Non-Newtonian Fluid | Oil Authority

A non-Newtonian fluid is any fluid whose viscosity is not constant across all shear rates — meaning the ratio of shear stress to shear rate changes depending on how fast the fluid is being deformed, in contrast to a Newtonian fluid (such as water or light crude oil) where viscosity is a fixed material constant independent of shear rate; virtually all successful water-based and oil-based drilling fluids are deliberately engineered to be non-Newtonian because the combination of high viscosity at low shear rates (which suspends drill cuttings and weighting materials when circulation stops) with low viscosity at high shear rates (which allows the fluid to be pumped through the drillstring and bit jets with acceptable pressure losses) cannot be achieved with Newtonian rheology; the principal rheological models used to characterize non-Newtonian drilling fluids are the Bingham plastic model (two parameters: plastic viscosity PV in mPa·s and yield point YP in Pa), the power-law model (two parameters: consistency index K and flow behavior index n), and the Herschel-Bulkley model (three parameters: yield stress tau_0, consistency index K, and flow index n), with the Herschel-Bulkley model being the most physically accurate for most modern muds because it correctly represents both the finite yield stress that keeps cuttings suspended at rest and the shear-thinning behavior that reduces pumping friction at drilling flow rates.

Key Takeaways

Shear-thinning pseudoplastic behavior is the target property for drilling fluid design because it simultaneously satisfies the two competing rheological requirements of a drilling fluid — the fluid must be thin enough to pump through small-diameter bit nozzles and drillstring connections at high velocities (where shear rates may reach 10,000 to 100,000 s-1) without exceeding the maximum allowable equivalent circulating density that would fracture the formation, and yet thick enough at annular shear rates of 5 to 100 s-1 to lift cuttings from the bottomhole to the surface with acceptable slip velocities; in a Bingham plastic approximation, the plastic viscosity PV (measured by the difference between the 600 rpm and 300 rpm readings on a Fann viscometer multiplied by 1 cP per unit) characterizes the high-shear flow resistance, while the yield point YP (300 rpm reading minus PV) characterizes the low-shear gel-forming tendency, and the yield point-to-plastic viscosity ratio YP/PV is a practical design target that should stay below 1.5 to 2.0 to avoid excessive pressure surges during pipe connections and below 0.3 to 0.5 to avoid inadequate hole cleaning in highly deviated wells.
Gel strength is the time-dependent component of non-Newtonian behavior in drilling fluids that is distinct from the steady-state flow curve described by Bingham plastic or power-law models — gel strength represents the static yield stress that develops when the fluid is left undisturbed (at rest during a pipe connection, a survey, or a wiper trip) as colloidal clay platelets and polymer chains form a loose three-dimensional network; gel strength is measured at 10 seconds (initial gel, IGS) and 10 minutes (progressive gel, PGS) after agitation using a Fann viscometer at 3 rpm and reported in pounds per 100 square feet; progressive gels that are significantly higher than initial gels (fragile or thixotropic gels, PGS/IGS > 1.5) are problematic because they require high surge pressures to break circulation after a connection and can cause formation fracture in tight pressure-window wells; flat or linear gels where PGS is approximately equal to IGS indicate a robust non-progressive mud that will break circulation without pressure spikes, which is the design target for deepwater and HPHT wells where fracture gradient margins may be as narrow as 0.5 ppg.
Herschel-Bulkley model provides the most physically rigorous description of drilling fluid non-Newtonian behavior and is required for accurate equivalent circulating density calculations in HPHT and deepwater wells where the Bingham plastic approximation introduces pressure prediction errors of 5 to 15 percent — the Herschel-Bulkley equation is tau = tau_0 + K × gamma^n, where tau is shear stress in Pa, tau_0 is the yield stress in Pa (the minimum stress required to initiate flow, analogous to the yield point in the Bingham model but more precisely defined as the true no-flow threshold), K is the consistency index in Pa·s^n (related to overall viscosity level), and n is the flow index (dimensionless, 0 to 1 for shear-thinning fluids with n=1 reducing to the Bingham plastic and n=1 with tau_0=0 giving Newtonian behavior); fitting Herschel-Bulkley parameters requires three or more viscometer readings (typically 3, 100, 300, and 600 rpm), and modern hydraulics simulation software (Landmark WELLPLAN, Halliburton WellPlan, Weatherford Magnus) performs the Herschel-Bulkley regression and integrates the non-Newtonian pressure gradient equations to predict ECD profiles within ±0.1 to 0.2 ppg accuracy in vertical wells and ±0.2 to 0.4 ppg in highly deviated wells.
Dilatant or shear-thickening non-Newtonian behavior (viscosity increases with shear rate) is highly undesirable in drilling fluids and indicates a mud system that is out of specification — dilatant behavior can result from over-treatment with certain polymers (high concentrations of rigid-rod biopolymers like xanthan gum at low water activity), from excessive barite sag creating a high-solids pack, or from colloidal interparticle repulsion being overwhelmed by high-shear compression in narrow annular gaps; a dilatant mud will cause pump pressure spikes during bit jet acceleration, may lock up the annulus in narrow clearance sections, and produces flow-dependent pressure surges that complicate kick detection; rheology trending toward dilatancy (300 rpm reading approaching or exceeding 600 rpm reading on the Fann viscometer) is a maintenance alarm that requires immediate treatment with deflocculant (such as SAPP or lignosulfonate) or dilution with base fluid to restore shear-thinning character before continuing drilling operations.
Completion and workover fluids, cement slurries, and hydraulic fracturing fluids are also engineered as non-Newtonian systems for specific operational reasons — hydraulic fracturing fluids use viscoelastic surfactant or crosslinked polymer gels (polyacrylamide or guar-based) whose non-Newtonian properties allow them to suspend proppant at low shear rates in the fracture while breaking to low viscosity (triggered by a breaker additive) after the treatment so the fluid can flow back without trapping the proppant; cement slurries are designed as Bingham plastic fluids with sufficient yield point to prevent free water separation but with low plastic viscosity to allow displacement by pumping; these non-Newtonian fluid design principles are shared across all downhole fluid systems and the same Fann viscometer measurements and rheological model parameters are used across drilling, cementing, and stimulation fluid engineering.

Fast Facts

The classification of drilling mud as a non-Newtonian fluid was formalized in the 1940s when the Bingham plastic model, developed by Eugene Bingham in 1916 for paint rheology, was adapted to describe drilling mud behavior by Melrose, Savins, and others at mid-century. The Fann VG meter (variable-speed viscometer), introduced in the 1950s and standardized by API RP 13B, measures mud viscosity at 600, 300, 200, 100, 6, and 3 rpm bob speeds corresponding to shear rates of approximately 1022, 511, 341, 170, 10.2, and 5.1 s-1 — providing enough data points to fit Bingham plastic, power-law, and Herschel-Bulkley parameters from a single instrument. The 600/300 rpm readings remain the most commonly reported field measurements despite the availability of multi-speed readings, because the Bingham plastic calculation (PV = R600 - R300; YP = R300 - PV) requires only two values and provides sufficient accuracy for most routine mud engineering decisions. In deepwater wells where the pressure window between pore pressure and fracture gradient may be as narrow as 0.1 to 0.3 ppg, the additional precision of the Herschel-Bulkley model is operationally critical, driving adoption of full six-speed Fann measurements and computerized hydraulics models as standard practice in deepwater drilling programs.

What Is a Non-Newtonian Fluid?

Isaac Newton's viscosity law states that shear stress is proportional to shear rate with a constant proportionality factor (the dynamic viscosity). Water, glycerol, and most simple liquids follow this law — double the shear rate and you double the force required to shear the fluid, regardless of how fast or how long you have been shearing. These are Newtonian fluids. Non-Newtonian fluids violate this simple proportionality in one or more ways: viscosity may decrease with increasing shear rate (shear-thinning or pseudoplastic behavior), increase with increasing shear rate (shear-thickening or dilatant behavior), require a minimum stress before flow begins at all (yield stress or Bingham behavior), or change with time at constant shear rate (thixotropic or rheopectic behavior).

Drilling fluids exploit non-Newtonian behavior by design. The same fluid that flows easily through bit nozzles at 150 gpm must also hold a 19-pound drill collar in suspension when circulation is stopped for a 30-minute pipe connection. No Newtonian fluid can do both. By engineering the mud with colloidal clay platelets, polymer chains, and electrostatic charge management, fluid designers create a material that thins dramatically as shear rate increases (pseudoplastic behavior) and builds a gel structure progressively during rest periods. The result is a fluid that is simultaneously pumpable, cuttings-transporting, and suspension-stable — properties that are incompatible in any Newtonian system.

Rheological Models for Drilling Fluid Non-Newtonian Behavior

Three mathematical models dominate drilling fluid rheology characterization and hydraulics calculation. The Bingham plastic model adds a yield stress tau_y to the Newtonian equation: tau = tau_y + PV × gamma, where PV is plastic viscosity and gamma is shear rate. This two-parameter model fits most bentonite-water muds reasonably well at moderate shear rates but overestimates low-shear viscosity, causing it to predict higher ECD values than actually occur in the annulus at typical 20 to 80 s-1 annular shear rates. The power-law model uses tau = K × gamma^n (no yield stress), where n less than 1 gives shear-thinning behavior. The power-law model accurately represents the high-shear behavior of polymer-based muds but underestimates pressure near the wellbore where yield stress effects dominate at low flow velocities in large-diameter sections. The Herschel-Bulkley model combines both: tau = tau_0 + K × gamma^n, capturing yield stress, consistency, and shear thinning with three parameters fit from five or six viscometer speeds. For horizontal wells in deepwater plays where ECD management is critical, Herschel-Bulkley is the required model, and deviation from Herschel-Bulkley predictions of more than 0.1 ppg is treated as a mud quality excursion requiring investigation.

Non-Newtonian Fluid Design in Global Deepwater Operations

Canada (AER / WCSB): AER's Directive 008 (Wellbore Caliper Surveys) and associated drilling reporting requirements for WCSB wells specify that mud properties including plastic viscosity, yield point, and gel strengths at 10 seconds and 10 minutes be recorded in the well completion report for all wells using weighted mud systems; the non-Newtonian rheology data is used by AER engineering staff to verify that the mud program was capable of providing adequate wellbore integrity (preventing kicks through sufficient gel strength) and formation protection (preventing lost circulation through excessive ECD from overly viscous muds); in WCSB Montney and Duvernay horizontal drilling where ERD wells extend 2,000 to 3,000 meters horizontally from vertical, cuttings transport modeling using Herschel-Bulkley parameters is required by major operators (Tourmaline, ARC Resources, Birchcliff) to verify that annular velocity and rheology are sufficient to maintain solids transport above the critical transport velocity in the horizontal section and prevent packoff.

United States (API / BSEE): API Recommended Practice 13B-1 (Water-Based Drilling Fluids) and 13B-2 (Oil-Based Drilling Fluids) define the standard measurement procedures for Fann VG meter readings, gel strength, and derived rheological parameters used to characterize the non-Newtonian properties of all drilling muds used in US wells; BSEE's offshore regulatory framework for Gulf of Mexico deepwater wells requires that drilling programs submitted for approval include a hydraulics analysis demonstrating that ECD will remain within the fracture gradient throughout all drilling phases, with the analysis based on Fann viscometer data and a documented rheological model consistent with API 13B standards; the API/BSEE regulatory framework does not mandate a specific rheological model (Bingham, power-law, or Herschel-Bulkley) but requires that the model used be appropriate for the mud type and that ECD predictions be validated against measured standpipe pressure during drilling to confirm model accuracy within ±3 to 5 percent.