fluid_properties · water properties
Water Viscosity
μw1 = A·T^B; μw = μw1·(0.9994+4.0295e-5·P+3.1062e-9·P²) [McCain 1991]
click formula to derive ↑
Inputs
°F
ppm NaCl
psi
Description
Computes brine viscosity from a temperature/salinity-dependent atmospheric-pressure term plus a small pressure correction, traced this session to McCain (1991, SPE-18571-PA) — the source a secondary compilation (pengtools) attributes this exact polynomial form to. Water viscosity feeds fractional-flow, injectivity, and IPR calculations wherever water production or injection is significant.
Variables
| Symbol | Unit | Description |
|---|---|---|
| μw | cP | Water Viscosity |
| T | °F | Reservoir temperature at which viscosity is evaluated. |
| S | ppm NaCl | Formation water salinity as NaCl-equivalent ppm (the same convention used by rw_salinity). Converted internally to weight-percent solids for the correlation. |
| P | psi | Reservoir pressure at which the pressure correction to viscosity is applied. |
Assumptions
- Salinity is expressed (and converted internally) as NaCl-equivalent, consistent with the ppm convention used elsewhere in this app (rw_salinity)
- Correlation represents produced/formation brine, not fresh injection water with unusual chemistry (e.g. polymer or scale-inhibitor additives)
- No dissolved gas content correction — the correlation is for gas-free (or lightly gas-saturated) brine
Limitations
- The salinity-dependent A/B coefficients were traced to a secondary compilation (pengtools) attributing this exact form to McCain (1991, SPE-18571-PA), not to Meehan (1980) directly, despite the correlation's common informal attribution to Meehan in petroleum-engineering literature; neither McCain (1991)'s nor Meehan (1980)'s own original printed content was independently read this session, so the coefficients themselves are not verified against a primary source — only McCain (1991)'s bibliographic identity is confirmed
- This session's own golden-vector cross-check (against known fresh-water steam-table viscosity) used zero salinity, which validates the T^B temperature form and the pressure correction but does not exercise the salinity-dependent A/B polynomial coefficients at all
- No fittedRange is authored on these inputs — the correlation's stated temperature/pressure/salinity fit envelope was not located this session; this is a disclosed gap, not an assertion of unlimited validity
- The ppm-NaCl-equivalent → weight-percent-solids conversion (÷10,000) used here is an approximation that ignores brine density at high salinity; treat results at very high salinity (>150,000 ppm) with added caution
- As with any viscosity correlation, lab-measured brine viscosity is preferred for high-value well test or injectivity design work
Use Cases
- → Fractional flow and relative permeability: Supply μw to fractional-flow and Buckley-Leverett-style waterflood calculations, where the water/oil viscosity ratio controls displacement efficiency.
- → Injectivity and voidage: Estimate injection-well injectivity index using brine viscosity at reservoir pressure and temperature.
- → Produced-water handling: Estimate flowing brine viscosity for wellbore and surface-facility pressure-drop calculations in high-water-cut wells.
Related Calculations
Region Notes
Global
Reservoir brine viscosity typically falls from ~0.3–0.5 cP at 150–200°F to ~0.15–0.25 cP at 250–300°F; high-salinity brines (>100,000 ppm) run somewhat higher than fresh water at the same temperature.
Permian Basin
Deep Wolfcamp brines (salinity 100,000–200,000+ ppm, 180–240°F) typically show μw ≈ 0.3–0.45 cP — noticeably higher than the fresh-water baseline at the same temperature due to high dissolved solids.
References
Primary source
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