Capillary pressure explains why an oil–water reservoir does not necessarily have a single sharp contact separating completely oil-filled rock from completely water-filled rock. Above a free-water level, buoyancy creates a pressure difference between fluids; the rock’s capillary-pressure curve connects that difference to the fractions of its pores occupied by the fluids.
For an ideal water-wet reservoir at static equilibrium, the oil–water pressure difference at height h above the free-water level is Pc = (ρw − ρo)gh. With a 200 kg/m³ density contrast, a point 10 metres above that level has Pc = 19.62 kPa. That pressure does not by itself give water saturation: an independently determined rock-specific drainage curve is still required. This guide extends the Gold Standard of Petroleum Geology.
Find the question you need
Choose a route or read the chapters in sequence. Every teaching chapter is open and the grouped chapter index is expandable.
Define the free-water level
Distinguish pressure datum, contacts and pore-scale occupancy. Start with [Chapter 1](#pt-capillary-chapter-1).
Calculate pressure with height
Derive hydrostatic differences and a fictional profile. Start with [Chapter 3](#pt-capillary-chapter-3).
Interpret the transition zone
Read entry pressures and rock-dependent saturation. Start with [Chapter 6](#pt-capillary-chapter-6).
Check geological evidence
Test wettability, drainage history, scale and logs. Start with [Chapter 8](#pt-capillary-chapter-8).
Practise and continue
Change the density contrast and connect to the wider library. Start with [Chapter 11](#pt-capillary-chapter-11).
Return to the Petroleum Geology subject guide for the complete field.
Chapter index
Define the free-water level: Chapters 1–2
Calculate pressure with height: Chapters 3–5
Interpret the transition zone: Chapters 6–7
Check geological evidence: Chapters 8–10
Practise and continue: Chapters 11–12
CHAPTER 1 OF 12 · Define the free-water level
1. Ask which contact the interpretation actually describes
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A water-bearing interval, an oil-producing interval and a log-picked oil–water contact can be observations of different quantities. The free-water level is a reference depth at which the oil and water pressures are equal in the simplified equilibrium construction. A saturation contact is commonly an operational threshold inferred from logs, fluid behavior or a reporting convention. They are not required to coincide.
Think of porous rock as a network of varied pore bodies and narrow throats, not an underground swimming pool. Entry into a pore throat costs capillary pressure, and a population of different throat sizes means invasion changes gradually as the pressure difference grows. Two layers at the same depth can carry different water saturations because their pore systems differ.
This chapter is about static two-phase oil–water equilibrium in a water-wet rock. Gas–water systems, mixed wettability, dynamic production and altered pore pressures require their own definitions. Treating those cases as automatically equivalent would replace geology with a shortcut.
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CHAPTER 2 OF 12 · Define the free-water level
2. Define capillary pressure, density and the vertical datum
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Use Pc = Po − Pw for this oil–water model, where Po is oil-phase pressure and Pw is water-phase pressure. Both are pressures at the same location. Define h positive upward from the free-water level, so h = 0 is the depth at which Po = Pw. The sign convention matters: switching the direction of depth without modifying the equation can reverse the physical answer.
At approximately constant density and gravitational acceleration, a static fluid pressure decreases with elevation according to dP/dh = −ρg. Oil is less dense than water in the constructed example. Therefore oil pressure decreases less rapidly upward than water pressure, and the difference Po − Pw grows with height.
Density in kg/m³ multiplied by g in m/s² and h in metres produces kg/(m·s²), or pascals. When a chart uses kilopascals, divide by 1,000; when a reservoir uses other pressure units, document the conversion. Relative pressure is not the same as an absolute formation-pressure reading.
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CHAPTER 3 OF 12 · Calculate pressure with height
3. Derive the buoyant pressure difference
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At a free-water-level reference h = 0, set Po(0) = Pw(0) = P0. Above it, Po(h) = P0 − ρo gh and Pw(h) = P0 − ρw gh. Subtracting gives Pc(h) = Po − Pw = (ρw − ρo)gh. This derivation is the entire source of the linear height relationship in the ideal incompressible model.
Oil–water density contrast is the controlling coefficient, not the density of oil alone. The equation has the same broad pressure balance as capillary rise, but it does not say every pore admits oil whenever Pc becomes positive. The pore-entry threshold still depends on the rock-fluid interface and wetting state.
The relationship also assumes pressures have equilibrated over the connected system and there is no significant fluid motion, strong capillary disequilibrium or lateral pressure gradient modifying the datum. If the fluids are appreciably compressible or density varies with depth, integrate the depth-dependent density contrast instead of multiplying a single constant.
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CHAPTER 4 OF 12 · Calculate pressure with height
4. Work a 20-metre fictional saturation-height profile
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Suppose water density is 1,000 kg/m³, oil density is 800 kg/m³ and g = 9.81 m/s². The density difference is 200 kg/m³. Therefore Pc = 1,962h pascals when h is in metres, or Pc = 1.962h kPa.
At heights 0, 5, 10 and 20 metres, the corresponding pressure differences are 0, 9.81, 19.62 and 39.24 kPa. These are not universal reservoir values: the numbers belong to this explicitly fictional constant-density fluid pair.
To translate those pressures into water saturation, introduce a separate fictional rock curve. Suppose a laboratory primary-drainage relation for this rock would indicate Sw near 1.00, 0.70, 0.45 and 0.27 at those pressures respectively. Such values are illustrative inputs, not predictions derived from the hydrostatic equation.
| Height above FWL | Δρ × g × h | Illustrative Sw | Interpretation |
|---|---|---|---|
| 0 m | 0 kPa | 1.00 | Pressure-equality datum |
| 5 m | 9.81 kPa | 0.70 | Partial oil invasion in example curve |
| 10 m | 19.62 kPa | 0.45 | More pore space occupied by oil |
| 20 m | 39.24 kPa | 0.27 | Approaching the assumed high-oil zone |
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CHAPTER 5 OF 12 · Calculate pressure with height
5. Keep a pressure curve separate from a depth curve
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A capillary-pressure curve has Pc on one axis and saturation on the other. A depth or height curve adds hydrostatic equilibrium and a datum. The modelling chain is h → Pc(h) → Sw(Pc), provided the laboratory curve applies to that rock and fluid history. Each arrow requires an assumption or measurement.
If someone gives you only a free-water level and density contrast, you can calculate Pc but not Sw uniquely. Many different pore-throat distributions could produce different saturations at the same pressure. Conversely, the same measured saturation at two depths does not prove the fluids have the same pressure difference if their rock textures or wetting states differ.
A useful interpretation notes which data were measured on core, which came from petrophysical logs and which were imposed by a chosen rock-type function. It also asks whether laboratory pressure was converted to reservoir interfacial tension and density conditions appropriately.
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CHAPTER 6 OF 12 · Interpret the transition zone
6. Understand why smaller pore throats need more pressure
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For a simplified cylindrical capillary tube, the Laplace relation is Pc = 2σ cosθ / r, with interfacial tension σ, contact angle θ and tube radius r under the selected wetting convention. A rock is not a bundle of identical straight tubes, but the expression exposes the trend: smaller effective throats demand larger entry pressure under comparable fluid conditions.
Use a hypothetical σ = 0.030 N/m and θ = 0°, so cosθ = 1. A 10-micrometre radius corresponds to 6 kPa, a 3-micrometre radius to 20 kPa and a 1-micrometre radius to 60 kPa. The exercise explains why at 19.62 kPa some pathways may have admitted nonwetting oil while tighter pathways remain water-bearing.
Those tube radii are not a reconstruction of pore-throat statistics in a real reservoir. Contact-angle distributions, interconnected shapes, surface roughness and snap-off complicate actual displacement. The purpose is to understand why an otherwise simple hydrostatic pressure profile can yield a broad saturation transition.
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CHAPTER 7 OF 12 · Interpret the transition zone
7. Compare a clean sand with a tighter rock at the same height
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Imagine two adjacent layers at h = 10 metres above the same equilibrated oil–water free-water level. Both see the same ideal capillary pressure of 19.62 kPa. The coarser sand may have low entry pressures and reach comparatively low Sw, while a tighter, more strongly capillary-retentive layer can remain water-rich.
Thus there is no universal thickness for the transition zone. Rock types with different entry pressures, pore-size distributions and wetting properties create different saturation-height functions. A petrophysical interpretation that imposes one Sw value on every facies may miss the controlling geology.
Be especially careful when borrowing a permeability threshold as a direct capillary-pressure threshold. Permeability and pore-throat structure are related, but they are not identical descriptions. A quantitative relationship needs a tested rock-type model, not just an assumed colour on a log.
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CHAPTER 8 OF 12 · Check geological evidence
8. Distinguish initial drainage from later fluid history
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Primary drainage describes the nonwetting phase invading a system initially filled by the wetting phase. Imbibition describes displacement in the opposite wetting direction. Because interfaces can become trapped and contact lines behave differently, the saturation at a particular Pc can depend on the route taken. This is hysteresis, not a numerical error.
Production, water injection and changing pressure can shift both the local saturation distribution and the relevant relationship between Pc and Sw. A curve derived for initial hydrocarbon charge is therefore not automatically the right curve for a waterflood at later time.
Check the samples: were they cleaned and restored, which fluid pair was used, what drainage and imbibition sequence was applied, and was wettability preserved or altered? Those questions protect a static geologic reconstruction from being misread as a dynamic flow forecast.
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CHAPTER 9 OF 12 · Check geological evidence
9. Make the evidence map explain its own limitations
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Core plug capillary-pressure experiments constrain pore entry and saturation under their procedures. Well-log resistivity, NMR and other measurements constrain different aspects of fluid occupancy and rock quality, with their own calibration assumptions. Formation-pressure measurements can support fluid gradients and contacts, but must be quality-controlled for supercharge and mobility effects.
Build a traceable record from datum through pressure gradients, rock typing, laboratory curves and log-derived saturation comparisons. If two interpretations fit the observations, show both rather than declaring the curve unique. Cross-facies comparisons should identify the laboratory sample coverage and the spatial scale of each observation.
An attractive pressure-versus-height plot is not enough when core histories differ, the pore network is heterogeneous or the proposed free-water level lacks pressure evidence. The testing plan should specify which additional observation would discriminate competing saturation models.
| Evidence | Can support | Cannot establish alone |
|---|---|---|
| Fluid pressure gradient | Density and pressure datum | Unique pore-entry distribution |
| Capillary pressure on core | Sample-specific Pc–Sw relationship | Whole-field facies continuity |
| Resistivity / NMR interpretation | Depth-dependent fluid occupancy | One globally valid saturation function |
| Core fabric and logs | Rock types, thickness, local boundaries | Identical wettability across all layers |
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CHAPTER 10 OF 12 · Check geological evidence
10. Answer the questions parents and students actually ask
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Why can rock above the oil–water contact still contain water? Because wetting water can occupy smaller pores and adhere to surfaces after nonwetting oil invades larger connected pore spaces. The amount depends on capillary conditions and rock history.
Does the free-water level appear as a neat line on every log? Not necessarily. It is a pressure-equality reference in this construction, whereas log-picked contacts may refer to saturation thresholds, tool response or formation fluids. Their relation requires interpretation, not identical terminology.
Does a higher Pc mean the rock always contains less water? Under the specified primary-drainage water-wet relation, increasing Pc commonly means lower wetting-phase saturation. An imbibition path, different wettability, altered fluids or a new rock type can change that interpretation.
Can this static equation predict oil recovery? No. It contributes to an initial-state picture. Dynamic recovery needs permeability, relative permeability, pressure changes, flow geometry, well completions and other reservoir and engineering information.
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CHAPTER 11 OF 12 · Practise and continue
11. Change the density contrast and check the meaning
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Keep h = 10 metres but use water density 1,030 kg/m³ and oil density 850 kg/m³. Now Δρ = 180 kg/m³, so Pc = 180 × 9.81 × 10 = 17,658 Pa = 17.658 kPa. The answer drops from 19.62 kPa even though the geometric height has not changed.
Would Sw necessarily fall or rise by a fixed percentage? No. To determine the new saturation you must evaluate the relevant Pc–Sw relationship, ideally with fluid-property corrections made for the changed system. A slight change in Pc can mean a large saturation change in one part of a curve and a tiny change in another.
As a second check, halve the height to 5 metres while keeping the new density contrast. The hydrostatic Pc becomes 8.829 kPa. Write the units, confirm the sign convention and explain why the calculation establishes a pressure difference rather than a producible oil volume.
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CHAPTER 12 OF 12 · Practise and continue
12. Connect the contact problem to the wider petroleum system
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The gold standard is a defensible chain from a fluid pressure datum to a rock-appropriate capillary-pressure curve and then to saturation, with the uncertainties visible. There is no single magic contact that can stand in for all three parts of that chain.
The Petroleum Geology root connects reservoir fabric with source, migration, seal and evidence. For a different kind of reservoir calculation, continue to layered permeability and directional flow. It explains fluid movement, not the capillary equilibrium profile developed here.
The spatial covariance and gas-filled pore volume guide addresses another important distinction: why separate averages of pore volume and saturation do not always reproduce the spatially paired calculation.
Sources and further reading
The resources below explain the underlying physical principles and the measurement context. Numerical values and comparison cases in this article are original fictional teaching models; they are not reported field or instrument results.
- SLB Defining Series: Wettability — Free-water level, capillary transition zones and wettability
- SLB Energy Glossary: Capillary Pressure Curve — Rock pore-throat distribution and saturation response
- SLB Energy Glossary: Saturation — Volume fraction of pore space occupied by a phase
- USGS Water Science: Capillary Action — Accessible wetting and capillary-rise physical context
Gold Standard of Petroleum Geology · How X Works · The Gold Standard of Education
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Source context checked 21 October 2026. Study examples deliberately simplify their conditions; application to field or laboratory decisions requires appropriate specialist evidence.