Moveable Hydrocarbons

Key Takeaways

• The moveable hydrocarbon index (MHI) derived from wireline log analysis is calculated as one minus the ratio of the flushed zone water saturation (Sxo) to the undisturbed formation water saturation (Sw): MHI = 1 - (Sw/Sxo); a high MHI (approaching 1.0) indicates that the drilling fluid filtrate has effectively displaced the hydrocarbons in the flushed zone, suggesting that the hydrocarbons are mobile and that production is likely to be predominantly hydrocarbon with limited formation water; a low MHI indicates minimal filtrate displacement, suggesting either that the hydrocarbons are immobile (too viscous, too low saturation, or in too tight a rock to flow), that the formation contains predominantly water rather than hydrocarbons, or that the invasion profile has not differentiated enough for the comparison to be meaningful; the MHI must be interpreted with knowledge of the mud filtrate invasion characteristics, the formation fluid viscosity, and the permeability of the formation, because a tight formation may have the same low MHI as a water-bearing formation simply because neither water nor hydrocarbon displaced effectively during the short time of drilling and logging.
• Critical oil saturation (So_cr) is the threshold oil saturation below which oil becomes discontinuous in the pore network and loses its relative permeability, making the remaining oil immoveable regardless of the pressure differential applied: at very low oil saturations, the oil occupies isolated ganglia in individual pores rather than forming a connected network through the pore throats, and without pore-throat connectivity there is no flow path for oil to move through the rock; the critical oil saturation in carbonate reservoirs with complex pore geometry may be higher (15-25%) than in well-sorted sandstones (5-15%) because the heterogeneous pore structure creates many isolated oil ganglia at intermediate saturations; the economic consequence of critical saturation is that it defines the practical lower limit of oil recovery by any depletion mechanism, and understanding the critical saturation of a specific reservoir is essential for setting realistic recovery factor expectations and for evaluating whether enhanced oil recovery methods (surfactant flooding, miscible injection) that reduce interfacial tension and mobilize residual oil ganglia are economically justified.
• The relationship between moveable hydrocarbons and relative permeability is fundamental to production performance prediction: the relative permeability to oil (kr_o) at the initial water saturation defines how easily oil moves through the rock at reservoir conditions without water cut, while the relative permeability to oil at higher water saturations (after partial water displacement by production or injection) defines how much oil mobility remains as the water saturation increases during the producing life; the crossover point of the oil and water relative permeability curves (where kr_o equals kr_w) is the saturation at which water and oil contribute equally to total flow, and this point determines the water-oil ratio at which water handling costs begin to exceed oil revenue for typical production economics; formations with sharply curved relative permeability curves (high irreducible water saturation, low critical oil saturation, and rapid transition from oil-dominated to water-dominated flow) produce oil efficiently in early life but transition abruptly to high water cut, leaving a relatively small fraction of the original oil in place as unrecoverable residual oil.
• Heavy oil and bitumen reservoirs contain hydrocarbons that are technically present in the pore space but not moveable under primary depletion conditions because the oil viscosity (which can exceed 10,000 centipoise or even 1 million centipoise for bitumen) makes the pressure gradient required to flow the oil through the reservoir at economic rates physically impossible without thermal stimulation: the mobility of oil is defined as the ratio of relative permeability to viscosity, and the extremely high viscosity of heavy oil reduces its mobility to near zero at reservoir temperature; thermal EOR methods (SAGD, CSS huff-and-puff, fireflood) convert this immoveable heavy oil into moveable oil by reducing its viscosity by orders of magnitude through heating; bitumen in the Alberta oil sands with a natural viscosity of 1-5 million centipoise at reservoir temperature (8-12°C) becomes freely flowing at 100-200 centipoise when heated to 200-240°C by steam injection, transforming a practically immoveable resource into one of the most producible in the world.
• The distinction between moveable and non-moveable hydrocarbons has different implications for reserve classification under the Society of Petroleum Engineers (SPE) Petroleum Resources Management System (PRMS): proved reserves (1P) must be hydrocarbons that are reasonably certain to be commercially recovered under existing economic conditions and existing technology, which requires the hydrocarbons to be moveable at a rate that generates positive net cash flow at current commodity prices; proved developed producing (PDP) reserves represent the highest-confidence subset of hydrocarbons that are already flowing from open wells; proved developed non-producing (PDNP) reserves include moveable hydrocarbons behind pipe or in shut-in zones; the PRMS explicitly excludes immoveable residual hydrocarbons from all reserve categories, limiting reserves to the moveable fraction plus any residual oil that can be mobilized by specifically planned and economically viable EOR projects; understanding which part of the hydrocarbon in place is moveable (and at what cost) is therefore the foundational technical question in any reserve determination exercise.