Mobility: Effective Permeability over Viscosity, Multiphase Mobility Ratio, and WCSB Reservoir Productivity

Mobility in reservoir engineering is the ratio of the effective permeability of a phase to the viscosity of that phase, written as M = k_eff / mu, with units of millidarcy per centipoise (mD/cP) in field practice or m^2/(Pa s) in SI. For a single-phase reservoir the term reduces to absolute permeability divided by phase viscosity; in a multiphase system, where oil, water, and gas occupy the same pore space, each phase has its own mobility computed from its relative permeability (k_r times absolute k) divided by its in-situ viscosity. Total mobility is the sum of the individual phase mobilities, and well productivity, in the inflow performance relationship that underlies every Darcy-flow productivity index calculation, is directly proportional to the product of total mobility and the net pay thickness (the k h / mu term). Mobility is therefore the single physical quantity that ties together rock quality, fluid quality, and saturation history into a number that predicts how readily a reservoir will deliver hydrocarbons to a wellbore. In the Western Canadian Sedimentary Basin, mobility numbers span an enormous range. A clean Cardium tight oil reservoir at Pembina may have an effective oil permeability of 0.4 mD against an in-situ oil viscosity of 0.8 cP, giving an oil mobility of 0.5 mD/cP. A Montney liquids-rich shale at Karr or Gold Creek may have effective gas permeability of 0.0002 mD against a gas viscosity of 0.022 cP, giving 0.009 mD/cP, two orders of magnitude lower and the reason why hydraulic fracturing is mandatory in those rocks. At the opposite extreme, a McMurray heavy oil sand in the Athabasca region may have a permeability of 4,000 mD against a bitumen viscosity of 800,000 cP, giving an oil mobility of just 0.005 mD/cP, which is why Cenovus Energy, Suncor Energy, and other operators deploy SAGD steam injection to reduce bitumen viscosity by four orders of magnitude and bring the in-situ mobility back into a producible range. The mobility ratio M_ratio, defined as the mobility of the displacing phase divided by the mobility of the displaced phase, is the central control on every secondary and tertiary recovery scheme: an M_ratio greater than 1 means the displacing fluid moves faster than the displaced fluid and produces viscous fingering, early breakthrough, and poor sweep efficiency, while an M_ratio less than 1 yields a stable displacement front. Mobility also controls injectivity, fall-off interpretation, transient pressure analysis, and inter-well interference patterns, making it the master variable in reservoir engineering and a required input in every COGE Handbook compliant reserves classification under NI 51-101.

Single-Phase Versus Multiphase Mobility

In a single-phase reservoir, mobility reduces to absolute permeability divided by viscosity and is straightforward to estimate from a core plug measurement plus a PVT viscosity correlation. In multiphase flow, each phase has its own effective permeability dictated by saturation, wettability, and capillary pressure, and the relative permeability curves (oil-water and gas-oil) come from special core analysis (SCAL) on preserved or restored-state core. A Cardium oil reservoir at 60% oil saturation may show k_ro = 0.4 (relative oil permeability), giving k_eff_oil = 0.4 times absolute k, while k_rw at the same saturation may be 0.05, making oil mobility roughly eight times water mobility at that point and dictating waterflood timing decisions.

Mobility Ratio and Sweep Efficiency

The mobility ratio M_ratio determines whether a displacement front advances stably or develops viscous fingers. A waterflood in a Cardium sand at 0.8 cP oil viscosity and 0.4 cP water viscosity, with comparable effective permeabilities, gives M_ratio near 0.5 (favourable, stable front). A waterflood in a heavy oil sand with 200 cP oil and 0.5 cP water gives M_ratio near 400, producing severe fingering and water cycling. Polymer flooding raises injected water viscosity to 30 to 60 cP, dropping the ratio back below 5 and recovering 8% to 14% incremental original oil in place per Saskatchewan pilot results documented by SK Ministry of Energy and Resources.

Related Terms

Mobility connects directly to several core reservoir parameters. Permeability is the rock-flow component of mobility and is measured in millidarcy on core plugs or back-calculated from well tests; without it, no mobility number can be defined. Viscosity is the fluid-flow component and is measured on PVT samples or estimated from correlations, with reservoir temperature and dissolved gas content driving most of the in-situ value. Relative permeability is the saturation-dependent multiplier that turns absolute permeability into effective permeability for each phase in a multiphase flow.

Real-World WCSB Scenario: Polymer Flood Mobility Match at a Pembina Cardium Pilot

A Pembina Cardium operator launched a 2-pattern polymer flood pilot covering 64 hectares to lift recovery factor in a previously waterflooded zone. Pre-pilot mobility ratio was estimated at 8.4 (oil viscosity 1.2 cP, water viscosity 0.45 cP, k_ro/k_rw near 3.1), giving high fingering risk. The injection design used a 35 cP HPAM polymer solution at 1,200 ppm concentration, billed at CAD 2,800 per tonne for the dry polymer plus CAD 18 per m3 mixing cost, with a total Year 1 chemical budget of CAD 1.6 million.

Six months of bottomhole pressure and tracer data history-matched the post-flood mobility ratio at 1.8, well inside the favourable window. Incremental oil response averaged 32 m3/d per pattern above the pre-polymer baseline, totalling CAD 4.6 million in Year 1 net revenue at the WTI prices prevailing, and the project advanced to a 12-pattern expansion under AER Directive 051 scheme approval the following year.