1. Reservoir Performance Curves

2. 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.

3. Ultimate recovery factor,% Reservoir mechanism
Different recovery mechanisms and recovery factors associated with each of them
Ultimate recovery factor,%
Reservoir mechanism
5% of the OOIP
Fluid &rock expansion (F&R Exp.M)
15-30% of the OOIP
Depletion drive mechanism(D.D.M)
40-50% of the OOIP
Gas cap drive mechanism(G.C.D.M)
50% or more of the OOIP
Water drive mechanism (W.D.M.)

4. Reservoir performance curves

5. 2-For Gas cap drive reservoirs:
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 .

6. 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.

7. 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.

8. 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.

9. 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

10. 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.

11. 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.

12. N * * * Np

13. Past performance:
1-production data ,and
2-pressure data from production commencement so far.
3-PVT data.

14. 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

15. 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 .

16. * N * * * * Np or P Gas cap or water influx Correct assumption
Lost production or
Thief zone
Np or P

17. 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 .

18. 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.

19. 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.

20. 7-Constant temperature
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.

21. 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.