SO
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 Flow Assurance and Scale Team (FAST) Institute of Petroleum Engineering Heriot-Watt University Edinburgh, Scotland [email protected] Society of Petroleum Engineers Distinguished Lecturer 2007-08 Lecture Season
Outline 1) The Old Foe a) b) c) d)
Formation Definition of scale Water (Ba) Problems caused Common oilfield scales Mechanisms of scale formation
2) The New Approach
Injection Water (SO4) •• •• • • •••• •
Ba2+ + SO42- Æ BaSO4(s)
a) The new challenges b) Proactive rather than reactive scale management c) Effect of reservoir processes
3) Conclusions Slide 3 of 39
Outline 1) The Old Foe a) b) c) d)
Formation Definition of scale Water (Ba) Problems caused Common oilfield scales Mechanisms of scale formation
2) The New Approach
Injection Water (SO4) •• •• • • •••• •
Ba2+ + SO42- Æ BaSO4(s)
a) The new challenges b) Proactive rather than reactive scale management c) Effect of reservoir processes
3) Conclusions Slide 4 of 39
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.) Slide 5 of 39
1b) Problems Caused
Scale deposits z z z z z z z
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 z z
plug formation & filtration equipment reduce oil/water separator efficiency
Slide 6 of 39
Examples - Formation Damage scale crystals block pore throats
quartz grains Slide 7 of 39
Examples - Flow Restrictions
Slide 8 of 39
Examples - Facilities separator scaled up
and after cleaning
Slide 9 of 39
SPE 87459
1c) Common Oilfield Scales Name
Formula
Specific Gravity
Solubility cold water
other
(mg/l) Common Scales barium sulphate
BaSO4
4.50
2.2
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)
SiO2
2.65
insoluble
HF soluble
60 mg/l in 3% HCl
Sand Grains silicon dioxide
Some Other Scales Iron Scales:
Fe2O3, FeS, FeCO3
Exotic Scales:
ZnS, PbS Slide 10 of 39
1d) Mechanisms of Scale Formation
Carbonate scales precipitate due to ∆P (and/or ∆T) z
wellbore & production facilities
Ca2+(aq) + 2HCO-3(aq) = CaCO3(s) + CO2(aq) + H2O(l)
Sulphate scales form due to mixing of incompatible brines z z
injected (SO4) & formation (Ba, Sr and/or Ca) near wellbore area, wellbore & production facilities
Ba2+(aq) (Sr2+or Ca2+) + SO42-(aq) = BaSO4(s) (SrSO4 or CaSO4)
Concentration of salts due to dehydration z
wellbore & production facilities
Slide 11 of 39
Outline 1) The Old Foe a) b) c) d)
Formation Definition of scale Water (Ba) Problems caused Common oilfield scales Mechanisms of scale formation
2) The New Approach
Injection Water (SO4) •• •• • • •••• •
Ba2+ + SO42- Æ BaSO4(s)
a) The new challenges b) Proactive rather than reactive scale management c) Effect of reservoir processes
3) Conclusions Slide 12 of 39
2a) The New Challenges
Deepwater and other harsh environments z z z z
Inhibitor placement z
Low temperature and high pressure Long residence times Access to well difficult Compatibility with other production chemicals
Complex wells (eg deviated, multiple pay zones)
Well value & scale management costs
Slide 13 of 39
Access to Well
Subsea wells z
z
z
z
difficult to monitor brine chemistry deferred oil during squeezes well interventions expensive (rig hire) squeeze campaigns and/or pre-emptive squeezes Slide 14 of 39
Inhibitor Placement in Complex Wells
Where is scaling brine being produced? Can we get inhibitor where needed? z z
z
Ptubing head
wellbore friction pressure zones (layers / fault blocks) damaged zones
Pcomp 1 Presv 1 Shale
Options: z z z z
Bullhead bullhead + divertor Coiled Tubing from rig Inhibitor in proppant / gravel pack / rat hole
Fault
Pcomp N
Presv N
Slide 15 of 39
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 z z
Rig hire for treatments US$100-400 thousand / day z z z
good for inhibitor placement control susceptible to scale damage
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 Slide 16 of 39
2b) Proactive Rather Than Reactive Scale Management
Scale management considered during CAPEX Absolute must: good quality brine samples and analysis Predict z z z z
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 Slide 17 of 39
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)
Slide 18 of 39
EXAMPLE 1
SPE 80252
Extended Brine Mixing at Producers
Slide 19 of 39
EXAMPLE 1
SPE 80252
Extended Brine Mixing at Producers
This well has been treated > 220 times!
Field M (streamline model) Slide 20 of 39
EXAMPLE 2
SPE 60193
Barium (mg/l)
Barium Stripping (Field A)
Dilution line
% injection water
Slide 21 of 39
EXAMPLE 2
SPE 94052
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
Slide 22 of 39
EXAMPLE 2
Barium Stripping (Theory) Ba2+ (hot)
SO42Rock
FW 1) Formation water (FW): [Ba2+] but negligible [SO42-] Slide 23 of 39
EXAMPLE 2
Barium Stripping (Theory) Ba2+ (cold)
SO42(hot)
IW 2) Waterflood: SO42- rich injection water displaces Ba2+ rich FW
Rock
FW
Slide 24 of 39
EXAMPLE 2
Barium Stripping (Theory) Ba2+ (cold)
IW
SO42-
BaSO4 (hot)
Rock
FW
3) Reaction: In mixing zone Ba2+ + SO42- → BaSO4 Slide 25 of 39
EXAMPLE 2
Barium Stripping (Theory) 3000
900
Ba Ba (mixing) SO4 SO4 (mixing)
800 2500 2000
[Ba] (mg/l)
600 500
1500 400 1000
300 200
500 100 0 0
20
40
60
seawater fraction (%)
80
0 100
[SO4] (mg/l)
700
•Large reduction in [Ba] •Small reduction in [SO4] (SO4 in excess) •Typical behaviour observed in many fields Slide 26 of 39
EXAMPLE 2
Barium Stripping (Model & Field Data) 90 Field A - actual Field A - dilution line Field A - modelled
barium concentration (ppm)
80 70 60 50 40 30 20 10 0 0
20
40
60
% seawater
80
100 Slide 27 of 39
EXAMPLE 3
SPE 100516
Sulphate Stripping (Theory)
Injection water (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 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 Slide 28 of 39
EXAMPLE 3
Ion Exchange Rock: 0.038
ˆ C Mg C Mg = 0.50 ˆ C Ca C Ca
Gyda FW (mg/l)
FW: 0.077
IW: 3.2 IW (mg/l)
CCa
Ca in solution
30,185
426
CMg
Mg in solution
2,325
1,368
ĈCa
Ca on rock
ĈMg
Mg on rock
Slide 29 of 39
EXAMPLE 3
Sulphate Stripping (Theory) Ba2+ (hot)
SO42-
Ca2+
Mg2+ Rock
FW 1) Formation water: [Ca2+] and [Mg2+] in equilibrium with rock Slide 30 of 39
EXAMPLE 3
Sulphate Stripping (Theory) Ba2+ (cold)
IW
SO42-
Ca2+ (hot)
Mg2+ Rock
FW
2) Waterflood: [Ca2+] and [Mg2+] no longer in equilibrium Slide 31 of 39
EXAMPLE 3
Sulphate Stripping (Theory) Ba2+ (cold)
IW
SO42-
Ca2+ (hot)
Mg2+ Rock
FW
3) Reaction 1: Ca2+ and Mg2+ ion exchange with rock Slide 32 of 39
EXAMPLE 3
Sulphate Stripping (Theory) Ba2+ (cold)
IW
SO42-
Ca2+ (hot)
Mg2+
CaSO4 Rock
FW
4) Reaction 2: In hotter zones Ca2+ + SO42- → CaSO4 Slide 33 of 39
EXAMPLE 3
35,000
3,500
30,000
3,000
25,000
2,500
20,000
2,000
15,000
1,500
10,000
1,000
5,000
500
0 0
20
40
60
seawater fraction (%)
80
Ca Ca (mixing) Mg Mg (mixing) [Mg] (mg/l)
[Ca] (mg/l)
Modelling Prediction: [Ca] and [Mg]
•Large reduction in [Mg] •No apparent change in [Ca]
0 100 Slide 34 of 39
EXAMPLE 3
40000
8000
35000
7000
30000
6000
25000
5000
20000
4000
15000
3000
10000
2000
5000
1000
0
0 0
20
40
60
80
100
Ca Ca (mixing) Mgl Mg (mixing) [Mg] (mg/l)
[Ca] (mg/l)
Observed Field Data: [Ca] and [Mg]
•Large reduction in [Mg] •No apparent change in [Ca]
seawater fraction (%) Slide 35 of 39
EXAMPLE 3
Modelling Prediction: [Ba] and [SO4] 900
3000 Ba Ba (mixing) SO4 SO4 (mixing)
800 2500 2000
[Ba] (mg/l)
600 500
1500 400 300
1000
200 500 100 0 0
20
40
60
seawater fraction (%)
80
0 100
[SO4] (mg/l)
700
•Small reduction in [Ba] •Large reduction in [SO4] (No SO4 at < 40% SW) Slide 36 of 39
EXAMPLE 3
300
3000
250
2500
200
2000
150
1500
100
1000
50
500
0
0 0
20
40
60
seawater fraction (%)
80
100
Ba Ba (mixing) SO4l SO4 (mixing) [SO4] (mg/l)
[Ba] (mg/l)
Observed Field Data: [Ba] and [SO4]
•Small reduction in [Ba] •Large reduction in [SO4] (No SO4 at < 40% SW) Slide 37 of 39
3) Conclusions
Modelling tools may assist with understanding of where scale is forming and what is best scale management option… z z
identify location and impact of scaling 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 z z
reservoir description numerical errors changes to production schedule, etc.
… so monitoring essential. Slide 38 of 39
Acknowledgements
Sponsors of Flow Assurance and Scale Team (FAST) at Heriot-Watt University: Baker Petrolite, BWA Water Additives, BP, Champion Technologies, Chevron, Clariant, ConocoPhillips, Halliburton, M I Production Chemicals, Nalco, Petrobras, Petronas, REP, Rhodia, Saudi Aramco, Shell, StatoilHydro and Total
Slide 39 of 39
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 Flow Assurance and Scale Team (FAST) Institute of Petroleum Engineering Heriot-Watt University Edinburgh, Scotland [email protected] Society of Petroleum Engineers Distinguished Lecturer 2007-08 Lecture Season
Outline 1) The Old Foe a) b) c) d)
Formation Definition of scale Water (Ba) Problems caused Common oilfield scales Mechanisms of scale formation
2) The New Approach
Injection Water (SO4) •• •• • • •••• •
Ba2+ + SO42- Æ BaSO4(s)
a) The new challenges b) Proactive rather than reactive scale management c) Effect of reservoir processes
3) Conclusions Slide 3 of 39
Outline 1) The Old Foe a) b) c) d)
Formation Definition of scale Water (Ba) Problems caused Common oilfield scales Mechanisms of scale formation
2) The New Approach
Injection Water (SO4) •• •• • • •••• •
Ba2+ + SO42- Æ BaSO4(s)
a) The new challenges b) Proactive rather than reactive scale management c) Effect of reservoir processes
3) Conclusions Slide 4 of 39
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.) Slide 5 of 39
1b) Problems Caused
Scale deposits z z z z z z z
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 z z
plug formation & filtration equipment reduce oil/water separator efficiency
Slide 6 of 39
Examples - Formation Damage scale crystals block pore throats
quartz grains Slide 7 of 39
Examples - Flow Restrictions
Slide 8 of 39
Examples - Facilities separator scaled up
and after cleaning
Slide 9 of 39
SPE 87459
1c) Common Oilfield Scales Name
Formula
Specific Gravity
Solubility cold water
other
(mg/l) Common Scales barium sulphate
BaSO4
4.50
2.2
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)
SiO2
2.65
insoluble
HF soluble
60 mg/l in 3% HCl
Sand Grains silicon dioxide
Some Other Scales Iron Scales:
Fe2O3, FeS, FeCO3
Exotic Scales:
ZnS, PbS Slide 10 of 39
1d) Mechanisms of Scale Formation
Carbonate scales precipitate due to ∆P (and/or ∆T) z
wellbore & production facilities
Ca2+(aq) + 2HCO-3(aq) = CaCO3(s) + CO2(aq) + H2O(l)
Sulphate scales form due to mixing of incompatible brines z z
injected (SO4) & formation (Ba, Sr and/or Ca) near wellbore area, wellbore & production facilities
Ba2+(aq) (Sr2+or Ca2+) + SO42-(aq) = BaSO4(s) (SrSO4 or CaSO4)
Concentration of salts due to dehydration z
wellbore & production facilities
Slide 11 of 39
Outline 1) The Old Foe a) b) c) d)
Formation Definition of scale Water (Ba) Problems caused Common oilfield scales Mechanisms of scale formation
2) The New Approach
Injection Water (SO4) •• •• • • •••• •
Ba2+ + SO42- Æ BaSO4(s)
a) The new challenges b) Proactive rather than reactive scale management c) Effect of reservoir processes
3) Conclusions Slide 12 of 39
2a) The New Challenges
Deepwater and other harsh environments z z z z
Inhibitor placement z
Low temperature and high pressure Long residence times Access to well difficult Compatibility with other production chemicals
Complex wells (eg deviated, multiple pay zones)
Well value & scale management costs
Slide 13 of 39
Access to Well
Subsea wells z
z
z
z
difficult to monitor brine chemistry deferred oil during squeezes well interventions expensive (rig hire) squeeze campaigns and/or pre-emptive squeezes Slide 14 of 39
Inhibitor Placement in Complex Wells
Where is scaling brine being produced? Can we get inhibitor where needed? z z
z
Ptubing head
wellbore friction pressure zones (layers / fault blocks) damaged zones
Pcomp 1 Presv 1 Shale
Options: z z z z
Bullhead bullhead + divertor Coiled Tubing from rig Inhibitor in proppant / gravel pack / rat hole
Fault
Pcomp N
Presv N
Slide 15 of 39
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 z z
Rig hire for treatments US$100-400 thousand / day z z z
good for inhibitor placement control susceptible to scale damage
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 Slide 16 of 39
2b) Proactive Rather Than Reactive Scale Management
Scale management considered during CAPEX Absolute must: good quality brine samples and analysis Predict z z z z
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 Slide 17 of 39
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)
Slide 18 of 39
EXAMPLE 1
SPE 80252
Extended Brine Mixing at Producers
Slide 19 of 39
EXAMPLE 1
SPE 80252
Extended Brine Mixing at Producers
This well has been treated > 220 times!
Field M (streamline model) Slide 20 of 39
EXAMPLE 2
SPE 60193
Barium (mg/l)
Barium Stripping (Field A)
Dilution line
% injection water
Slide 21 of 39
EXAMPLE 2
SPE 94052
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
Slide 22 of 39
EXAMPLE 2
Barium Stripping (Theory) Ba2+ (hot)
SO42Rock
FW 1) Formation water (FW): [Ba2+] but negligible [SO42-] Slide 23 of 39
EXAMPLE 2
Barium Stripping (Theory) Ba2+ (cold)
SO42(hot)
IW 2) Waterflood: SO42- rich injection water displaces Ba2+ rich FW
Rock
FW
Slide 24 of 39
EXAMPLE 2
Barium Stripping (Theory) Ba2+ (cold)
IW
SO42-
BaSO4 (hot)
Rock
FW
3) Reaction: In mixing zone Ba2+ + SO42- → BaSO4 Slide 25 of 39
EXAMPLE 2
Barium Stripping (Theory) 3000
900
Ba Ba (mixing) SO4 SO4 (mixing)
800 2500 2000
[Ba] (mg/l)
600 500
1500 400 1000
300 200
500 100 0 0
20
40
60
seawater fraction (%)
80
0 100
[SO4] (mg/l)
700
•Large reduction in [Ba] •Small reduction in [SO4] (SO4 in excess) •Typical behaviour observed in many fields Slide 26 of 39
EXAMPLE 2
Barium Stripping (Model & Field Data) 90 Field A - actual Field A - dilution line Field A - modelled
barium concentration (ppm)
80 70 60 50 40 30 20 10 0 0
20
40
60
% seawater
80
100 Slide 27 of 39
EXAMPLE 3
SPE 100516
Sulphate Stripping (Theory)
Injection water (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 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 Slide 28 of 39
EXAMPLE 3
Ion Exchange Rock: 0.038
ˆ C Mg C Mg = 0.50 ˆ C Ca C Ca
Gyda FW (mg/l)
FW: 0.077
IW: 3.2 IW (mg/l)
CCa
Ca in solution
30,185
426
CMg
Mg in solution
2,325
1,368
ĈCa
Ca on rock
ĈMg
Mg on rock
Slide 29 of 39
EXAMPLE 3
Sulphate Stripping (Theory) Ba2+ (hot)
SO42-
Ca2+
Mg2+ Rock
FW 1) Formation water: [Ca2+] and [Mg2+] in equilibrium with rock Slide 30 of 39
EXAMPLE 3
Sulphate Stripping (Theory) Ba2+ (cold)
IW
SO42-
Ca2+ (hot)
Mg2+ Rock
FW
2) Waterflood: [Ca2+] and [Mg2+] no longer in equilibrium Slide 31 of 39
EXAMPLE 3
Sulphate Stripping (Theory) Ba2+ (cold)
IW
SO42-
Ca2+ (hot)
Mg2+ Rock
FW
3) Reaction 1: Ca2+ and Mg2+ ion exchange with rock Slide 32 of 39
EXAMPLE 3
Sulphate Stripping (Theory) Ba2+ (cold)
IW
SO42-
Ca2+ (hot)
Mg2+
CaSO4 Rock
FW
4) Reaction 2: In hotter zones Ca2+ + SO42- → CaSO4 Slide 33 of 39
EXAMPLE 3
35,000
3,500
30,000
3,000
25,000
2,500
20,000
2,000
15,000
1,500
10,000
1,000
5,000
500
0 0
20
40
60
seawater fraction (%)
80
Ca Ca (mixing) Mg Mg (mixing) [Mg] (mg/l)
[Ca] (mg/l)
Modelling Prediction: [Ca] and [Mg]
•Large reduction in [Mg] •No apparent change in [Ca]
0 100 Slide 34 of 39
EXAMPLE 3
40000
8000
35000
7000
30000
6000
25000
5000
20000
4000
15000
3000
10000
2000
5000
1000
0
0 0
20
40
60
80
100
Ca Ca (mixing) Mgl Mg (mixing) [Mg] (mg/l)
[Ca] (mg/l)
Observed Field Data: [Ca] and [Mg]
•Large reduction in [Mg] •No apparent change in [Ca]
seawater fraction (%) Slide 35 of 39
EXAMPLE 3
Modelling Prediction: [Ba] and [SO4] 900
3000 Ba Ba (mixing) SO4 SO4 (mixing)
800 2500 2000
[Ba] (mg/l)
600 500
1500 400 300
1000
200 500 100 0 0
20
40
60
seawater fraction (%)
80
0 100
[SO4] (mg/l)
700
•Small reduction in [Ba] •Large reduction in [SO4] (No SO4 at < 40% SW) Slide 36 of 39
EXAMPLE 3
300
3000
250
2500
200
2000
150
1500
100
1000
50
500
0
0 0
20
40
60
seawater fraction (%)
80
100
Ba Ba (mixing) SO4l SO4 (mixing) [SO4] (mg/l)
[Ba] (mg/l)
Observed Field Data: [Ba] and [SO4]
•Small reduction in [Ba] •Large reduction in [SO4] (No SO4 at < 40% SW) Slide 37 of 39
3) Conclusions
Modelling tools may assist with understanding of where scale is forming and what is best scale management option… z z
identify location and impact of scaling 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 z z
reservoir description numerical errors changes to production schedule, etc.
… so monitoring essential. Slide 38 of 39
Acknowledgements
Sponsors of Flow Assurance and Scale Team (FAST) at Heriot-Watt University: Baker Petrolite, BWA Water Additives, BP, Champion Technologies, Chevron, Clariant, ConocoPhillips, Halliburton, M I Production Chemicals, Nalco, Petrobras, Petronas, REP, Rhodia, Saudi Aramco, Shell, StatoilHydro and Total
Slide 39 of 39
