drainage, Oil & Gas Glossary

What Is Drainage in Reservoir Engineering?

Drainage is the displacement process in which the wetting phase saturation decreases within a porous medium — oil (non-wetting) displacing water (wetting phase) during reservoir charging, or gas (non-wetting) displacing oil during gas cap expansion or gas injection. Drainage is the opposite of imbibition (wetting phase saturation increasing). During drainage, the non-wetting phase must overcome capillary entry pressure to invade pore throats — it preferentially enters the largest throats first, where entry pressure is lowest. Drainage governs the initial distribution of hydrocarbons in a reservoir (original oil saturation established when oil migrated into the trap), controls gas-oil displacement during blowdown and gas injection EOR, and determines the shape of drainage relative permeability and capillary pressure curves used in reservoir simulation.

Key Takeaways

Drainage is non-wetting phase displacing wetting phase — in a water-wet reservoir, this means oil or gas displacing water; capillary forces resist drainage (must be overcome by buoyancy or injection pressure).
During geological reservoir charging, buoyancy pressure from the hydrocarbon column drives drainage — oil migrates into trap pore space, displacing water downward.
Capillary entry pressure (Pc = 2σ cosθ / r) must be exceeded before the non-wetting phase can invade a pore throat of radius r — this entry pressure determines the height of the oil column above free water level.
Drainage relative permeability and capillary pressure curves differ from imbibition curves (hysteresis) — reservoir simulators require both curve sets for processes that include both drainage and imbibition cycles.
Irreducible water saturation (Swi or Swirr) is the minimum water saturation achievable by drainage — water remains in the smallest pores and as thin films on grain surfaces even after complete drainage.

Drainage in Reservoir Charging and Production

The initial saturation state of a hydrocarbon reservoir is established by primary drainage: the geological process by which buoyant oil or gas migrates upward into a structural or stratigraphic trap, displacing connate water from the pore space. The final irreducible water saturation (Swi) is controlled by capillary forces in the smallest pores — water held in micropores and as wetting films on grain surfaces that buoyancy cannot displace. In water-wet rocks, Swi is typically 10–30% of pore volume. The oil saturation at discovery conditions is therefore So = 1 - Swi in the pay zone above the free water level.

During production, drainage occurs wherever gas expands into oil-saturated rock: during primary depletion below bubble point (solution gas drive releases gas bubbles that grow and displace oil by drainage); during gas cap expansion (gas cap grows downward into the oil column); and during gas injection EOR (injected gas displaces oil downward). Gas-oil drainage produces a gas relative permeability function (krg) that is typically steep — gas mobility rises sharply once gas saturation exceeds critical gas saturation (Sgc), the threshold above which gas becomes mobile. Below Sgc, gas remains immobile in isolated bubbles and contributes no flow but does reduce oil relative permeability.

Fast Facts: Drainage

Definition: wetting phase saturation decreasing; non-wetting phase invading
Water-wet system example: oil (non-wetting) displacing water (wetting) during geological charging
Capillary pressure sign: positive during drainage in water-wet rock (capillary forces resist non-wetting invasion)
Pore invasion sequence: largest pores first (lowest entry pressure), smallest pores last
End state: irreducible water saturation (Swi) — water in smallest pores, capillary-held
Critical gas saturation (Sgc): gas saturation below which gas is immobile; typically 2–10% PV
Geological process: primary drainage — hydrocarbon charging of trap
Hysteresis: drainage kr/Pc curves differ from imbibition — both needed in simulation

Reservoir Engineering Tip:

Ensure your reservoir simulation model includes both drainage and imbibition relative permeability and capillary pressure tables when simulating a WAG (water-alternating-gas) injection project or a field undergoing blowdown below bubble point followed by water injection. In WAG, the reservoir undergoes alternating drainage (gas cycle) and imbibition (water cycle) — using imbibition-only kr curves for both cycles overestimates water relative permeability during the gas cycle and underestimates trapped gas saturation (the Land trapping model quantifies how much gas is hysteretically trapped by imbibition after drainage). The trapped gas saturation reduces oil relative permeability significantly and is one of the main reasons WAG pilot incremental recovery differs from waterflood-only predictions. The simulation will not honour the data without both curve sets programmed with hysteresis.

Drainage is also referred to as:

Primary drainage — the geological process of hydrocarbon emplacement into a water-bearing trap; the first drainage cycle any reservoir rock experiences
Secondary drainage — drainage occurring after at least one imbibition cycle, such as gas re-injection into a waterflooded reservoir
Desaturation — the reduction of wetting-phase saturation; used in some petrophysical and EOR contexts
Forced drainage — drainage driven by external pressure gradient (injection pressure) rather than capillary suction; contrasted with spontaneous imbibition which is capillary-driven

Frequently Asked Questions About Drainage

What determines the irreducible water saturation in a reservoir?

Irreducible water saturation (Swi) is controlled by pore size distribution and wettability. In water-wet rocks, water occupies the smallest pores and coats grain surfaces as a thin wetting film — these locations are inaccessible to buoyancy-driven oil because the capillary pressure required to invade them exceeds the available hydrocarbon column height. Rocks with a broad pore size distribution (fine-grained sands, siltstones) have higher Swi than rocks with uniform large pores (coarse-grained beach sands, oolite grainstones) because a larger fraction of pore volume is in small pores where water is capillary-trapped. Swi correlates inversely with permeability (tight rocks have high Swi) and can be estimated from mercury injection capillary pressure (MICP) data or from NMR T2 measurements. In highly cemented tight gas sands, Swi can exceed 50% pore volume — leaving only 50% of total porosity available for gas.

How does drainage relate to the transition zone between free water level and oil-water contact?

The transition zone (or oil-water contact zone) is the region where oil saturation increases from zero at the free water level (FWL) upward toward the irreducible water saturation (Swi) at the base of the clean pay zone. In the transition zone, both oil and water are mobile — oil saturation is below Swi and capillary forces (height-dependent) partially support both fluids. The height of the transition zone above FWL depends on capillary pressure: Pc = Δρ × g × h, where Δρ is the oil-water density difference, g is gravity, and h is height above FWL. Tight rocks (high Pc) have thick transition zones (tens of metres); high-permeability rocks (low Pc) have thin transition zones (a few metres). Wells drilled in the transition zone produce both oil and water — the water is not injected water but connate water mobilised from pores above Swi. This capillary-controlled water production is often misinterpreted as premature water breakthrough.

What is critical gas saturation and why does it matter for reservoir simulation?

Critical gas saturation (Sgc) is the minimum gas saturation at which gas becomes a mobile phase — below Sgc, gas exists as isolated, immobile bubbles dispersed in the oil phase. Sgc is typically 2–10% pore volume for solution gas drive reservoirs and is measured in PVT laboratories during constant composition expansion tests. In reservoir simulation, Sgc must be set correctly in the gas relative permeability table — if Sgc is set to zero, the simulator will mobilise gas immediately when it nucleates (overpredicting gas production rate and underpredicting oil recovery during the solution gas drive stage). If Sgc is too high, gas production onset will be delayed artificially. Incorrect Sgc is one of the more common but subtle reservoir simulation calibration errors — it shows up as mismatch between simulated and actual GOR evolution in the early blowdown period below bubble point.

Why Drainage Matters in Oil and Gas

Drainage is as fundamental to reservoir engineering as imbibition — the two processes together define the full range of fluid displacement that occurs throughout a reservoir's producing life. From the geological charging of a trap (primary drainage establishing initial oil saturation) to blowdown production below bubble point (solution gas drive as drainage), to gas injection EOR cycles that alternate drainage and imbibition, every stage of reservoir production involves drainage at some scale. Correct drainage relative permeability and capillary pressure measurements — on native or restored-state core, at reservoir conditions — are essential inputs to any reservoir simulation that attempts to predict recovery from gas injection, blowdown, or WAG processes. Overlooking drainage curves in favour of imbibition-only simulation models is a systematic error that can significantly misrepresent recovery potential in gas-cap drive and gas injection development scenarios.

Drainage: Definition, Capillary Displacement, and Reservoir Charging