Reservoir Estimation -Material
Balance
Material Balance Estimation
• Material balance analysis is an interpretation method
used to determine original fluids-in-place (OFIP) based on
production and static pressure data.
• The general material balance equation relates the original
oil, gas, and water in the reservoir to production volumes
and current pressure conditions / fluid properties.
• The material balance equations considered assume tank-
type behavior at any given datum depth — the reservoir
is considered to have the same pressure and fluid
properties at any location in the reservoir. This
assumption is quite reasonable provided that quality
production and static pressure measurements are
obtained.
• Consider the case of the depletion of the reservoir shown
below. At a given time after the production of fluids from
the reservoir has commenced, the pressure drops from
its initial reservoir pressure pi, to some average reservoir
pressure, p.
• Using the law of mass balance, during the pressure drop
(Dp), the expansion of the fluids left over in the reservoir
must be equal to the volume of fluids produced from the
reservoir.
Reservoir Fluid Properties
Some Critical Reservoir Fluids properties are :
• Bubble point pressure
• Solution GOR
• Oil Formation Volume Factor
• Oil Density
Reservoir Fluid Properties– Bubble Point Pressure
• The bubble point pressure is defined as the
pressure at which the first bubble of gas
comes out of solution. At this point, we can
say the oil is saturated - it cannot hold
anymore gas.
• Above this pressure the oil is under-
saturated, and the oil acts as a single-phase
liquid. At and below this pressure the oil is
saturated, and any lowering of the pressure
causes gas to be liberated resulting in two-
phase flow
Reservoir Fluid Properties– Oil Formation Volume Factor
• The oil formation volume factor, Bo, is defined as the ratio of the volume of oil (plus the gas in
solution) at the prevailing reservoir temperature and pressure to the volume of oil at standard
conditions. Bo is always greater than or equal to unity. The oil formation volume factor can be
expressed mathematically as:
• A typical oil formation factor curve, as a function of pressure for an under saturated crude oil (pi
> pb), is shown in Figure.
• As the pressure is reduced below the initial reservoir pressure pi, the oil volume increases due to
the oil expansion. This behavior results in an increase in the oil formation volume factor and will
continue until the bubble-point pressure is reached.
• At pb, the oil reaches its maximum expansion and consequently attains a maximum value of Bob
for the oil formation volume factor. As the pressure is reduced below pb, volume of the oil and
Bo are decreased as the solution gas is liberated. When the pressure is reduced to atmospheric
pressure and the temperature to 60°F, the value of Bo is equal to one.
Reservoir Fluid Properties– Solution Gas to Oil Ratio
• The solution gas oil ratio is the amount of gas dissolved in the oil (or
water) at any pressure. It increases approximately linearly with
pressure and is a function of the oil (or water) and gas composition.
A heavy oil contains less dissolved gas than a light oil.
• In general, the solution gas oil (or water) ratio varies from 0 (dead
oil (or water)) to approximately 2000 scf / bbl. (very light oil (or
water)).
• The solution gas oil (or water) ratio increases with pressure until the
bubble point pressure is reached, after which it is a constant, and
the oil (or water) is said to be under saturated.
• 1-2: As the reservoir pressure is decreased from initial reservoir
pressure (Pi) to bubble point pressure (Pb), the dissolved gas oil ratio
is constant. This is because, above the bubble point there is no free
gas in the reservoir. So the amount of gas that comes out at the
surface will be dissolved gas only and the solution gas oil ratio will
remain constant.
• 2-3: As the reservoir pressure falls below bubble point pressure, free
gas will continuously evolve in the reservoir. This leaves less gas
dissolved in the oil, therefore the solution gas oil ratio steadily
declines below the bubble point pressure.
Reservoir Fluid Properties– Oil Density
• Oil gravity relates the density of oil to that of the density of water. The oil gravity has a very strong
effect on the calculated oil viscosity and solution gas-oil ratio. It has an indirect effect on the oil
compressibility and the oil formation volume factor, since these variables are affected by the
solution gas-oil ratio.
• The American Petroleum Institute (API) developed a specific gravity scale that measures the
relative density of various petroleum liquids. API gravity is gradated in degrees on a hydrometer
instrument and was designed so that most values would fall between 10° and 70° API.
• Usually the oil gravity is readily known. It ranges from 45 °API (light oil) through 20 °API (medium
density) to 10 °API (heavy oil). The conversion from API gravity (oil field units) to relative gravity
(relative to water) is:
Reservoir Fluid Properties– Oil viscosity
• Oil viscosity is a measure of the resistance to
flow exerted by the oil, and is given in units of
centipoises (cP).
• Higher values indicate greater resistance to flow.
• For oil, the viscosity decreases with increasing
temperature and pressure (up to the bubble
point).
• Above the bubble point pressure, oil viscosity
increases minimally with increasing pressure as
shown. It is a very strong function of reservoir
temperature, oil gravity, and solution gas-oil
ratio.
General Material Balance Relations
• The general form of the equation can be described as;
• where,
• N = initial oil in place (STB)
• m =ratio of volume of gas cap to volume of oil zone
• Np = cumulative oil production (STB)
• Rp = cumulative produced gas oil ratio
• Rs = solution gas oil ratio
• We= cumulative water influx from the aquifer into the reservoir (STB)
• Wp = cumulative amount of aquifer water produced (stb)
• Bo = oil formation volume factor rb/stb
• Bw = water formation volume factor rb/stb
• Cw = connate water isothermal compressibility in 1/psi
• dp represents change in pressure ( in psi)
Gas Material Balance Relations
• When plotted on a graph of p/Z versus cumulative production,
the equation can be analyzed as a linear relationship.
• Several measurements of static pressure and the corresponding
cumulative productions can be used to determine the x-intercept
of the plot - the original gas-in-place (OGIP), shown as G in the
equation
• King (1993) introduced p/Z* to replace p/Z. By modifying Z,
parameters to incorporate the effects of adsorbed gas were
incorporated, so the total gas-in-place is interpreted, rather than
just the free gas-in-place; and a straight line analysis technique is
still used. This concept has been extended to additional reservoir
types with Fekete's p/Z** method (Moghadam et al. 2009).
• The reservoir types considered in the advanced material balance
equation are: over pressured reservoirs, water-drive reservoirs,
and connected reservoirs. The total Z** equation is shown below
with the modified material balance equation
Oil Material Balance Relations
• Black Oil Material Balance (p>pb)
• "Solution Gas Drive" (Oil) Material Balance: (all p )
