Microbial enhanced oil recovery

After primary production and waterflooding, typically more than half the oil in a reservoir stays underground — bypassed in unswept channels or capillary-trapped as droplets in individual pores. Microbial enhanced oil recovery proposes the cheapest possible reagent for mobilising it: a microbial consortium, injected with nutrients, that manufactures its recovery chemicals in place.

Why oil stays in the ground

Capillary trapping is a force balance. Oil droplets sit in pore throats, held by the interfacial tension between crude and brine — tens of millinewtons per metre. Mobilising them means raising the capillary number, the ratio of viscous to capillary forces, by orders of magnitude; in practice that means cutting interfacial tension toward the 0.01–0.001 mN/m range or flipping wettability so water pushes rather than bypasses. Conventional surfactant flooding does this with imported chemicals, and the chemicals plus their delivery dominate the cost. MEOR’s wager is that the reservoir can be turned into its own chemical plant.

The in-situ toolkit

The consortium’s products map onto the physics one-to-one. Biosurfactants — lipopeptides and glycolipids such as surfactin and rhamnolipids — drop interfacial tension at concentrations where shipping synthetic surfactants would be uneconomic. Biomass growing preferentially in high-permeability streaks plugs them and redirects the waterflood into rock that has never been swept — heterogeneity used as a tool instead of fought. Fermentation gas, mostly CO2 and nitrogen, re-pressurises the near-well region and dissolves into the oil, swelling it and cutting viscosity; fermentation solvents and light acids adjust viscosity and wettability. All of it happens kilometres below any valve, at reservoir temperature, pressure and salinity.

Why control is the real limit

That distance is also the problem. A reservoir is a black box between two wells: temperatures above what most cultured strains tolerate, salinity and pH unmeasured, nutrients distributed by convection nobody controls. Injected consortia compete with a native microbiome that has been adapting to that rock for millions of years. The response reads out only as the production curve, months later, confounded with every operational change in between — attribution is statistical, never instrumental. The failure mode mirrors the mechanism: the same uncontrolled growth that plugs a thief zone can sour a reservoir, as sulfate-reducing bacteria convert injected sulfate into hydrogen sulfide that corrodes steel and downgrades the crude. Hence the honest profile: low capital, probabilistic outcome, worked where screening fits — moderate temperature and salinity — and thin as a commercial field, with much of the practice kept as in-house programmes of national oil companies.