1. Introduction
Wettability is one of the most significant parameters controlling how fluids are distributed and produced from a reservoir. It defines the preference of a rock surface to be in contact with either water or oil when both phases coexist within the pore system. Because it governs capillary pressure, relative permeability, residual oil saturation, and displacement efficiency, understanding wettability is essential for accurate formation evaluation and for the design of enhanced oil recovery (EOR) processes.
Traditional laboratory methods—such as contact angle measurement, Amott–Harvey, and USBM tests—are accurate but expensive, slow, and limited to a small number of core samples. In contrast, capillary pressure data and well logs provide broader, indirect but powerful tools to infer wettability over an entire reservoir interval. Integrating these data sources helps in predicting flow behavior and optimizing recovery strategies with higher spatial confidence.
This article discusses how wettability can be determined using capillary pressure relationships and well-log responses, highlighting the petrophysical basis, indicators, and interpretation methodologies, while avoiding the complexity of mathematical formulations.
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2. Fundamentals of Wettability
Wettability expresses how a rock surface interacts with immiscible fluids such as oil and water. When a rock prefers water, it is termed water-wet; when it prefers oil, it is oil-wet; and when no clear preference exists, it is intermediate-wet or mixed-wet.
The concept is based on the balance of interfacial forces between rock, oil, and water. A strongly water-wet system tends to hold water films tightly on pore surfaces, forcing oil to occupy larger pores. In an oil-wet rock, the reverse occurs: oil adheres to the grain surface and water occupies the central pore spaces.
In a reservoir, wettability influences:
Fluid distribution: Determines which phase occupies small or large pores.
Capillary pressure: Controls the pressure difference needed to move fluids through pores.
Relative permeability: Affects the mobility ratio between oil and water.
Residual saturation: Dictates how much oil remains after waterflooding.
EOR response: Determines success of surfactant or polymer flooding operations.
Recognizing these effects is vital because two reservoirs with identical porosity and permeability may exhibit entirely different production behavior simply due to differing wettability conditions.
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3. Capillary Pressure and Wettability Relationship
Capillary pressure reflects the pressure difference between non-wetting and wetting fluids at pore level. Its magnitude and shape are controlled by pore size distribution, interfacial tension, and wettability. Therefore, analyzing capillary pressure curves provides valuable qualitative information about the rock–fluid interactions.
In a water-wet system, the entry pressure is high because water clings to the pore walls, resisting displacement. Capillary pressure increases sharply as saturation decreases, producing a steep curve. Conversely, in an oil-wet system, capillary forces are reversed; entry pressure is lower, and the curve is flatter because oil readily coats the surfaces.
This contrast allows capillary pressure data to serve as a diagnostic signature for wettability identification.
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4. Laboratory Determination of Capillary Pressure
Capillary pressure data can be obtained through several experimental methods, the most common being:
Mercury Injection Capillary Pressure (MICP): Mercury acts as a non-wetting fluid to air-filled pores. This technique provides detailed pore-throat size distribution and entry pressures.
Centrifuge Method: A fluid pair (typically oil and brine) is separated by centrifugal force to determine pressure–saturation relationships under more realistic reservoir conditions.
Porous Plate Method: Uses air-brine or oil-brine systems at controlled pressures to simulate displacement processes similar to reservoir flow.
The choice of method depends on available sample size, desired pressure range, and accuracy requirements. Regardless of the method, the resulting curve can reveal the relative wettability through its general trend and hysteresis behavior between drainage and imbibition cycles.
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5. Interpretation of Capillary Pressure Curves for Wettability
The shape and hysteresis of the capillary pressure curve provide qualitative indications of wettability:
1. Strongly Water-Wet: High entry pressure; steep slope; wide separation between drainage and imbibition curves.
2. Weakly Water-Wet: Moderate entry pressure; slightly reduced hysteresis.
3. Intermediate- or Mixed-Wet: Balanced behavior; drainage and imbibition curves intersect or show irregular slopes.
4. Oil-Wet: Low entry pressure; shallow slope; minimal hysteresis or even reversed capillary behavior.
A wide hysteresis between drainage and imbibition indicates strong adhesion of the wetting phase, while minimal hysteresis points to uniform oil wetness. These observations can be correlated with core wettability indices when available, ensuring consistency across the dataset.
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6. Well-Log Indicators of Wettability
In addition to laboratory data, several logging responses provide indirect evidence of reservoir wettability. Logs capture variations in electrical, acoustic, and nuclear properties that depend on fluid distribution and surface interactions. The key indicators include:
6.1 Resistivity Logs
Resistivity is sensitive to the distribution of conductive brine within the pore space.
In water-wet rocks, water forms continuous films along grain surfaces, providing conductive pathways, resulting in lower resistivity.
In oil-wet formations, brine becomes isolated, resistivity increases, and Archie’s parameters (a, m, n) may deviate from standard values.
Interpreting anomalously high resistivity in zones of known water saturation can therefore hint at oil-wet behavior.
6.2 Spontaneous Potential (SP) Logs
SP anomalies can be dampened in oil-wet rocks because ionic movement across the borehole wall is reduced when the rock surface is coated with oil films. A suppressed SP deflection relative to a baseline shale can suggest oil wetness, especially when supported by other indicators.
6.3 Nuclear Magnetic Resonance (NMR) Logs
NMR measurements provide pore size distributions and fluid typing. The relaxation times (T₂) are affected by the surface interactions between fluids and grains.
Water-wet rocks show shorter T₂ values due to stronger surface relaxation of bound water, whereas oil-wet rocks show longer relaxation times and weaker bound-water peaks.
6.4 Dielectric and Nuclear Logs
Dielectric dispersion logs respond to fluid conductivity and polarization; oil-wet conditions may reduce permittivity values. Similarly, neutron-density cross-plots can highlight anomalous responses due to fluid replacement and film thickness differences related to wettability.
By integrating these multiple log responses—resistivity, SP, NMR, and dielectric—a consistent picture of wettability can be built even in the absence of direct core analysis.
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7. Integration of Capillary Pressure and Log Data
The most reliable determination of wettability comes from combining laboratory and log-derived information. Capillary pressure provides microscopic evidence of fluid–rock interactions, while logs offer macroscopic coverage across the reservoir.
A typical workflow includes:
1. Deriving wettability signatures from capillary pressure curves measured on representative core samples.
2. Calibrating log responses (such as resistivity and NMR) against these laboratory results in the same depth intervals.
3. Extending the interpretation of calibrated log parameters to uncored sections, generating a continuous wettability profile along the wellbore.
4. Integrating with geological models to map lateral wettability variations across the field.
Such integration not only validates the petrophysical interpretation but also supports reservoir simulation studies that require accurate wettability inputs for capillary pressure and relative permeability functions.
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8. Influence of Wettability on Reservoir Performance
Understanding wettability has direct operational and economic implications.
In strongly water-wet systems, water flooding tends to be efficient because injected water readily displaces oil from smaller pores, yielding high recovery factors.
In oil-wet or mixed-wet systems, recovery efficiency decreases since water bypasses oil adhering to pore surfaces, leaving high residual oil saturation.
During EOR operations, wettability alteration (via surfactant or low-salinity water flooding) becomes a powerful mechanism to improve microscopic displacement efficiency.
Hence, the accurate determination of wettability from capillary pressure and logs forms the foundation for predicting fluid behavior during primary and secondary recovery stages.
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9. Limitations and Uncertainties
While capillary pressure and logging methods are invaluable, they are not without limitations.
Capillary pressure curves are obtained on small core plugs that may not represent reservoir heterogeneity.
Laboratory conditions often differ from actual reservoir temperature, pressure, and wettability states.
Log interpretation requires careful calibration; similar responses can arise from lithological or salinity variations rather than wettability changes.
Mixed-wet systems present complex signatures that may overlap with those of other rock types.
Therefore, the interpretation must always be supported by multiple datasets, including core analysis, production data, and geological understanding.
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10. Emerging Trends in Wettability Evaluation
Recent developments in digital rock physics, imaging, and machine learning are enhancing wettability characterization. High-resolution micro-CT scans allow three-dimensional visualization of fluid distribution, while AI algorithms can classify wettability states from integrated log patterns. Data-driven workflows enable continuous field-scale wettability mapping, which previously required extensive laboratory programs. These advances are transforming wettability from a static laboratory parameter into a dynamic reservoir property continuously monitored during production.
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11. Conclusion
Wettability determination is a cornerstone of reservoir characterization. It governs the movement, distribution, and recoverability of hydrocarbons. Although direct laboratory measurements remain the standard, capillary pressure data and well logs offer practical and comprehensive tools to infer wettability across entire formations.
Capillary pressure curves reveal microscopic interactions between fluids and rocks through their shape, entry pressures, and hysteresis, while log responses—particularly resistivity, SP, NMR, and dielectric—provide macroscopic, depth-continuous indications. Integrating both approaches enables petroleum engineers to establish reliable wettability models that improve reservoir simulation accuracy and enhance recovery strategies.
Ultimately, understanding wettability through capillary pressure and log interpretation empowers decision-makers to optimize waterflood design, select appropriate EOR methods, and predict field performance with greater confidence. As digital technologies evolve, these integrated methods will continue to refine the understanding of fluid–rock interactions, supporting smarter and more sustainable reservoir management.
Written by Dr.Nabil Sameh
-Business Development Manager at Nileco Company
-Certified International Petroleum Trainer
-Professor in multiple training consulting companies & academies, including Enviro Oil, ZAD Academy, and Deep Horizon
-Lecturer at universities inside and outside Egypt
-Contributor of petroleum sector articles for Petrocraft and Petrotoday magazines
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