Formation Water PVT Properties

Overview

Formation water (brine) properties are essential for:

• Reservoir simulation — Aquifer influx, water coning
• Material balance — Water expansion drive calculations
• Production forecasting — Water breakthrough, water cut trends
• Well testing — Aquifer properties, permeability calculations
• Pressure-transient analysis — Total compressibility determination
• Production facility design — Separator sizing, water handling

Unlike oil and gas, formation water properties are primarily influenced by:

1. Temperature — Dominant effect on density and viscosity
2. Pressure — Affects compressibility and dissolved gas
3. Salinity — Total dissolved solids (TDS) concentration

The McCain (1991) correlations presented here provide comprehensive property predictions for formation water at reservoir conditions.

Salinity and Units

Total Dissolved Solids (TDS)

Formation water contains dissolved salts (primarily NaCl, CaCl₂, MgCl₂). Salinity is expressed in multiple units:

In this document:

• S denotes weight % solids (0 to 30%)
• Pure water: S = 0%
• Typical seawater: S ≈ 3.5%
• Heavy brines: S = 20-30%

Water Density (ρw)

Standard Conditions Density

Water density at standard conditions (14.7 psia, 60°F) is calculated from salinity:

Where:

• $\rho_w$ = water density at standard conditions, lb/ft³
• $S$ = salinity, weight % (0 to 30%)

Accuracy: As accurate as laboratory measurement throughout full range of salinity.

Typical values:

• Pure water (S = 0%): ρw = 62.37 lb/ft³
• Seawater (S = 3.5%): ρw = 63.91 lb/ft³
• Heavy brine (S = 25%): ρw = 73.73 lb/ft³

Reservoir Conditions Density

Density at reservoir conditions is obtained from:

Where $B_w$ is the formation volume factor at reservoir pressure and temperature.

Water Formation Volume Factor (Bw)

The water FVF relates reservoir volume to stock-tank volume:

McCain provides correlations for pressure and temperature effects on water volume. The complete correlation accounts for:

1. Thermal expansion — Water expands with increasing temperature
2. Pressure compression — Water compresses with increasing pressure
3. Dissolved gas — Gas in solution increases volume

McCain Bw Correlation

The water FVF is correlated as:

Where:

• $\Delta V_{wT}$ = volume change due to temperature (from 60°F to reservoir T)
• $\Delta V_{wp}$ = volume change due to pressure (from 14.7 psia to reservoir P)

Temperature effect:

Water expands with temperature. The McCain correlation provides accurate Bw over the range:

• Temperatures: to 260°F
• Pressures: to 5,000 psia
• Salinities: all concentrations

Accuracy: Within 2% of experimental data.

Physical trends:

• Bw increases with temperature (thermal expansion)
• Bw decreases with pressure (compressibility)
• Bw slightly affected by salinity (≈ 1% variation)
• Typical range: Bw = 1.00 to 1.06 bbl/STB

Solution Gas-Water Ratio (Rsw)

Natural gas dissolves in water at reservoir conditions. The solution gas-water ratio is the volume of gas (at standard conditions) dissolved in one stock-tank barrel of water.

Pure Water Rsw

For pure water (S = 0%), McCain provides:

Where:

And:

• $R_{swp}$ = solution gas-water ratio for pure water, scf/STB
• $p$ = pressure, psia
• $T$ = temperature, °F

Applicability:

• Pressures: 1,000 to 10,000 psia
• Temperatures: 100 to 340°F
• Accuracy: Within 5% of original graphical correlation

Important: Do NOT use below 1,000 psia (correlation becomes inaccurate).

Formation Water Rsw (Brine)

Dissolved salts reduce gas solubility. The salinity correction factor is:

Therefore:

Where:

• $R_{sw}$ = solution gas-water ratio for brine, scf/STB
• $R_{swp}$ = Rsw for pure water (from previous correlation)
• $S$ = salinity, weight %
• $T$ = temperature, °F

Applicability:

• Salinities: to 30%
• Temperatures: 70 to 250°F
• Accuracy: Within 3% of graphical correlation

Physical trends:

• Rsw increases with pressure (more gas dissolves)
• Rsw increases with temperature (typically opposite to oil)
• Rsw decreases with salinity (salt-out effect)
• Typical values: 5 to 25 scf/STB at reservoir conditions

Water Compressibility (Cw)

Water compressibility measures volume change with pressure:

Undersaturated Water Compressibility — Osif (1988)

For pressures above bubblepoint (no free gas):

Where:

• $C_w$ = water compressibility, psi⁻¹
• $p$ = pressure, psia
• $S$ = salinity, mg/L (note: different units!)
• $T$ = temperature, °F

Applicability:

• Temperatures: 200 to 270°F
• Pressures: 1,000 to 20,000 psia
• Salinities: to 200,000 mg/L

Physical trends:

• Cw decreases with pressure (harder to compress at high P)
• Cw decreases with temperature (more rigid structure at high T)
• Cw decreases with salinity (dissolved salts stiffen water)
• Typical values: (2 to 5) × 10⁻⁶ psi⁻¹

Saturated Water Compressibility — McCain (1991)

For pressures below bubblepoint (dissolved gas present):

The gas liberation term is:

Using B and C from the Rsw correlation.

Note: McCain states this saturated Cw correlation has "unknown accuracy" and should be considered "order of magnitude" only.

Practical approach: For most reservoir engineering calculations, use Osif correlation (undersaturated). The gas liberation effect is small compared to oil systems.

Water Viscosity (μw)

Viscosity at Atmospheric Pressure

Water viscosity at reservoir temperature and 1 atm pressure:

Where:

And:

• $\mu_{w1}$ = water viscosity at 1 atm, cP
• $T$ = temperature, °F
• $S$ = salinity, weight %

Applicability:

• Temperatures: 100 to 400°F
• Salinities: to 26%
• Accuracy: Within 5% of graphical correlation

Pressure Correction

Water viscosity at reservoir pressure:

Where:

• $\mu_w$ = water viscosity at reservoir pressure, cP
• $\mu_{w1}$ = water viscosity at 1 atm (from previous correlation)
• $p$ = pressure, psia

Applicability:

• Pressures: to 10,000 psia (within 4%)
• Pressures: 10,000 to 15,000 psia (within 7%)

Physical trends:

• μw decreases with temperature (dominant effect, exponential)
• μw increases slightly with pressure (weak effect, quadratic)
• μw increases with salinity (dissolved salts increase viscosity)
• Typical values: 0.2 to 1.0 cP at reservoir conditions
• Pure water at 150°F: μw ≈ 0.35 cP
• Brine (S = 25%) at 150°F: μw ≈ 0.55 cP

Functions Covered

The following functions implement McCain's formation water property correlations. See each function page for detailed parameter definitions, Excel syntax, and usage examples.

Comparison: Water vs. Oil Properties

Key differences:

• Water is nearly incompressible compared to oil
• Water viscosity is low and varies primarily with temperature
• Water holds very little dissolved gas (salting-out effect)
• Water FVF is close to 1.0 (small expansion)

Practical Applications

Material Balance — Aquifer Influx

Water properties needed for Carter-Tracy aquifer model:

• Cw — Water compressibility for aquifer expansion
• μw — Water viscosity for aquifer mobility
• Bw — Water volume at reservoir conditions

Well Testing — Total Compressibility

Total compressibility in aquifer/water zone:

Where:

• $S_w$ = water saturation
• $c_w$ = water compressibility
• $c_f$ = formation (rock) compressibility

Production Forecasting — Water Cut

Water production rate:

Surface water rate from reservoir:

Related Documentation

• PVT Overview — Correlation selection guide
• Gas Properties — Natural gas PVT
• Oil Formation Volume Factor — Oil FVF correlations
• PTA Dimensionless Variables — Uses total compressibility

References

1. McCain, W.D. Jr. (1991). "Reservoir-Fluid Property Correlations—State of the Art." SPE Reservoir Engineering, 6(2), pp. 266-272. SPE-18571-PA. Equations 52-65.

2. Osif, T.L. (1988). "The Effects of Salt, Gas, Temperature, and Pressure on the Compressibility of Water." SPE Reservoir Engineering, 3(1), pp. 175-181. SPE-13174-PA.

3. McCain, W.D. Jr. (1990). The Properties of Petroleum Fluids, 2nd Edition. Tulsa, OK: PennWell Books. Chapter 9: Properties of Produced Water.

4. Collins, A.G. (1975). Geochemistry of Oilfield Waters. Developments in Petroleum Science, Vol. 1. Amsterdam: Elsevier.

5. Ahmed, T. (2019). Reservoir Engineering Handbook, 5th Edition. Cambridge, MA: Gulf Professional Publishing. Chapter 7: Unconventional Gas Reservoirs.

6. Craft, B.C. and Hawkins, M.F. (1991). Applied Petroleum Reservoir Engineering, 2nd Edition. Englewood Cliffs, NJ: Prentice Hall. Chapter 2: Reservoir Fluids Properties.