Abstract
Low salinity water injections for oil recovery have shown seemingly promising results in the case of clay-bearing sandstones saturated with asphaltic crude oil. Reported data showed that low salinity water injection could provide up to 20% pore volume (PV) of additional oil recovery for core samples and up to 25% PV for reservoirs in near wellbore regions, compared with brine injection at the same Darcy velocity. The question remains as to whether this additional recovery is also attainable in reservoirs. The answer requires a thorough understanding of oil recovery mechanism of low salinity water injections. Numerous hypotheses have been proposed to explain the increased oil recovery using low salinity water, including migration of detached mixed-wet clay particles with absorbed residual oil drops, wettability alteration toward increased water-wetness, and emulsion formation. However, many later reports showed that a higher oil recovery associated with low salinity water injection at the common laboratory flow velocity was neither necessarily accompanied by migration of clay particles, nor necessarily accompanied by emulsion. Moreover, increased water-wetness has been shown to cause the reduction of oil recovery. The present study is based on both experimental and theoretical analyses. Our study reveals that the increased oil recovery is only related to the reduction of water permeability due to physical plugging of the porous network by swelling clay aggregates or migrating clay particles and crystals. At a fixed apparent flow velocity, the value of negative pressure gradient along the flow path increases as the water permeability decreases. Some oil drops and blobs can be mobilized under the increased negative pressure gradient and contribute to the additional oil recovery. Based on the revealed mechanism, we conclude that low salinity water injection cannot be superior to brine injection in any clay-bearing sandstone reservoir at the maximum permitted injection pressure. Through our study of low salinity water injection, the theory of tertiary oil recovery has been notably improved.
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Abbreviations
- BR:
-
Brine injection
- BT:
-
Breakthrough
- Ca :
-
Dimensionless capillary number
- D c :
-
Core diameter (m)
- DW:
-
Distilled water injection
- EOR:
-
Enhanced oil recovery
- f′:
-
Derivative of water fractional flow with respect to water saturation (df/dS w)
- \({f'_{\rm f}}\) :
-
Derivative of water fractional flow with respect to water saturation at the water-invading front
- HF:
-
High flow rate injection
- K :
-
Absolute permeability (air permeability) (m2)
- K w :
-
Permeability of the water phase (m2)
- k rw :
-
Relative permeability to the water phase
- L :
-
Length of the bypass (m)
- L c :
-
Length of the core (m)
- LS:
-
Low salinity brine injection
- N c :
-
Standard capillary number (m−2)
- \({N_{\rm c}^{0}}\) :
-
Standard capillary number at the tertiary oil recovery of 7.3% PV for the core with θ R = 0 (m−2)
- P 1 :
-
Upstream pressure (Pa)
- P 2 :
-
Downstream pressure (Pa)
- P cb :
-
Back capillary pressure (Pa)
- P cf :
-
Frontal capillary pressure (Pa)
- P cP :
-
Capillary pressure generated by the interface in the pore (Pa)
- P cT :
-
Capillary pressure generated by the interface in the throat (Pa)
- PST/PPT:
-
Ratio of snap-off capillary pressure in a throat to capillary pressure for the piston-like advance of a convex interface in the same throat
- PV:
-
Pore volume (m3)
- q w :
-
Volumetric flow rate of water (m3/s)
- r P :
-
Pore radius (m)
- r T :
-
Throat radius (m)
- rP/rT:
-
Pore–throat aspect ratio
- S oi :
-
Initial oil saturation
- S ro :
-
Residual oil saturation
- S w :
-
Water saturation
- S wi :
-
Initial water saturation
- TDS:
-
Total dissolved solids (kg/m3)
- V :
-
Darcy velocity (apparent velocity) (q w/A) (m/s)
- V w :
-
Cumulative volume of the injected water (m3)
- V wBT :
-
Cumulative water injection volume at water breakthrough (m3)
- x :
-
Distance (m)
- ΔP :
-
Injection pressure difference (Pa)
- ΔP*:
-
Injection pressure difference corresponding to final tertiary oil recovery for each core (Pa)
- ΔP w/Δx :
-
Gradient of pressure in the water (Pa/m)
- ΔQ o :
-
Increased oil recovery in PV during a period of water injection
- \({\Delta Q_{\rm o}^{\ast}}\) :
-
Final tertiary oil recovery in PV for each core
- \({\phi}\) :
-
Core porosity
- μ :
-
Viscosity (Pa.s)
- μ w :
-
Water viscosity (Pa.s)
- μ 0 :
-
Oil viscosity (Pa.s)
- θ A :
-
Advancing contact angle (°)
- θ R :
-
Receding contact angle (°)
- σ :
-
Interfacial tension (N/m)
- ζ :
-
Ratio of N c to \({ N_{\rm c}^{\ast}}\)
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Open Access This is an open access article distributed under the terms of the Creative Commons Attribution Noncommercial License (https://creativecommons.org/licenses/by-nc/2.0), which permits any noncommercial use, distribution, and reproduction in any medium, provided the original author(s) and source are credited.
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Li, Y. Oil Recovery by Low Salinity Water Injection into a Reservoir: A New Study of Tertiary Oil Recovery Mechanism. Transp Porous Med 90, 333–362 (2011). https://doi.org/10.1007/s11242-011-9788-8
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DOI: https://doi.org/10.1007/s11242-011-9788-8