Reservoir Performance
Curves
Typical performance curves of primary
recovery mechanisms
• It is very rare to find a reservoir driven by single
mechanism. In most cases , the reservoirs are driven
by more than one mechanism.
• For example, if you have a water drive reservoir
producing above bubble point pressure, the
mechanisms will be water influx and fluid and rock
expansion. Once the reservoir pressure introduce to
become lower than bubble point pressure , the
driving mechanism of the same reservoir will be
water drive and solution gas drive.
Different recovery mechanisms and recovery factors
associated with each of them
Reservoir mechanism Ultimate recovery factor,%
Fluid &rock expansion
(F&R Exp.M)
5% of the OOIP
Depletion drive
mechanism(D.D.M)
15-30% of the OOIP
Gas cap drive
mechanism(G.C.D.M)
40-50% of the OOIP
Water drive mechanism
(W.D.M.)
50% or more of the OOIP
Reservoir performance curves
• 1- For water drive reservoirs:
• A rapid pressure reduction is occurred and then the
water influx can compensate this reduction causes
gradual pressure reduction.
• Gas oil ratio ( GOR) : Almost constant = solubility of
gas
• 2-For Gas cap drive reservoirs:
• The reduction in reservoir pressure is slow due
to the high expansibility of the gas , then
reduction of the reservoir pressure is
compensated by the gas cap expansion .
• Near the end of the reservoir life , reservoir
pressure is considerably decline , the gas cap
gas invades the oil zone and you can,t avoid
the production of the gas cap gas . thus you
will concern a rapid increase in GOR , which is
• corresponding to rapid decline in the reservoir
pressure.
• 3-For depletion drive reservoirs:
• The reservoir pressure declines slowly at the
beginning and then rapidly.
• The GOR remains more or less constant for the
period from the initial reservoir pressure up to the Pb
( bubble point pressure). Then it decreases for a
short period and then increases again to reach a
maximum value after which it starts to decrease
again. To explain this, it is well known that the gas
solubility above the bubble point pressure is
constant and therefore the surface GOR is constant
as well.
• Once the pressure is reduced below bubble point
pressure , the solution gas start to release from oil ,
however , this gas can not be move (immobile) until
• its saturation exceeds the critical gas saturation. So ,
the observed surface GOR in this short period (
from Pb to Sgc) decreases.
• After that , the released free gas becomes mobile
and can be produced to be added to the solution gas
which results in increasing the GOR.
• Near the end of the reservoir life , the reservoir
pressure declines to a low value which means an
increase in the gas formation volume factor (Bg) .
since the surface gas oil ratio ,GOR is expressed as :
• GOR = K g . o .o + Rs
Kg g g
• Thus , surface GOR starts to decreases due to
increasing g
• 4-Rock and fluid expansion :
• As for the rock and fluids expansion which dominates
for a very short period of reservoir life , the reservoir
pressure declines very rapidly while thesurface GOR
remains constant.
How to Determine the Reservoir
Driving Mechanism
• The worst conditions is the rock and fluid
expansion only.
• This exists in the case of DDR above Pb.
Np o + Wp w = N oi Ce  P
N =
Np o + Wp w
oi Ce  P
• i.e
Y = Constant.
N
*
*
*
Np
• Past performance:
1-production data ,and
2-pressure data from production commencement
so far.
3-PVT data.
• The driving mechanism of any reservoir can be
determined as follows :• Plot the past performance (GOR & pressure Vs Np/N
) and compare the same with the typical
performance curves of the different driving
mechanisms to guess which mechanism
• To check if your guessing is correct or not ,do the
following:
• Assume the lowest efficient driving mechanism i.e
(that is to say) a fluid & rock expansion only (D.D.R
above Pb ) i.e. under saturated DDR
•
•
•
•
The M.B. equation for this reservoir can be
written as:
NPBo +WPBW= N BOICe  P
Use the past performance data of your
reservoir (P, NP. and PVT data)
Use the past performance to solve the M.B.
equation at different time intervals and plot
apparent N versus pressure .
Gas cap or water
influx
*
N
Correct
assumption
*
*
*
Lost production or
Thief zone
Np or P
*
• If this plot represent a horizontal line , this means
that your assumption is good and your driving
mechanism is really fluid & rock expansion
mechanism.
• If not , there are two possibilities :
a) The apparent (N) increases with pressure or Np .
This indicate that there is an other external force
rather than DDR mechanism which might be gas cap
or water influx (We) or both . To check which of
which go to the logs.
b)The apparent (N) is decreases , this means that
your reservoir connected to a thief zone .
Limitations and Assumptions of MBE
1-Reliable production data:
All production data should be recorded with respect
to the same time period. If possible, gas-cap- and
solution gas production records should be maintained
separately .
2- Average reservoir pressure (A big difficulty):
A source of error is often introduced in the MBE
calculations when determining the average reservoir
pressure and the associated problem of correctly
weighting or averaging the individual well pressures.
3-PVT analysis procedure must duplicate the
actual reservoir gas libration process
It is assumed that the PVT samples or data sets
represent the actual fluid compositions and that
reliable and representative laboratory procedures
have been used.
4-Type of crude oil (Heavy , medium or light
crude oil).
5- Ratio of the gas cap size to oil zone size.
6-The use of PVT empirical correlations in the
absence of PVT laboratory analysis
7-Constant temperature
Pressure-volume changes in the reservoir are
assumed to occur without any temperature
changes. If any temperature changes occur,
they are usually sufficiently small to be
ignored without significant error.
8-Pressure equilibrium
All parts of the reservoir have the same pressure, and
fluid properties are therefore constant throughout.
Minor variations in the vicinity of the well bores may
usually be ignored. Substantial pressure variation
across the reservoir may cause excessive calculation
error.
9-Constant reservoir volume
Reservoir volume is assumed to be constant
except for those conditions of rock and water
expansion or water influx that are specifically
considered in the equation.