capillary pressure curve

A capillary pressure curve is a laboratory-measured relationship expressing the pressure difference across an oil-water or gas-water interface inside a pore throat as a function of wetting-phase saturation in a reservoir rock sample, characterizing how the capillary pressure that a buoyant non-wetting fluid must overcome to enter and drain pore throats varies from complete water saturation at the free water level to irreducible water saturation at the top of the transition zone, across the full pore size distribution of the rock. In Western Canada Sedimentary Basin reservoir engineering, capillary pressure curves serve three foundational functions: saturation height modeling converts a Pc-Sw curve measured on core samples at reservoir conditions into a predictive function for water saturation at each height above the free water level in the pay column, used to populate 3D geological models and compute hydrocarbon pore volumes for Cardium, Viking, Duvernay, and Montney reservoirs; free water level determination locates the depth at which capillary pressure equals zero for the oil-water system, distinguishing it from the shallower oil-water contact where resistivity logs detect the saturation transition; and seal capacity analysis quantifies the maximum hydrocarbon column height a cap rock or fault seal can retain before buoyancy pressure exceeds the threshold capillary entry pressure of the sealing lithology. The two primary laboratory measurement methods are mercury injection capillary pressure testing, which injects non-wetting mercury at progressively increasing pressures into a dry evacuated core plug and records cumulative mercury volume versus pressure to characterize pore throat size distribution and threshold entry pressure, and centrifuge capillary pressure measurement, which applies a controlled centrifugal body force to core plugs saturated with reservoir fluids and measures expelled wetting-phase volume as a function of rotational speed, yielding drainage and imbibition curves under conditions closer to actual reservoir fluid properties than mercury testing. Converting mercury injection data to reservoir conditions requires the Leverett conversion equation, where Pc at reservoir conditions equals Pc measured in mercury multiplied by the ratio of reservoir interfacial tension times cosine of reservoir contact angle to mercury interfacial tension times cosine of mercury contact angle; typical conversion factors for WCSB sandstone reservoirs with water-wet wettability and crude oil range from 0.04 to 0.08, reflecting the large difference between mercury surface tension of 480 mN/m and crude oil-brine interfacial tension of 15 to 30 mN/m. The shape of the drainage capillary pressure curve reflects the pore structure of the reservoir: tight rocks with small, poorly connected pore throats such as Montney siltstone show high entry pressures of 0.5 to 5 MPa and steep curves with irreducible water saturations of 30 to 50%, while high-quality Cardium or Viking sandstones show low entry pressures of 0.01 to 0.1 MPa and gradual curves with irreducible water saturations of 10 to 25%. Imbibition curves, measured by reducing capillary pressure after drainage to simulate waterflood displacement, capture wettability effects through the capillary pressure value at which spontaneous imbibition begins, the area between drainage and imbibition curves (related to wettability index by the Amott-Harvey method), and the residual oil saturation at the end of imbibition, which determines waterflood recovery efficiency in Cardium and Viking pools. In saturation height function development for WCSB reservoir characterization, petrophysicists commonly group core samples by Leverett J-function or flow zone indicator class and fit analytical curve forms such as the Brooks-Corey or lambda function to each rock type, enabling the saturation height model to predict water saturation in uncored wells and between well control points using the porosity and permeability logs as rock type discriminators. The Alberta Energy Regulator requires submission of capillary pressure data in pool evaluation reports for new field applications and enhanced recovery scheme approvals, with MICP data used to verify cap rock seal integrity for carbon dioxide injection and acid gas disposal projects under the framework of AER Directive 051. Understanding capillary pressure curve measurement, conversion to reservoir conditions, and application in saturation height modeling, volumetric analysis, and seal evaluation gives petrophysicists, reservoir engineers, and geologists the quantitative foundation for accurate hydrocarbon pore volume estimation and EOR program design in WCSB tight and conventional reservoirs.

• Drainage and imbibition paths: The drainage curve represents a non-wetting fluid (oil or gas) displacing water from progressively smaller pore throats as capillary pressure increases, simulating primary migration and trap filling. The imbibition curve represents water re-entering the pore system as capillary pressure decreases, simulating waterflood displacement. The hysteresis between the two curves reflects wettability: strongly water-wet rocks show large spontaneous imbibition at positive capillary pressure, while mixed-wet or oil-wet rocks show reduced or absent spontaneous imbibition, with the wettability index quantified by the Amott-Harvey or USBM method using areas under the two curves.
• MICP and Leverett conversion: Mercury injection capillary pressure testing injects mercury at pressures from 1 psi to 60,000 psi, characterizing pore throats from 100 microns to 0.003 microns in a single experiment on a 1 to 5 cm plug. Conversion to reservoir conditions via Pc-reservoir = Pc-mercury times (sigma-res cos theta-res) / (sigma-Hg cos theta-Hg) uses reservoir fluid interfacial tension and contact angle values measured or estimated for the specific WCSB crude-brine system; for central Alberta Cardium oil reservoirs the conversion factor is typically 0.04 to 0.06.
• Saturation height function development: Petrophysicists use Leverett J-function normalization (J = Pc times square root of k/phi divided by sigma cos theta) to collapse multiple core samples of similar rock quality onto a single dimensionless curve, then convert back to saturation versus height above free water level using local permeability and porosity. WCSB Cardium and Viking reservoirs commonly require two to four rock type classes to capture the full porosity-permeability range, with each class assigned its own J-function curve for saturation height modeling in the 3D geological model.
• Seal capacity and column height calculation: The maximum hydrocarbon column height a seal can retain equals the threshold capillary entry pressure of the sealing lithology divided by the product of the buoyancy pressure gradient (density difference between water and hydrocarbon times gravitational acceleration) converted from MICP to reservoir conditions. AER cap rock integrity assessments for CO2 storage projects in Alberta require MICP tests on a minimum of five seal plugs representing the full heterogeneity of the sealing formation above the injection interval.
• Tight reservoir applications (Montney, Duvernay): In tight gas and liquids-rich reservoirs where pore throat radii are 0.005 to 0.1 microns, MICP curves show high entry pressures and complex multi-modal pore systems reflecting intergranular and intercrystalline porosity contributions. Petrophysicists use MICP-derived pore throat size distributions to calibrate NMR T2 spectra, to predict formation water salinity effects on resistivity response, and to estimate the minimum pressure required for hydraulic fracture complexity in Montney and Duvernay completion design.

Capillary Pressure Curves in a Viking Formation Saturation Height Model at Provost

A WCSB operator building a new geological model for a Viking Formation pool at Provost submitted 18 restored-state core plugs for centrifuge drainage and imbibition capillary pressure measurements at 50 degrees Celsius with actual Viking crude and formation brine. Rock typing by flow zone indicator divided the plugs into three classes: Class 1 (k greater than 50 mD), Class 2 (5 to 50 mD), and Class 3 (less than 5 mD). J-function curves for each class were fit to Brooks-Corey equations and applied in the 3D model to predict Sw at every grid cell. The resulting saturation model reduced volumetric uncertainty from plus or minus 22% to plus or minus 11% compared to the previous log-based Sw assignment, lowering the proved undeveloped reserve estimate by 8% and prompting the operator to advance two additional appraisal wells before committing to a 20-well Cardium development program.

Related Terms

Capillary number uses capillary pressure concepts at the pore scale to quantify whether viscous or capillary forces dominate during displacement, forming the theoretical basis for EOR screening and surfactant flood design. Saturation height function is the product of capillary pressure curve analysis applied to well log prediction, translating the Pc-Sw relationship into a depth-saturation model populated across the 3D reservoir grid. Free water level is the datum at which capillary pressure equals zero in the oil-water system, located below the observed oil-water contact by a depth corresponding to the reservoir entry pressure, and calculated from capillary pressure curves combined with fluid density data. Mercury injection capillary pressure is the most widely used laboratory measurement method, providing high-pressure pore throat size distribution data from a single experiment but requiring Leverett conversion to translate mercury-air measurements to reservoir oil-brine conditions. Wettability controls the shape and hysteresis of the imbibition capillary pressure curve, with oil-wet or mixed-wet conditions shifting the imbibition curve toward negative capillary pressures and reducing spontaneous water imbibition, directly affecting waterflood recovery efficiency predictions derived from the curve.