Crude Blending — Engineering Fundamentals

1. Why blending indices?

For an ideal mixture, only properties that are linear functions of mass or volume mix without correction. Density and heat capacity blend linearly on a mass basis. Vapor pressure, viscosity, and pour point are highly nonlinear — a 10% addition of light naphtha to bitumen drops the bitumen viscosity by ~50% and raises its vapor pressure by ~3×.

Industry handles this by transforming each property into a blending index that does mix linearly (on either mass or volume basis), then inverting the index back to the property. Each property uses a different index function tuned to empirical mixing data.

2. Density / API blending

Density blends linearly on a volume basis because density × volume = mass and mass is conserved:

°API does not blend linearly because the API-to-SG transformation is hyperbolic. Always convert API → SG first, blend, then convert back: °API_blend = 141.5/SG_blend − 131.5.

3. RVP — Chevron VPBI

Reid Vapor Pressure is the bubble-point at 100°F for a vented sample. Mixing low- and high-RVP streams gives a result that is below the arithmetic mean. Chevron's VPBI captures this:

Blend volume-weighted, then invert:

The 1.25 exponent is Chevron's empirical vapor-pressure blending index — an industry correlation regressed across product families, not a value defined in an ASTM standard (D6378 covers RVP measurement, not blending). Because the exponent exceeds 1, the index behaves as a power-mean that returns a blend RVP slightly above the simple volume average — capturing the light ends' disproportionate contribution to vapor pressure, which is the safe side for an RVP spec check.

4. Viscosity — Refutas blending

Refutas (1942) is the industry-standard for crude viscosity blending. Kinematic viscosity (cSt) follows:

The double-log captures viscosity's exponential temperature dependence. Blend on a mass basis (mass is the conserved quantity for viscous transport):

Invert:

For viscosity at any temperature, ASTM D341 (Walther-MacCoull):

Fit A, B from two known (ν, T) points (typically 100°F and 210°F per ASTM D445). Then extrapolate to pipeline T.

5. Pour-point blending

Pour point (the temperature at which the crude stops flowing) is dominated by wax crystallization. Adding even a small amount of low-pour diluent dramatically depresses the blend pour. The Pour Point Blending Index (PPBI) commonly used in midstream:

The 12.5 exponent gives very heavy weight to the lowest-pour component, matching field experience that 10% diluent drops the blend pour by 30–50 °F. Volume-weighted:

6. Dilbit / heavy-crude example

Alberta bitumen (8°API, RVP 2 psi, 10,000 cSt @ 100°F, pour +80°F) blended with natural-gas-plant condensate (60°API, RVP 12, 0.7 cSt, pour −60°F):

	70% Bit / 30% Cond	50% / 50%	Pure Bit
API	20.4	29.9	8
RVP (psi)	~5.3	~7.5	2
Viscosity @ 100°F (cSt)	~80	~11	10,000
Pour point (°F)	~+50	~+30	+80

This is why dilbit shippers target 30% condensate addition: it brings viscosity below the typical 250 cSt pipeline limit and pour point below the line minimum, while keeping RVP under the 10–14 psi summer/winter spec.

7. References

• ASTM D6378 — Vapor Pressure Measurement by Mini-Method (replaces D323).
• ASTM D7152 — Standard Practice for Calculating Viscosity of a Petroleum Blend.
• ASTM D341 — Standard Practice for Viscosity-Temperature Charts.
• ASTM D445 — Kinematic Viscosity of Transparent and Opaque Liquids.
• ASTM D97 — Pour Point of Petroleum Products.
• API MPMS Ch. 12.3 — Calculation of Properties of Blended Petroleum Products.
• Refutas, J.M. (1942). Viscosity blending index method.
• Riazi, M.R. (2005). Characterization and Properties of Petroleum Fractions, ASTM MNL50.
• Wauquier, J.P. (1995). Petroleum Refining Vol. 1: Crude Oil, Petroleum Products, Process Flowsheets, Editions Technip.