Reservoir Production Processes

Diapositive 1Reservoir Production Processes
(Reserves, Reservoir Drive Mechanisms, GOR, Phase Diagrams, Oil Recovery Factor)
Copyright 2007, , All rights reserved
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STOIIP: Stock Tank Oil Initially In Place
Reserves
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Where;
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Where:
: porosity Sw: water saturation
Bo: formation volume factor
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What are Reserves?
Oil and gas trapped beneath the earth’s surface that can be recovered under existing economic conditions and with current technology.
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Np: cumulative stock tank oil prod.
Affected by:
Reservoir Rock
Fluid Properties
Production Mechanism
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Gas
Oil
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What is the STOIIP in the following case (in bbls)?
A: 300m x 500m h: 200m : 20%
Sw: 25% Bo: 1.35
1m3 = 6.289bbls
If ultimate RF of this reservoir is 30% and oil price is $75/bbl, how much is the total revenue? Assume there is no market for the gas in this case.
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Influx of aquifer water
Expansion of original reservoir fluids
Free gas
Interstitial water
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Main source(s) of reservoir energy
liberation and expansion of dissolved gas
Possible secondary gas cap
Typical production characteristics
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Formation of Secondary Gas Cap
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Typical Production Characteristics
Reservoir pressure behavior
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Gas/oil ratio, SCF/STB
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Pure gas-cap drive reservoir has no aquifer
Expansion of gas cap and liberation and expansion of solution gas in the oil zone
Gas cap expands pushing GOC down and maintaining higher pressure
Good sweep
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Oil zone in communication with acquifer
influx of acquifer water - edge-water drive, bottom-water drive
Pressure decline relatively slow
Water production increases steadily
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Edge-Water Drive
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Bottom-Water Drive
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Effect of Production Rate on Pressure
Production data - lower oil production rate
2000
1900
1800
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Reservoir pressure
Reservoir pressure in this reservoir declines more slowly and even rises because the aquifer is able to provide enough pressure support to offset lower fluid withdrawal from this reservoir. Oil production rate in the figure above is lower than in the previous example.
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Water
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Basic drive mechanisms usually occur in combination.
A large aquifer and a large gas cap can occur in a reservoir simultaneously.
Oil production pressure drop results in some dissolved gas drive component in any oil reservoir drive mechanism (even in water-drive and gas-cap drive).
Dominant drive mechanism depends on the “strength" of each of the source(s) of reservoir energy: size of original gas cap, "strength" of aquifer (size and permeability), and degree of pressure decline.
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Main energy - gravitational force
Point A
Point B
Point C
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Gravity drainage may occur in any type of reservoir.
Gravity drainage is particularly important in solution-gas and gas-cap drive oil reservoirs.
Gravitational segregation can improve recovery efficiency substantially when it has time to act.
In solution-gas drive reservoirs, liberated solution gas may segregate from oil to form a secondary gas cap.
In gas-cap drive reservoirs, oil in gas-invaded region drains down to rejoin oil column, reducing residual oil saturation (and thus improving recovery efficiency).
Recovery efficiency for a gravity-drainage reservoir may approach that of better water-drive reservoirs.
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100
80
60
40
20
0
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Gas/oil ratio, MSCF/STB
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Water drive
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expansion of gas
No water production
Flowing life can be increased by reducing surface back-pressure through installing compression
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Gas reservoir with acquifer
expansion of gas and water influx
Pressure decline slower than volumetric gas reservoir
Water production may start early and increases with time
Flowing life can be increased by installing continuous or intermittent water removal equipment
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Solution-gas drive oil reservoirs
High reservoir dip angle
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Water drive oil reservoirs
Large fluid density difference
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Volumetric gas reservoir (gas expansion drive)
Low abandonment pressure
Water-drive gas reservoir
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ER = Oil recovery efficiency (recovery factor), [% (for API study)]
= Reservoir porosity, fraction
Bob = Formation volume factor of oil at bubblepoint, RB/STB
k = Reservoir permeability, [darcy (for API study);
µob = Oil viscosity at bubblepoint pressure, cp
pb = Bubblepoint pressure of oil, psig
pa = Abandonment reservoir pressure, psig
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= Reservoir porosity, fraction
Bob = Formation volume factor of oil at bubblepoint, RB/STB
k = Reservoir permeability, [darcy (for API study);
µob = Oil viscosity at bubblepoint pressure, cp
µo = Oil viscosity at initial conditions, cp
µw = Water viscosity, cp
pa = Abandonment reservoir pressure, psig
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k = Reservoir permeability, md
f = Reservoir porosity, fraction
mo = Oil viscosity, cp
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N
N
RF
p

Reservoir Production Processes

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