Reservoir performance
prediction methods
PREDICTING OIL
RESERVOIR PERFORMANCE
• Most reservoir engineering calculations involve the use of
the material balance equation. Some of the most useful
applications of the MBE require the concurrent use of fluid
flow equations, e.g., Darcy’s equation.
• Combining the two concepts would enable the engineer to
predict the reservoir future production performance as a
function of time. Without the fluid flow concepts, the MBE
simply provides performance as a function of the average
reservoir pressure.
PREDICTING OIL
RESERVOIR PERFORMANCE
• Prediction of the reservoir future performance is
ordinarily performed in the following two phases:
• Phase 1:
Predicting cumulative hydrocarbon production as a
function of declining reservoir pressure. This stage is
accomplished without regard to:
• Actual number of wells
• Location of wells
• Production rate of individual wells
• Time required to deplete the reservoir
Phase 2:
The second stage of prediction is the time-production phase. In
these calculations, the reservoir performance data, as calculated
from Phase One, are correlated with time. It is necessary in this
phase to account for the number of wells and the productivity
of each well.
PHASE 1. RESERVOIR PERFORMANCE PREDICTION
METHODS
The material balance equation in its various mathematical forms as is
designed to provide with estimates of the initial oil in place N, size of
the gas cap m, and water influx We. To use the MBE to predict the
reservoir future performance, it requires two additional relations:
1- Equation of producing (instantaneous) gas-oil ratio
2- Equation for relating saturations to cumulative oil production
These auxiliary mathematical expressions are presented as follows
Instantaneous Gas-Oil Ratio
The produced gas oil ratio (GOR) at any particular
time is the ratio of the standard cubic feet of total gas
being produced at any time to the stock-tank barrels
of oil being produced at that same instant. Hence,
the name instantaneous gas-oil ratio.
The following expression describes the GOR
mathematically :
(1)
The instantaneous GOR equation is of fundamental importance in
reservoir analysis. The importance of Equation (1) can appropriately
be discussed in conjunction with Figures(1) and (2).
These illustrations show the history of the gas-oil ratio of a
hypothetical depletion drive reservoir that is typically characterized
by the following points:
Fig-1:Characteristics of solution-gas-drive
reservoirs.
Fig-2:History of GOR and Rs for a solutiongas-drive reservoir.
Point 1: When the reservoir pressure p is above the
bubble point pressure pb, there is no free gas in the
formation, i.e., krg = 0, and therefore:
GOR = Rsi = Rsb
(2)
The gas-oil ratio remains constant at Rsi until the
pressure reaches the bubble-point pressure at Point
2.
Point 2: As the reservoir pressure declines below pb,
the gas begins to evolve from solution and its
• saturation increases. This free gas, however, cannot
flow until the gas saturation Sg reaches the critical
gas saturation Sgc at Point 3.
From Point 2 to Point 3:
The instantaneous GOR is described by a decreasing
gas solubility as:
GOR = Rs
(3)
Point 3:
At Point 3, the free gas begins to flow with the oil and the
values of GOR are progressively increasing with the
declining reservoir pressure to Point 4. During this pressure
decline period, the GOR is described by Equation (1), or:
Point 4:
At Point 4, the maximum GOR is reached due to the
fact that the supply of gas has reached a maximum
and marks the beginning of the blow-down period to
Point 5.
Point 5:
This point indicates that all the producible free gas
has been produced and the GOR is essentially
equal to the gas solubility and continues to Point 6.
There are three types of gas oil ratios, all expressed in
scf/STB, which must be clearly distinguished from each
other. These are:
1. Instantaneous GOR (defined by Equation (1)
2. Solution GOR
3. Cumulative GOR
The solution gas-oil ratio is a PVT property of the crude oil
system. It is commonly referred to as gas solubility and
denoted by Rs.
It measures the tendency of the gas to dissolve in or
evolve from the oil with changing pressures.
It should be pointed out that as long as the evolved gas
remains immobile, i.e., gas saturation Sg is less than the
critical gas saturation, the instantaneous GOR is equal to
the gas solubility, i.e.:
GOR = Rs
The cumulative gas oil ratio Rp, as defined previously in the
material balance equation, should be clearly distinguished
from the producing (instantaneous) gas-oil ratio (GOR). The
cumulative gas-oil ratio is defined as:
cumulative (TOTAL) gas produced
RP =
cumulative oil produced
GP
RP = —— (4)
Np
or
where :
Rp = cumulative gas-oil ratio, scf/STB
Gp = cumulative gas produced, scf
Np = cumulative oil produced, STB
• The cumulative gas produced Gp is related to the
instantaneous GOR and cumulative oil production by the
expression:
(5)
• Equation (5) simply indicates that the cumulative gas
production at any time is essentially the area under the
curve of the GOR versus Np relationship, as shown in
Figure 3.
Fig-3:Relationship between GOR and Gp.
• The incremental cumulative gas produced Gp
between Np1, and Np2 is then given by:
(6)
• The above integral can be approximated by using the
trapezoidal rule, to give:
• Equation (5) can then be approximated as:
(7)
Solution
Step 1. Construct the following table:
The Reservoir Saturation Equations
The saturation of a fluid (gas, oil, or water) in the
reservoir is defined as the volume of the fluid
divided by the pore volume, or:
oil volume
(8)
So =
pore volume
Sw =
Sg =
water volume
pore volume
gas volume
pore volume
So + Sw + Sg + 1.0
(9)
(10)
(11)
• Consider a volumetric oil reservoir with no gas
cap that contains N stock-tank barrels of oil at the
initial reservoir pressure pi. Assuming no water
influx gives:
• Soi = 1 - Swi
• where the subscript i indicates initial reservoir
condition. From the definition of oil saturation:
If the reservoir has produced Np stock-tank barrels
of oil, the remaining oil volume is given by:
remaining oil volume = (N - Np) Bo
(12-13)
Substituting Equations 12-13 and 12-12 into
Equation 12-8 gives:
• It should be pointed out that the values of the relative
permeability ratio krg/kro as a function of oil
saturation can be generated by using the actual field
production as expressed in terms of Np, GOR, and
PVT data. The proposed methodology involves the
following steps:
• Step 1. Given the actual field cumulative oil
production Np and the PVT data as a function of
pressure, calculate the oil and gas saturations from
Equations 12-15 and 12-16, i.e.:
Step 2. Using the actual field instantaneous GORs,
solve Equation 12-1 for the relative permeability ratio
as:
Step 3. Plot (krg/kro) versus So on a semilog paper.
Equation 12-15 suggests that all the remaining oil
saturation be distributed uniformly throughout the
reservoir. If water influx, gas-cap expansion, or gascap shrinking has occurred, the oil saturation
equation, i.e., Equation 12-15, must be adjusted to
account for oil trapped in the invaded regions.
Oil saturation adjustment for water influx
The proposed oil saturation adjustment methodology
is illustrated in Figure 12-4 and described by the
following steps:
Step 1. Calculate the pore volume in the water invaded
region, as:
We - Wp Bw = (P.V)water (1 - Swi - Sorw)
Solving for the pore volume of water-invaded zone
(P.V)water gives:
Figure 12-4. Oil saturation adjusted
for water influx.
Step 2. Calculate oil volume in the water invaded zone,
or:
volume of oil = (P.V)water . Sorw
(12-19)
Step 3. Adjust Equation 12-14 to account for the
trapped oil by using Equations 12-18 and 12-19:
Oil saturation adjustment for gas-cap
expansion
The oil saturation adjustment procedure is illustrated in Figure 12-5 and
summarized below:
Step 1. Assuming no gas is produced from the gas cap, calculate the net
expansion of the gas cap, from:
Step 2. Calculate the pore volume of the gas-invaded zone,
(P.V)gas, by solving the following simple material balance:
Figure 12-5. Oil saturation adjustment for gascap expansion.
• Step 3. Calculate the volume of oil in the gasinvaded zone.
• Step 4. Adjust Equation 12-14 to account for the
trapped oil in the gas expansion zone by using
Equations 12-22 and 12-23, to give:
Oil saturation adjustment for combination
drive
• For a combination drive reservoir, i.e., water influx
and gas cap, the oil-saturation equation as given by
Equation 12-14 can be adjusted to account for both
driving mechanisms, as:
Saturated-Oil Reservoirs
If the reservoir originally exists at its bubble-point
pressure, the reservoir is referred to as a saturated-oil
reservoir. As the reservoir pressure declines below the
bubble-point, the gas begins to evolve from solution.
The general MBE may be simplified by assuming that the
expansion of the gas is much greater than the expansion
of rock and initial water and, therefore, can be neglected.
For a volumetric and saturated oil reservoir with no fluid
injection, the MBE can be expressed by:
(12)
The above material balance equation contains two
unknowns, which are:
• Cumulative oil production ,Np
• Cumulative gas production,Gp
The following reservoir and PVT data must be
available in order to predict the primary recovery
performance of a depletion drive reservoir in terms of
Np and Gp:
•
•
•
•
a. Initial oil-in-place N
b. Hydrocarbon PVT data
c. Initial fluid saturations
d. Relative permeability data
(13)
• The above results should be compared with the
averaged laboratory relative permeability data.
• All the techniques that are used to predict the future
performance of a reservoir are based on combining the
appropriate MBE with the instantaneous GOR using the
proper saturation equation. The calculations are repeated
at a series of assumed reservoir pressure drops. These
calculations are usually based on one stock tank barrel of
oil in place at the bubble-point pressure. This avoids
carrying large numbers in the calculation procedure and
permits calculations to be made on the basis of the
fractional recovery of initial oil in place.
• There are several widely used techniques that were
specifically developed to predict the performance of
solution-gas-drive reservoirs, including:
• Tarner’s method
• Tracy’s method
• Muskat’s method
• These methodologies are presented in the following
section.
Tarner’s Method
• Tarner (1944) suggests an iterative technique for
predicting cumulative oil production Np and cumulative
gas production Gp as a function of reservoir pressure. The
method is based on solving the material balance equation
and
the
instantaneous
gas-oil
ratio
equation
simultaneously for a given reservoir pressure drop from p1
to p2. It is accordingly assumed that the cumulative oil and
gas production has increased from Np1 and Gp1 to Np2 and
Gp2. To simplify the description of the proposed iterative
procedure, the stepwise calculation is illustrated for a
volumetric saturated-oil reservoir. It should be pointed out
that Tarner’s method could be extended to predict the
volumetric behavior of reservoirs under different driving
mechanisms.
Step 1. Select a future reservoir pressure p2 below the
initial (current) reservoir pressure p1 and obtain the
necessary PVT data. Assume that the cumulative oil
production has increased from Np1 to Np2. It should
be pointed out that Np1 and Gp1 are set equal to zero
at the initial reservoir pressure, i.e., bubble point
pressure.
Step 2. Estimate or guess the cumulative oil production
Np2 at p2.
Step 3. Calculate the cumulative gas production Gp2 by
rearranging the MBE, i.e., Equation 12, to give:
(14)
(15)
• Step 4. Calculate the oil and gas saturations at the
assumed cumulative oil production Np2 and the
selected reservoir pressure p2 by applying Equations
(16),(17):
(16)
(17)
• Step 5. Using the available relative permeability data,
determine the relative permeability ratio krg/kro that
corresponds to the gas saturation at p2 and compute
the instantaneous (GOR)2 at p2 from Equation (1), as:
(18)
• It should be noted that all the PVT data in the
expression must be evaluated at the assumed
reservoir pressure p2.
• Step6: Calculate again the cumulative gas production
Gp2 at p2 by applying Equation (7), or:
(19)
• in which (GOR)1 represents the instantaneous GOR
at p1. If p1 represents the initial reservoir pressure,
then set (GOR)1 = Rsi.
• Step 7. The total gas produced Gp2 during the first
prediction period as calculated by the material
balance equation is compared to the total gas
produced as calculated by the GOR equation.
• These two equations provide with two independent
methods required for determining the total gas
produced.
• Therefore, if the cumulative gas production Gp2 as
calculated from Step 3 agrees with the value of Step
6, the assumed value of Np2 is correct and a new
pressure may be selected and Steps 1 through 6 are
repeated.
• Otherwise, assume another value of Np2 and repeat
Steps 2 through 6.
• Step 8. In order to simplify this iterative process,
three values of Np can be assumed, which yield three
different solutions of cumulative gas production for
each of the equations (i.e., MBE and GOR equation).
• When the computed values of Gp2 are plotted versus
the assumed values of Np2, the resulting two curves
(one representing results of Step 3 and the one
representing Step 5) will intersect.
• This intersection indicates the cumulative oil and gas
production that will satisfy both equations.
• It should be pointed out that it may be more
convenient to assume values of NP as a fraction of
the initial oil in place N. For instance, Np could be
assumed as 0.01 N, rather than as 10,000 STB. In
this method, a true value of N is not required.
• Results of the calculations would be, therefore, in
terms of STB of oil produced per STB of oil initially in
place and scf of gas produced per STB of oil initially
in place.
Example 12-6
A saturated oil reservoir has a bubble-point pressure of
2100 psi at 175°F. The initial reservoir pressure is 2925
psi. The following data summarizes the rock and fluid
properties of the field:
Original oil in place = 10 MMSTB
Connate-water saturation = 15%
Porosity = 12 %
cw = 3.6 x 10-6 psi-1
cf = 4.9 x 10-6 psi-1
Predict cumulative oil and gas production at 2100, 1800, and 1500 psi.
Solution
Phase 1: Oil recovery prediction above the bubble-point
pressure
Step 1. Arrange the MBE and solve for the cumulative oil as:
Step 2. Calculate the two expansion factors Eo and Ef,w for the
pressure declines from 2925 to 2100 psi:
Step 3. Calculate cumulative oil and gas production
when the reservoir pressure declines from 2925 to
2100 psi by applying Equation:
to give:
At or above the bubble point pressure, the producing
gas oil ratio is equal to the gas solubility at the bubble
point and, therefore, the cumulative gas production is
given by:
Gp = NP Rsi
Gp = (344,656) (1340) =462 MMscf
Step 4. Determine remaining oil in place at 2100 psi.
Remaining oil in place = 10,000,000 - 344,656
= 9,655,344 STB
This remaining oil in place is considered as the initial oil in
place during the reservoir performance below the
saturation pressure,
Phase 2: Oil recovery prediction below the bubble-point
pressure First prediction period at 1800 psi:
1.
Assume Np = 0.01 N and apply Equation (15) to solve for Gp:
2.
Calculate the oil saturation, to give:
3.
Determine the relative permeability ratio krg/kro from the available
data to give:
krg/kro = 0.0100
Relative permeability curve
100
Kg/Ko
10
1
0.1
0.01
0
10
20
30
40
50
So
60
70
80
90
4.
Calculate the instantaneous GOR at 1800 psi by
applying Equation(18):
to give:
5.
Solve again for the cumulative gas production by
using the average GOR and applying Equation (19) to
yield:
6. Since the cumulative gas production as calculated by the
two independent methods (Step 1 and Step 5) do not
agree, the calculations must be repeated by assuming a
different value for Np and plotting results of the calculation.
GP
MB
GOR
Actual Gp
Actual NP/N
Np/N