Formation,Removal,And Inhibition of Inorganic Scale in the Oilfield Enviroment
Oilfield Scale
Transcript of Oilfield Scale
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]
Slide 3 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)
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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)
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1a) Definition of ScaleScale 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 CausedScale deposits
formation damage (near wellbore)blockages in perforations or gravel packrestrict/block flow linessafety valve & choke failurepump wearcorrosion underneath depositssome scales are radioactive (NORM)
Suspended particlesplug formation & filtration equipmentreduce oil/water separator efficiency
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Examples - Formation Damage
quartz grainsquartz grains
scale crystals block scale crystals block pore throatspore throats
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Examples - Flow Restrictions
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Examples - Facilities
separator scaled up
and aftercleaning
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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
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1d) Mechanisms of Scale Formation
Carbonate scales precipitate due to ΔP (and/or ΔT)wellbore & production facilities
Sulphate scales form due to mixing of incompatible brinesinjected (SO4) & formation (Ba, Sr and/or Ca)near wellbore area, wellbore & production facilities
Concentration of salts due to dehydrationwellbore & 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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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)
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2a) The New Challenges
Deepwater and other harsh environmentsLow temperature and high pressureLong residence timesAccess to well difficultCompatibility with other production chemicals
Inhibitor placementComplex wells (eg deviated, multiple pay zones)
Well value & scale management costs
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Access to Well
Subsea wellsdifficult to monitor brine chemistrydeferred oil during squeezeswell interventions expensive (rig hire)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 frictionpressure zones(layers / fault blocks)damaged zones
Options:Bullheadbullhead + divertorCoiled Tubing from rigInhibitor in proppant / gravel pack / rat hole
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 millioneach to install
good for inhibitor placement controlsusceptible to scale damage
Rig hire for treatments US$100-400 thousand / daynecessary if using CTdeepwater may require 1-2 weeks / treatmentcf. 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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(BW
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Number of SRP per Year and Total Capacity
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2b) Proactive Rather Than ReactiveScale Management
Scale management considered during CAPEX Absolute must:
good quality brine samples and analysisPredict
water production history and profiles well by wellbrine chemistry evolution during well life cycleimpact of reservoir interactions on brine chemistryability 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)
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)
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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)
% injection water
Bar
ium
(mg/
l)
Dilution line
SPE 60193EXAMPLE 2
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Barium Stripping (Theory)
Injection water (containing SO4) mixes with formation water (containing Ba) leading to BaSO4 precipitation in the reservoirMinimal impact on permeability in the reservoirReduces BaSO4 scaling tendency at production wells
SPE 94052EXAMPLE 2
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Barium Stripping (Theory)
Ba2+
Rock
SO42-
1) Formation water (FW): [Ba2+] but negligible [SO42-]
FW
(hot)
EXAMPLE 2
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Barium Stripping (Theory)
Ba2+ SO42-
2) Waterflood: SO42- rich injection water
displaces Ba2+ rich FW
Rock
FWIW
(cold) (hot)
EXAMPLE 2
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Barium Stripping (Theory)
Ba2+ SO42-
Rock
3) Reaction: In mixing zone Ba2+ + SO42- → BaSO4
FWIW
(cold) (hot)
BaSO4
EXAMPLE 2
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Barium Stripping (Theory)
0
100
200
300
400
500
600
700
800
900
0 20 40 60 80 100seawater fraction (%)
[Ba]
(mg/
l)
0
500
1000
1500
2000
2500
3000
[SO
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
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Barium Stripping (Model & Field Data)
0
10
20
30
40
50
60
70
80
90
0 20 40 60 80 100% seawater
bariu
m c
once
ntra
tion
(ppm
)
Field A - actualField A - dilution lineField A - modelled
EXAMPLE 2
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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-equilibrateIncrease in Ca in Injection water leads to CaSO4 precipitation in hotter zones in reservoirMinimal impact on permeability in the reservoirReduces BaSO4 scaling tendency at production wells
SPE 100516EXAMPLE 3
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Ion Exchange
Ca
Mg
Ca
Mg
CC
0.50 CC
=FW: 0.077
IW: 3.2
Rock: 0.038
Mg on rockĈMg
Ca on rockĈCa
Mg in solutionCMg
Ca in solutionCCa
2,32530,185
Gyda FW (mg/l)
1,368426
IW (mg/l)
EXAMPLE 3
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Sulphate Stripping (Theory)
Ba2+
Rock
SO42- Ca2+ Mg2+
1) Formation water: [Ca2+] and [Mg2+] in equilibrium with rock
FW
(hot)
EXAMPLE 3
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Sulphate Stripping (Theory)
Ba2+ SO42- Ca2+ Mg2+
2) Waterflood: [Ca2+] and [Mg2+] no longer in equilibrium
Rock
FWIW
(cold) (hot)
EXAMPLE 3
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Sulphate Stripping (Theory)
Ba2+ SO42- Ca2+ Mg2+
3) Reaction 1: Ca2+ and Mg2+ ion exchange with rock
Rock
FWIW
(cold) (hot)
EXAMPLE 3
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Sulphate Stripping (Theory)
Ba2+ SO42- Ca2+ Mg2+
4) Reaction 2: In hotter zones Ca2+ + SO42- → CaSO4
Rock
FWIW
(cold) (hot)
CaSO4
EXAMPLE 3
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Modelling Prediction: [Ca] and [Mg]
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
0 20 40 60 80 100seawater fraction (%)
[Ca]
(mg/
l)
0
500
1,000
1,500
2,000
2,500
3,000
3,500
[Mg]
(mg/
l)
CaCa (mixing)MgMg (mixing)
•Large reduction in [Mg]
•No apparent change in [Ca]
EXAMPLE 3
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Observed Field Data: [Ca] and [Mg]
•Large reduction in [Mg]
•No apparent change in [Ca]
EXAMPLE 3
0
5000
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15000
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0 20 40 60 80 100
seawater fraction (%)
[Ca]
(mg/
l)
0
1000
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[Mg]
(mg/
l)
CaCa (mixing)MglMg (mixing)
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Modelling Prediction: [Ba] and [SO4]
0
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0 20 40 60 80 100seawater fraction (%)
[Ba]
(mg/
l)
0
500
1000
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2000
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3000
[SO
4] (m
g/l)
BaBa (mixing)SO4SO4 (mixing)
EXAMPLE 3
•Small reduction in [Ba]
•Large reduction in [SO4](No SO4 at < 40% SW)
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Observed Field Data: [Ba] and [SO4]
•Small reduction in [Ba]
•Large reduction in [SO4](No SO4 at < 40% SW)
EXAMPLE 3
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0 20 40 60 80 100
seawater fraction (%)
[Ba]
(mg/
l)
0
500
1000
1500
2000
2500
3000
[SO
4] (m
g/l)
BaBa (mixing)SO4lSO4 (mixing)
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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 scalingevaluate 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…..reservoir descriptionnumerical errorschanges to production schedule, etc.
… so monitoring essential.
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Acknowledgements
Sponsors of Flow Assurance and Scale Team (FAST) at Heriot-Watt University:
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Extra Slides
Barium stripping example (Field G)Placement example (Field X)
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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 G
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Barium Stripping (Field G)
0
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0 500 1000 1500 2000 2500
time (days)
bariu
m c
once
ntra
tion
(ppm
)
0
500
1000
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2000
2500
3000
sulp
hate
con
cent
ratio
n (p
pm)
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
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Barium Stripping (Field G)
0
50
100
150
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250
0 20 40 60 80 100
% seawater
bariu
m c
once
ntra
tion
(ppm
Field B - observedFiled B - dilution lineField B - modelled
deep reservoir + well/near well mixing
deep reservoir mixing
0
50
100
150
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250
0 20 40 60 80 100
% seawater
bariu
m c
once
ntra
tion
(ppm
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
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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 X
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Placement (Field D)
-200
-100
0
100
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300
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500
0 200 400 600 800
well length (m)
flow
rate
(m3/
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
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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)
flow
rate
(m3/
d) prior to squeezeshut-inINJ 1 bbl/mINJ 5 bbl/mINJ 10 bbl/m1 year after squeeze
SPE 87459EXAMPLE X