Viscosity
Viscosity is the fundamental physical property of a fluid that quantifies its internal resistance to flow — defined as the ratio of shear stress (the force per unit area applied tangentially to a fluid layer) to shear rate (the velocity gradient across the fluid perpendicular to the shear direction), expressed in units of Pascal-seconds (Pa·s) in SI units or centipoise (cP, equal to one millipascal-second) in the oilfield unit system; for a Newtonian fluid such as water or light crude oil, viscosity is a constant material property at a given temperature and pressure and is independent of the shear rate applied, while for non-Newtonian fluids such as drilling mud, cement slurry, and heavy oil, the apparent viscosity (shear stress divided by shear rate at a specific shear rate) varies with the rate of shearing and must be characterized by a multi-parameter rheological model; viscosity is critically important throughout oil and gas operations because it governs fluid flow through pipes and formation pore throats (via Darcy's law, where viscosity appears in the denominator of flow rate), controls the efficiency of oil displacement by water or gas (through the mobility ratio, which is the ratio of displacing-fluid mobility to displaced-fluid mobility and is proportional to the viscosity ratio), determines pump pressure requirements for fluid handling, and is the primary physical variable that distinguishes producible light oil (1 to 5 cP) from heavy oil (100 to 10,000 cP) and bitumen (greater than 100,000 cP at reservoir temperature).
Key Takeaways
- Dynamic viscosity versus kinematic viscosity distinction is fundamental to fluid mechanics — dynamic viscosity (also called absolute viscosity) mu is the ratio of shear stress to shear rate and has units of Pa·s or cP; kinematic viscosity nu is dynamic viscosity divided by fluid density (nu = mu/rho) and has units of m2/s or centistokes (cSt); the kinematic viscosity is more convenient when fluid flow is governed by inertial and viscous forces simultaneously (as in pipe flow characterized by Reynolds number Re = rho×v×D/mu = v×D/nu), while dynamic viscosity is more relevant when shear stress and flow rate are the primary engineering quantities; crude oil viscosity in production engineering is almost always reported as dynamic viscosity in cP because production flow equations use dynamic viscosity directly, while lubrication oils and refined products are often characterized in centistokes because their handling involves kinematic flow comparisons; the conversion between the two requires density: for a 30 API crude oil (density approximately 0.876 g/cc), a dynamic viscosity of 5 cP corresponds to a kinematic viscosity of approximately 5.7 cSt.
- Temperature dependence of crude oil viscosity is exponential — viscosity decreases sharply with increasing temperature following an Andrade-type relationship approximately mu = A × exp(B/T) where T is absolute temperature, and the practical consequence is that crude oil that is barely pumpable at surface conditions (high viscosity at ambient temperature) flows freely at reservoir temperature; for a medium-heavy crude oil (15 API, 500 cP at 15°C), the viscosity at typical reservoir temperature of 60°C may be 50 to 100 cP, and at 90°C it may be 15 to 30 cP — a factor of 15 to 30 reduction achieved purely by temperature; this is the thermodynamic basis for thermal EOR methods (steam flooding, SAGD, in-situ combustion) that heat the reservoir to reduce oil viscosity and enable production from formations where primary and cold water injection recovery is uneconomic; in Arctic and deepwater cold pipeline flow problems, the inverse applies — oil that flows at reservoir temperature congeals in the cold pipeline unless the pipeline is heated, insulated, or treated with pour-point depressants.
- Pressure dependence of viscosity increases with pressure (viscosity increases slightly with increasing pressure for most liquids) and is generally secondary to temperature effects for crude oils at moderate reservoir pressures but becomes significant for high-pressure reservoirs above 700 to 1,000 bar; gas viscosity behaves differently from liquid viscosity — gas viscosity increases with increasing temperature (unlike liquids, where viscosity decreases with temperature) because gas viscosity is governed by the frequency of molecular collisions (which increases with temperature) rather than by intermolecular attraction (which governs liquid viscosity); natural gas viscosity at reservoir conditions is typically 0.01 to 0.05 cP, compared to reservoir oil viscosity of 0.5 to 10 cP for light to medium crudes and formation water viscosity of 0.3 to 1.0 cP — this order-of-magnitude difference in viscosity is the primary reason gas wells produce at much higher rates per unit reservoir permeability than oil wells (the gas Darcy flow rate is higher by the inverse of the viscosity ratio).
- Drilling mud viscosity measurement using the Fann VG meter (rotational viscometer) at 600 rpm and 300 rpm provides the two readings from which the Bingham plastic viscosity (PV = R600 - R300, in cP) and yield point (YP = R300 - PV, in lb/100 ft2) are calculated; the funnel viscosity measured with the Marsh funnel (reporting the time in seconds for 946 mL of mud to flow through the funnel) is a quick field check of overall mud consistency but is not a true viscosity measurement because it is a combined measure of both viscosity and yield stress that cannot be decomposed into its components without the Fann meter; the plastic viscosity PV is the best single indicator of the high-shear viscosity of the mud (governing pump pressure losses in the drillstring) and should be maintained below approximately 20 to 30 cP for typical land drilling to keep surface pump pressures within operational limits, while the yield point YP governs cuttings carrying capacity in the annulus at low shear rates and should be maintained above 15 to 20 lb/100 ft2 for adequate hole cleaning in deviated wells.
- Reservoir fluid viscosity in simulation and material balance calculations must be corrected from surface conditions to reservoir conditions using PVT (pressure-volume-temperature) relationships — the oil viscosity at reservoir pressure and temperature is significantly lower than the dead oil viscosity measured in the laboratory at surface conditions, because dissolved solution gas dramatically reduces oil viscosity (the viscosity of oil saturated with 100 to 300 scf/bbl of solution gas at reservoir pressure may be 3 to 10 times lower than the bubble-point degassed oil viscosity); the Beggs-Robinson, Beal, and Chew-Connally correlations predict reservoir oil viscosity from API gravity, solution GOR, temperature, and pressure as inputs; accurate reservoir oil viscosity is required for Darcy flow rate calculations, material balance, and numerical reservoir simulation because viscosity errors of a factor of 2 propagate directly into factor-of-2 errors in predicted production rates and recovery factors in the viscosity-dominated (high-mobility-contrast) flow regimes encountered in heavy oil and viscous crude reservoirs.
Fast Facts
The unit of dynamic viscosity in the CGS system, the poise (P), is named after Jean-Louis-Marie Poiseuille (1799-1869), the French physician and physiologist who derived the fundamental equation for viscous flow in cylindrical tubes (Poiseuille's Law: Q = pi×r4×delta_P / 8×mu×L) while studying blood flow in capillaries — the same equation that governs fluid flow in cylindrical wellbores and tubular goods. One poise equals 0.1 Pa·s, so water at 20°C has a dynamic viscosity of approximately 1 cP (0.01 poise = 1 milliPascal-second). Crude oil viscosities span eleven orders of magnitude from the lightest condensates (0.1 cP) to the heaviest natural bitumens (10^8 cP, exceeding the viscosity of glass), making viscosity the single physical property with the widest range of values across the spectrum of naturally occurring petroleum fluids. In practical terms, 1 cP is the viscosity of water — so when reservoir engineers say a crude oil has a viscosity of 200 cP, they mean it flows 200 times more slowly than water through the same pore geometry under the same pressure gradient.
What Is Viscosity?
Imagine two parallel plates with fluid between them. Fix the bottom plate and apply a force to the top plate to slide it horizontally. The force required per unit area (shear stress) to maintain a given velocity difference between the plates (shear rate) is proportional to the fluid's viscosity. A thin, runny fluid like gasoline requires very little force to shear — low viscosity. A thick, syrupy fluid like heavy oil requires much more force — high viscosity. The proportionality constant between shear stress and shear rate is the dynamic viscosity mu, and it is one of the most consequential physical properties in oil and gas engineering.
Every flow equation in petroleum engineering contains viscosity — Darcy's law for flow through porous media, the Hagen-Poiseuille equation for pipe flow, the Stokes settling equation for drilled cuttings in the annulus, and the mobility ratio equation for EOR displacement efficiency. Viscosity separates light tight oil (1 to 3 cP, flows easily in fractures) from oil sands bitumen (1,000,000 cP, does not flow without thermal stimulation). It is why natural gas wells produce at rates 10 to 50 times higher per unit of permeability than oil wells. It is why SAGD works — heating bitumen from 10°C to 200°C reduces its viscosity by a factor of 100,000, transforming an immovable solid into a fluid that flows to the production well.
Viscosity Measurement and Control in Drilling Operations
In drilling operations, viscosity is the most frequently measured and managed fluid property on the rig. The Marsh funnel provides a rapid 30-second check of overall mud consistency — a funnel viscosity below 26 seconds suggests the mud may be too thin for adequate cuttings transport, while above 60 seconds suggests the mud is over-treated and pump pressures may be excessive. But the Fann VG meter provides the quantitative rheological data needed for engineering calculations: running at 600, 300, 200, 100, 6, and 3 rpm on the bob-and-sleeve viscometer yields the readings to fit Bingham plastic (PV/YP) or Herschel-Bulkley (K, n, tau_0) parameters. These parameters feed the hydraulics software that calculates ECD, annular velocity, and cuttings transport efficiency — the three linked outcomes that determine whether the wellbore is being drilled cleanly and safely. Maintaining viscosity within target ranges (PV 10 to 30 cP, YP 15 to 30 lb/100 ft2 for most drilling conditions) is the daily task of the mud engineer, who monitors rheology every six hours and treats the system with dispersant (to reduce excess viscosity) or polymer (to build insufficient viscosity) to stay within specification.
Viscosity Applications Across International Oil and Gas Operations
Canada (AER / WCSB): Oil viscosity is the defining technical parameter that separates WCSB's three major resource categories — conventional light and medium oil (less than 10 cP, primary or waterflood production), heavy oil (10 to 10,000 cP, cold production or polymer flooding in Lloydminster-Kindersley-Kerrobert heavy oil belt), and oil sands bitumen (greater than 100,000 cP at reservoir temperature, requiring thermal recovery by SAGD, CSS, or in-situ combustion); AER's Oil Sands Query (OSQ) database and bitumen resource assessments classify deposits by viscosity-based recovery method, and AER's regulatory reporting for SAGD operations requires viscosity data on produced bitumen to monitor reservoir performance and confirm that steam conformance is achieving the viscosity reduction required for commercial production rates; AER's Alberta Oil Sands Technology and Research Authority (AOSTRA) — the precursor to today's Alberta Innovates — defined the technical framework for SAGD development in the 1980s based on steam-induced viscosity reduction as the primary recovery mechanism, making viscosity the foundational property of Canada's largest oil resource.
United States (API / BSEE): API RP 13B-1 and 13B-2 (Recommended Practices for Drilling Fluid Testing) define the standard procedures for measuring drilling fluid viscosity including Marsh funnel, Fann VG meter, and gel strength measurements, ensuring that viscosity reported in US drilling daily reports is comparable across all operators and service companies; the USGS and EIA use crude oil viscosity in their resource classification systems, with tight oil reservoirs in the Permian Basin, Eagle Ford, and Bakken classified as light oil (1 to 5 cP) in contrast to heavy oil resources in California's San Joaquin Valley (Midway-Sunset, Cymric fields) where reservoir oil viscosities of 1,000 to 10,000 cP require steam stimulation, cyclic steam injection, or steamflooding; BSEE's production safety systems regulations for offshore production facilities include requirements for viscosity monitoring on produced fluids to detect flow assurance risks including wax deposition (crude oil viscosity increasing sharply below the wax appearance temperature, WAT) and asphaltene precipitation that can cause sudden viscosity increases and flowline plugging in subsea tieback systems.