This document discusses methods for calculating hydrocarbon volumes in reservoirs, including volumetric and material balance methods. It provides details on calculating oil, gas, and total hydrocarbon volumes based on parameters like porosity, net thickness, and saturation. It also covers reservoir drive mechanisms that can provide energy for hydrocarbon production, such as solution gas drive, gas cap drive, water drive, compaction drive, and combination drives. Reservoir performance data like pressure trends and gas-oil ratios can help identify the active drive mechanism.

1. RESERVOIR EVALUATION
The volume of hydrocarbons in a reservoir can
be calculated:
1. directly by volumetric methods
2. indirectly by material balance methods
Volumetrics provide a static measure of oil or
gas in place. Accuracy of volumetrics depends
on data for:
• porosity
• net thickness
• areal extent
• hydrocarbon saturations
Material balance methods provide a dynamic
measure of hydrocarbon volumes. Accuracy
depends on quality of data for:
• pressure surveys
• temperature surveys
• analysis of recovered fluids
Normally mass balance methods increase in
accuracy as the reservoir is produced.

2. VOLUMETRIC ANALYSIS
Also known as the geologist's method
because it is based on geological maps, core
logs and analysis of wireline logs. Isopach
maps are used to compute the bulk volume of
the reservoir (V).
For an oil reservoir above the bubble point the
oil-originally-in-place (OOIP) is given by:
OOIP = (V.n).(1 - Swi)
The stock tank oil in place is given by:
STOIP = (V.n).(1 - Swi) / Bo
where Bo is the oil formation volume factor.
The volume x porosity is the pore volume for
the reservoir (PV). So the OIP is also known as
the hydrocarbon pore volume (HCPV):
HCPV = (V.n).(1 - Swi) = PV.(1 - Swi)
The moveable oil volume (MOV) is given by:
MOV = PV.(1 - Swi - Soi)

3. GAS VOLUMES
The volume of free gas in a gas reservoir or gas-
initially-in-place is given by:
GIIP = Gr = (V.n).(1 - Swi)
In terms of standard volumes at STP, the gas
volume is:
G = (V.n).(1 - Swi) / Bg
G = (V.n).(1 - Swi).E
where Bg is the gas formation volume factor and E
is the gas expansion factor.
For oil and gas reservoirs below the bubble point,
the total hydrocarbon in place is given by the HCPV:
HCPV = (V.n).(1 - Swi)
The stock tank oil volume can be computed as:
STOIP = (V.n).(1 - Swi - Sg) / Bo
The standard gas volume at STP is given by:
G = (V.n).(1 - Swi - So) / Bg

4. VOLUME CALCULATIONS
To calculate volumes it is necessary to find the
areas between isopach contours. There are
several methods:
1. grid square counting
2. planimeter
3. digitizer table
Given the areas between contours, volumes
can be computed using:
1. Trapezoidal rule
2. Simpson's rule
For the trapezoidal rule with a contour interval, h, and where hn
is z-distance from the top contour to the crest of the reservoir :
V = h.[Ao + 2A1 + 2A2 + ...+ 2An-1 + An] + hn.An
2 2
Using Simpson's rule with a contour interval, h, and an even
number of intervals (odd number of lines) :
V = h.[Ao + 4A1 + 2A2+ ... + 2An-2 + 4An-1 + An] + hn.An
2 2
AoA3
A2
A1

5. USE OF VOLUMETRICS
In order to calculate stock tank volumes the
formation volume factors Bo and Bg are required.
Both Bo and Bg are functions of pressure (and
consequently of reservoir depth).
There are various methods of calculating an
averaging pressure over a reservoir:
1. well pressure over n wells
pav = Σpi / Σi
2. areal pressure over n sub-areas
pav = Σpi.Ai / ΣAi
3. volumetric pressure over n sub-volumes
pav = Σpi.Ai.zi / ΣAi.zi
The volumetric average gives the best estimate.
Formation volume factors can also be averaged in
the same way:
[Bo]av = ΣBo(pi).Ai.zi / ΣAi.zi
[Bg]av = ΣBg(pi).Ai.zi / ΣAi.zi

6. NET PAY CUT-OFFS
Net pay cut-offs are assigned on the basis of :
1. effective porosity (e.g. > 8%)
2. permeability (e.g. > 1 md)
3. thickness (e.g. > 1 m)
Wireline logs can also be used to assign net
pay. SP, porosity and density logs are used in
this way.
Combinations of n, k, and z may be used to
provide a cut-off for a particular reservoir, field
or pool.
Gross pay is the entire reservoir, net pay
involves some kind of cut-off decision.
Volumetric estimates of OOIP and GIIP may be
based on gross pay or net pay. Net pay
volumes are used almost exclusively in
economic analyses.

7. DRIVE MECHANISMS
Material balance methods involve estimation of
reservoir recovery from the PVT behaviour of
the reservoir and contained fluids.
Fluid phase expansion and rock skeleton
compression and can combine in a number of
ways to provide the energy to drive
hydrocarbons from subsurface reservoirs:
• Solution Gas Drive (or Depletion Drive)
• Gas Cap Drive (and Gravity Drainage)
• Natural Water Drive
• Compaction Drive
• Combination Drive
Ultimate oil and gas recoveries vary depending
on the drive mechanism. For oil, water drive is
most effective. Typical primary recoveries are
in the 25-40% range (maximum 75%).
For gas, gravity drainage, water drive and
depletion drive can provide > 80% recovery.

8. SOLUTION GAS DRIVE
The principle of solution gas drive or depletion
drive is the expansion of dissolved gas and
liquid oil in response to a pressure drop. The
change in fluid volume results in production.
Above the bubble point, only liquid oil
expansion occurs. Below the bubble point,
both liquid oil expansion and gas expansion
contribute to volume change.
Dissolved gas reservoirs typically recover
between 5 and 25% OOIP and 60 to 80% GIIP.
The Upper Cretaceous Cardium sand reservoir
is an example of a depletion drive reservoir.

9. SOLUTION GAS DRIVE HISTORY
• rapid and continuous pressure drop, rate
of decline falls at bubble point pressure.
• Rs (solution gas oil ratio) low until p = pb,
then increases to maximum and declines.
• absent or minimal water influx (watercut).
• gravity drainage is a special case in
steeply dipping reservoirs where gas
drives out more oil.
• maintaining pressure above bubble point
produces oil rather than gas for p < pb.
• well production declines rapidly, early
pumping required.
watercut
GOR (R)
pressure
time
Rsi

10. GAS CAP DRIVE
The principle of gas cap drive or depletion is
the expansion of free gas and in response to a
pressure drop. The change in fluid volume
results in production.
Gas cap expansion maintains the pressure in
the oil leg.
Gas cap drive reservoirs typically recover 20 to
40% OOIP, sometimes as high as 60%.
The Lower Mississippian Turner Valley
carbonate was a gas cap drive reservoir.

11. GAS CAP DRIVE HISTORY
• pressure drops continuously, but slowly.
• Rs (solution gas oil ratio) increases
continuously.
• water influx (watercut) absent or minimal
• gas cap cannot be allowed to shrink or oil
encroachment will occur resulting in
reduced recovery.
• oil leg wells can eventually produce gas.
• Wells have long flowing life (depending
on the size of the gas cap).
watercut
GOR (R)
pressure
time
Rsi

12. NATURAL WATER DRIVE (1)
The principle of natural water drive is that an
aquifer provides the energy for hydrocarbon
production. Both water expansion as a result
of pressure reduction and inflow are involved.
Natural water drive is associated with high
recovery rates, oil from 35-75% OOIP, gas
from 60-80% GIIP.
Bottom water drive, where the water leg
underlies the entire reservoir, and edge water
drive, where only part of the areal extent is
contacted by water, are recognized.
The Upper Devonian Leduc pools are driven
by inflow from the Cooking Lake Aquifer.
BOTTOM WATEREDGE WATER

13. NATURAL WATER DRIVE (2)
It is not uncommon for flow from the surface to
supply the energy for natural water drive.
When a pressure drop occurs, both the oil and
water liquid phases expand resulting in
production. Additionally, water inflow radially
and vertically displaces the oil towards the
producers.

14. NATURAL WATER DRIVE HISTORY
• pressure remains high, small drop.
• Rs (solution gas oil ratio) remains low.
• water influx starts early and increases to
appreciable levels.
• Residual oil may be trapped behind the
advancing water.
• Wells flow freely until water production
(watercut) becomes excessive.
watercut
GOR (R)
pressure
time
Rsi

15. COMPACTION DRIVE
In compaction drive, the energy for oil
production is provided by the collapse of the
porous medium skeleton and expansion of the
pore fluids when the reservoir pressure drops.
The increase in the "grain pressure" or
effective stress causes pore collapse and
compaction (consolidation) of the reservoir.
This drive mechanism is common in highly
compressible, unconsolidated reservoirs such
as those found in California, Venezuela, and
the heavy oil deposits of western Canada.
The Lower Cretaceous (Mannville) Clearwater
sands in the Cold Lake district provide an
example of compaction drive.

16. COMBINATION DRIVE
In combination drive reservoirs, at least two of
the basic drive mechanisms are active in
expelling oil:
• solution gas exsolution
• gas cap expansion
• natural water influx
• pore collapse
The example shows a combination of natural
water influx and gas cap drive.
In many of the western Canadian heavy oil
deposits, solution gas drive and compaction
drive act in combination, for example the Lower
Cretaceous (Mannville) Waseca sand in the
Lloydminster district.

17. RESERVOIR PERFORMANCE DATA
Pressure trends in reservoirs under various
drive mechanisms are distinctive.
Producing GOR is also strongly diagnostic of
drive mechanism.
100
80
60
40
20
0
0 10 20 30 40 50
%OOIP Produced
P
%
WATER DRIVE
GAS CAP DRIVE
SOLUTION
GAS DRIVE
100
80
60
40
20
0
0 10 20 30 40 50
%OOIP Produced
GOR
%
SOLUTION
GAS DRIVE
GAS CAP DRIVE
WATER DRIVE