Undersaturated Fluid

Key Takeaways

• The bubble point pressure is the defining characteristic of an undersaturated oil system and determines how much reservoir energy is available before the free gas drive mechanism begins — the bubble point of a reservoir fluid is measured by laboratory PVT (pressure-volume-temperature) analysis of a recombined reservoir fluid sample, using a series of controlled pressure depletions in a visual PVT cell to identify the pressure at which the first small bubble of gas forms in the liquid; for an undersaturated reservoir with initial pressure of 5,000 psi and a bubble point of 3,000 psi, the 2,000 psi of undersaturation represents a buffer of liquid compressibility drive that can be produced before the reservoir begins to experience the complications of a two-phase system (reduced oil relative permeability as gas saturation builds, GOR increases, gas coning toward producing wells); the undersaturation pressure also determines whether water injection can maintain the reservoir above the bubble point — injecting water to maintain reservoir pressure above the bubble point keeps the reservoir undersaturated and preserves the high oil relative permeability and single-phase flow conditions that maximize oil recovery; waterfloods that maintain reservoir pressure well above bubble point consistently achieve higher recovery factors than floods that allow the reservoir to deplete below bubble point before injection begins.
• Compressibility-driven production from an undersaturated oil reservoir is governed by the total compressibility of the reservoir system — in an undersaturated oil reservoir, the primary drive mechanisms are the expansion of the oil itself (oil compressibility, typically 10-20 x 10-6 per psi for medium-gravity crude), the expansion of formation water in the reservoir and in connected aquifers (water compressibility, approximately 3 x 10-6 per psi), and the expansion of the rock pore volume (pore compressibility, typically 2-10 x 10-6 per psi depending on burial depth and cementation); these compressibilities are small — a 100 psi pressure decline in 100 million barrels of reservoir fluid expands the system by only about 100-200 barrels — meaning that the primary drive mechanism in an undersaturated reservoir is its depletion drive, which can drain significant reserves but requires large pressure declines to produce appreciable volumes; the material balance equation for an undersaturated reservoir relates the pressure decline to the cumulative production through the total compressibility term, allowing the engineer to estimate original oil in place from the pressure-production history and to predict future production rates at various depletion scenarios.
• Undersaturated gas condensate reservoirs (where the initial reservoir pressure exceeds the dew point pressure of the retrograde condensate system) represent some of the most valuable and most technically demanding resources in petroleum engineering — a gas condensate reservoir is undersaturated if the reservoir pressure is above the dew point at reservoir temperature, meaning no liquid condensate has dropped out of the gas phase at initial conditions; as the reservoir is produced and pressure declines below the dew point, retrograde condensation occurs — liquid condensate forms in the reservoir rock, filling pore space and potentially reducing gas relative permeability; the condensate that drops out in the reservoir is essentially unrecoverable without gas recycling (reinjecting lean gas after stripping the condensate at surface, to maintain reservoir pressure above the dew point and prevent liquid dropout); the degree to which a gas condensate reservoir is undersaturated (the initial pressure minus the dew point) determines how much production can occur before the retrograde condensation begins and how much of the valuable condensate liquids can be recovered before they become stranded in the reservoir by permeability reduction from liquid saturation buildup.
• Well deliverability in undersaturated oil reservoirs benefits from the high oil relative permeability and low viscosity that single-phase flow conditions provide — in an undersaturated oil reservoir, the entire pore space available for flow is occupied by single-phase oil (plus irreducible water saturation), giving oil a relative permeability approaching 1.0 at the irreducible water saturation; this maximum relative permeability condition means that the pressure drawdown required to achieve a given production rate is at its minimum for the given absolute permeability; when the reservoir falls below bubble point and gas saturation develops, the oil relative permeability decreases rapidly as gas occupies increasing fractions of the pore space, and the flowing wellbore pressure required to produce the same oil rate increases significantly; this is why wells in undersaturated reservoirs typically have better initial productivity indices (PI, in barrels per day per psi of drawdown) than their below-bubble-point equivalents, and why maintaining reservoir pressure above the bubble point through water or gas injection preserves both the recovery factor and the well productivity over the life of the field.
• EOR methods for undersaturated oil reservoirs emphasize pressure maintenance to preserve single-phase flow rather than the phase-behavior manipulation used in saturated reservoir EOR — miscible gas injection (CO2 flooding or hydrocarbon gas flooding) in an undersaturated reservoir can achieve first-contact miscibility if the injection gas composition and pressure are above the minimum miscibility pressure for the specific crude, creating a true single-phase miscible displacement with theoretically 100% displacement efficiency in the contacted rock volume; this is more easily achieved in undersaturated reservoirs where the high pressure means the oil is already at conditions close to those required for miscibility with injected CO2 or natural gas; polymer flooding (injecting high-viscosity polymer solution to improve the mobility ratio of the waterflood) is another EOR method applicable to undersaturated viscous oil reservoirs where the oil viscosity is high enough to cause poor waterflood sweep; the selection between EOR methods for an undersaturated reservoir depends primarily on the oil viscosity (lower viscosity oils favor miscible gas; higher viscosity oils favor polymer or thermal methods), the reservoir heterogeneity, and the available injectant supply (CO2 source, natural gas supply, or water availability).