Transcript Low salinity Experimental challenges - Start

Low salinity water flooding
Experimental experience and challenges
Force workshop
Ingebret Fjelde
Outline
• Questions
• Experiences
• Challenges
• Concluding remarks
Low salinity Force 15 May 2008 IF 2
Questions
• Are the mechanisms in low salinity water flooding understood?
• Can low salinity water flooding be used in all sandstone fields?
– If not, when can it be used?
• Will low salinity water flooding improve the oil recovery in all
sandstone reservoirs?
• Can oil recovery be estimated by existing reservoir simulators?
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Low salinity water flooding can not be
understood by classic EOR
• No miscible process
• No reduction in IFT
• Mobility control?
k
m

M  D  ( rw )  ( o )
d
m w k ro
– Favorable mobility control if M<1
• Reducing krw or mo
• Increasing kro or mw
– Non of these seems to be dominating
• When all other explanations have failed put the blame on wettability
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Literature
• Reported to improve oil recovery in sandstones
– Core experiments and reservoirs
• Reported to depend on, e.g.
– Multicomponent ion exchange important
– Clay content (sometimes fines produced)
– Composition formation water (Ca2+, Mg2+)
– Oil composition (crude oil, no effect with white oils)
– Initial water saturation required
– pH increase (≈ alkaline flood, but no correlation with AN)
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Tulsa SPEIOR 2008
• SPE 113480, Endicott field
– Improved oil recovery shown in core floods and single well tracer test
– Kaoline content important
• SPE 113976
– Mechanisms
• Multiple-component ionic exchange (MIE) between adsorbed crude oil
components, cations in the in situ brine and clay mineral surfaces
– Single well tracer test Alaskian reservoir
• High salinity water and produced water Sor=0.300.02
• Non optimised low salinity brine Sor=0.280.02
• Optimised low salinity brine Sor=0.200.02
– Composition of optimised brine not given
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Irreversible?
• SCA2006-36
– Re-aged cores higher oil recovery at high salinity, but no oil
production in tertiary low salinity water flooding
• Not likely due to multiple-component ionic exchange
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Spontaneous imbibition limestone
Formation water vs low salinity water
0.50
0.45
0.40
Oil recovery
0.35
0.30
Formation water 1
Formation water 2
Low salinity 1
Low salinity 2
0.25
0.20
0.15
0.10
0.05
0.00
0
5
10
15
20
25
Time [days]
Low salinity water can also increase oil recovery in limestone
Probably not only clastic clays that are important for low salinity water
flooding of sandstone
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Adsorption surface active components onto surfaces
• Adsorption
– Surface charge
• pH, salinity and brine composition
– Adsorption density depends on salinity and brine composition
• Desorption
– Depend on the same parameters as adsorption
– By decreasing salinity adsorption density decreases
– Change of brine composition can also change surface charge
• Electrical double-layer expands with decreasing brine salinity
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Adsorption of acidic crude oil components
onto chalk
2,5
6
2,0
5
4
1,5
3
1,0
2
0,5
1
0,0
0
0,0
0,5
1,0
1,5
PV
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2,0
2,5
3,0
Oil volume [ml]
AN [mg KOH/ g]
Acid number in effluent during injection of crude oil to chalk
AN
AN injected crude oil
Oil production
Surfactant adsorption
Decreases with decreasing salinity
• Adsorption equilibrium
• Usually reversible
• Reduction of salinity will give desorption
• Similar expected for surface active
components in crude oils
• Asphaltenes may be an exception
Somasundaran, P. and Hanna, H.S., ”Physico-chemical aspects of adsorption at solid/liquid interfaces,”
in Improved Oil Recovery by Surfactant and Polymer flooding, ed. D.O. Shah and R.S. Schechter,
Academic Press, New York, 1977, pp. 2005-74
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Drilling fluids
• Water in drilling fluids can give swelling of clay and shale and
reduction of permeability
• Solved by using inhibitive drilling fluids
– Water based drilling fluid with high salinity
– Emulsified mud with high salt concentrations
Swelling clay: Bulk study
Volume change [%]
Kaolinite
Na-Montmorillonite
Low salinity water flood may not
be carried out in all oil reservoirs
150
130
110
90
70
50
30
10
-10
-30
-50
Base oil
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Brine 1
Brine 2
Oil based mud
filtrate
Mechanisms
Alteration of flow saturation functions
• Description of mechanisms required
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Challenge Time effects
• Analyses of effluents necessary to confirm that adsorption equilibrium has been
established
– Preparation of initial state at high salinity
– Preparation of final state at low salinity
– Studies of mechanisms
• Time effects can be important in the laboratory, but not in the fields
– But laboratory results will be used as inputs to simulators for estimations of oil
recovery potential
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Time effects 1
• Adsorption can be slow
• Oil components
• Aging of core plugs
• Chemicals
• Surfactants
• Polymers
I.Fjelde, T. Austad and J. Milter, ”Adsorption VII. Dynamic
adsorption of a dual surfactant system onto reservoir cores
at sea water salinity,” J. Petr. Science & Eng., 13 (1995),
1993-201.
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Time effects 2
Desorption surface active components can be slow
•
Interfacial tensions (IFT) between effluent samples and formation water during
back-production of mud filtrate with crude oil
– Fjelde, I., “Slow retention and release processes during drilling with emulsified
drilling fluids,” 18th International Oil Field Chemicals Symposium, Geilo,
Norway, 25-28 March 2007.
18
IFT (crude oil – brine) ≈ 30 mN/m
16
IFT [mN/m]
14
Mud filtrates
12
10
MFM
8
MFS
6
4
2
0
0
2
4
Light STO injected [PV]
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6
8
Challenge Crude oils
• Complex mixtures of surface active oil components
– Many types of surface active components
– Different crude oils different types and concentrations
– Interactions between crude oil components
• Interaction between resins and asphaltenes important for
asphaltene solubility / dispersion
• Simplified systems may not give good enough description
• Concentrations of surface active oil components and their solvency
different in stock tank oil and live oil
• Some oil components soluble in water
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Challenge Crude oils cont.
• Mixing of crude oils with low aromatic synthetic oil
– Will reduce concentrations of surface active oil components
– Can reduce solvency of some of the surface active components,
e.g. will increase aggregation of asphaltene molecules in oil
phase and on surfaces
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Challenge Crude oils / Oxidation
• Oxidation of crude oil will increase concentrations of acidic components
– Oxidation products can have other properties than original polar
components
• Oxidation products can be less soluble, e.g. oxidation asphaltenes
– Important to compare concentration of surface active components in
used crude oil vs in original reservoir oil
• Isolation of polar components from crude oil especially critical
– After short term storage, often difficult to dissolve all of the polar
components because of oxidation
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Challenge Correct sampling in laboratory
• Proposed mechanisms are known to depend on
– Conditions
• Temperature, pressure and pH
– Different properties can be affected, e.g.
• Solubility (ions and oil components)
• Interactions (ions, oil components and rock surfaces)
• Sampling should be carried out at test conditions
– Alternative, have to verify that sampling can be carried out at
other conditions, e.g. room temperature and 1 atm
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Challenge Reservoir conditions
• Reservoir conditions
– High temperature and high pressure
• Characterisation of mechanisms can be difficult at reservoir
conditions, e.g.
– Interactions between surfaces and oil components and ions
• Zeta potential
• Contact angles
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Challenge Potential estimates
Parametic study
Identify mechanisms
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Modelling
experiments
Simple but good
enough description
Preliminary studies in
simplified fluid and rock
systems, but final validation
at reservoir conditions
Extension
larger scale
Potential estimate
Behaviour larger
scale
Optimisation reservoir
process,
e.g. inj. strategy
Concluding remarks
• Low salinity water flooding an environmentally friendly EOR
method
• Open the route for alkaline flooding and alkaline/surfactant
flooding
• Need best practice for low salinity water flooding potential
evaluation
• Description of mechanisms and determination of recovery potential
should be confirmed using reservoir fluids and reservoir rocks at
reservoir conditions
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