
1000
1500
2000
2500
3000
[SO4](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)
flowrate(m3/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)
flowrate(m3/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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