Category Archives: Reservoir Fundamentals

Single-Phase Gas Reservoirs

Section 4 of the online course in Applied Petroleum Reservoir Engineering. Dr. Ron Terry discusses Single-Phase Gas Reservoirs, calculating hydrocarbon in place using two methods: through geological and geophysical data and through the material balance.

More information on the online course is available here.

Formation of Petroleum Reservoirs

The formation of petroleum reservoirs occurs over millions of years as oil and gas accumulations develop in underground traps formed by structural or stratigraphic geological features. These accumulations usually occur in the more porous and permeable sedimentary rock, where the petroleum molecules seep into the small inter-granular spaces, or in joints and fractures of the rock. The reservoir is the portion of the formation containing oil and gas that is hydraulically connected.

Conventional reservoirs need a source rock, a migration path, a reservoir rock and a cap rock.

The source rock is a rock that is rich in organic matter. These form as algae or other plant and animal life die and are buried in the sand. Over millions of years, these rock formations are covered by other rock formations and the pressure and temperature of the rock increases. The organic matter converts to oil and gas as it is heated.

As the oil and gas forms in the source rock, it begins to migrate through the inter-granular spaces, the joints and the fractures of the rock. The oil and gas molecules are less dense than the rock and water and naturally migrate slowly upward towards the surface.

The molecules continue migrating until they hit cap rock. Cap rock is typically a layer of impermeable rock that lacks the inter-granular spaces the molecules need to continue traveling. It overlays the reservoir rock and forms a trap. At this point, with no where for the molecules to go, and more molecules continuing to migrate out of the source rock, the molecules begin to accumulate in the rock directly below the cap rock – the reservoir rock.

If there is no cap rock, the molecules travel all the way to the surface, resulting in a natural oil seep.

Formation of Petroleum Reservoirs
Hyne, Norman J.: Geology for Petroleum Exploration, Drilling and Production, New York: McGraw-Hill Book Co., 1984

In recent years, unconventional reservoirs have been developed. These unconventional reservoirs are unique in that the source rock is the reservoir rock. No migration path or cap rock is needed, as the oil and gas are produced directly from the source rock where it was generated.


Terry, Ronald E., J. Brandon. Rogers, and B. C. Craft. Applied Petroleum Reservoir Engineering. Third ed. Massachusetts: Prentice Hall, 2014. Print.

Volume Factor

The volume occupied by a given amount of hydrocarbon varies depending on the pressure and temperature. A volume factor is a ratio of the volume at one set of conditions to a set of standard conditions. Typical volume factors include the formation volume factor, two-phase formation volume factor and gas volume factor. We’ll review the single-phase and two-phase volume factors for a specific reservoir fluid.
Visual conception of volume factors for Big Sandy reservoir
The fluid as it exists in a undersaturated oil reservoir is shown in A. At this point, 1.31 barrels is the formation volume factor Bo. Point B could represent a point within the wellbore; the pressure has decreased, but the temperature remains the same resulting in an increase in volume. As the fluid continues up the wellbore the pressure declines further. For the purposes of this illustration we are going to assume it stays at the same temperature. At some pressure between B(2500 psia) and C (1200 psia) the fluid passes the bubble point, and gas begins to break out of solution. This results in a much larger increase in the overall volume occupied and a decrease in the liquid volume. As the fluid reaches atmospheric pressure (D), it expands to its maximum extent and the last traces of gas break out of solution. Finally, at point E, the fluid cools to ambient temperature. The volume of both the liquid and the gas decrease slightly. This same progression is shown in the graph below, starting from the right and moving to the left.
Formation volume factor of bell field vs pressure
A saturated reservoir, meaning a reservoir in which both liquid and gas are present at initial conditions, would start at C rather than at A.

The gas volume factor (Bg) is calculated as follows (for standard conditions of psc is 14.7 psia and Tsc is 60°F):

gas volume factor

where T is temperature, p is pressure and z is the gas compressibility factor.

The two-phase formation volume factor (Bt) is calculated:

two-phase volume factor

where Rsoi and Rso are the initial solution gas-oil ratio and solution gas-oil ratio respectively. The solution gas oil ratio mirror the formation volume factor.
Solution gas ratio for Bell Field vs pressureTerry, Ronald E., J. Brandon. Rogers, and B. C. Craft. Applied Petroleum Reservoir Engineering. Third ed. Massachusetts: Prentice Hall, 2014. Print.

Reservoir Classification

Reservoir Classification is determined by the reservoir fluid’s phase behavior. They are classified into four reservoir types: single phase gas, gas condensate, undersaturated oil and saturated oil reservoirs. The differences in their phase behavior is illustrated in the following diagram.

Two phase diagram of four reservoir types classified by two phase PVT bahvior

We’ll start with a single phase gas reservoir. Point A represents the virgin reservoir. As The reservoir is produced, the fluid inside the reservoir remains at the same temperature, but decreases in pressure and follows the dashed line toward A1. This reservoir never enters the two-phase envelope and as a result, the reservoir is entirely gas throughout its entire life. The produced fluid, on the other hand decreases both in temperature and pressure towards A2. It does enter the two phase envelope and some liquids will be produced.

The retrograde gas condensate reservoirs also start out as gas but at point B. As the fluid is produced the fluid remaining in the reservoir drops into the two phase envelope (B1) and liquids start to be produced in the reservoir. The amount of liquids continue to increase until it reaches B2 and then vaporization of that retrograde liquid in the reservoir begins to occur until it reaches abandonment pressure (B3).

The third, undersaturated reservoirs (also called dissolved gas reservoirs) differ from the first in that the fluid exists as a liquid in the reservoir at initial conditions. As pressure declines (C1), the first bubbles of ‘dissolved’ gas begin to appear (at which point the reservoir is said to be saturated). As pressure continues to drop, the liquid volume in the reservoir decreases and more gas is produced. As oil is the primary product, pressure maintenance strategies in this reservoir type is crucial.

Finally we come to our saturated oil reservoirs. At initial conditions, this reservoir already has both liquid and gas present. These phases have separated overtime due to density differences resulting in a ‘gas cap’ over the reservoir. Typically, the reservoir is produced in the oil zone, allowing the expansion of the gas cap to assist in maintaining a high reservoir pressure.

Terry, Ronald E., J. Brandon. Rogers, and B. C. Craft. Applied Petroleum Reservoir Engineering. Third ed. Massachusetts: Prentice Hall, 2014. Print.