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Chapter 3-Rock & Fluid Properties UTM Part of Fundamental Petroleum Engineering
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Fundamentals Of Petroleum Engineering
SKPP 1313
CHAPTER 3:
ROCK AND FLUID PROPERTIES
Assoc. Prof. Issham Ismail
Department of Petroleum EngineeringFaculty of Petroleum & Renewable Engineering
Universiti Technologi Malaysia
COURSE CONTENTS
CHAPTER 3: ROCK & FLUID PROPERTIES (2) MOHD FAUZI HAMID
SKPP 1313: FUND. OF PETROLEUM ENGINEERING
Rock Characteristics
Porosity
Permeability
Rock and Fluid Interaction
Type of Reservoir
Type of Reservoir Drive Mechanism
Reservoir Rock Characteristics
SKPP 1313: FUND. OF PETROLEUM ENGINEERING
CHAPTER 3: ROCK & FLUID PROPERTIES (3) MOHD FAUZI HAMID
To form a commercial reservoir of hydrocarbons, any geological formation must exhibit two essential characteristics.
These are capacity for storage and a transmissibility to the fluids concerned.
Storage capacity requires void spaces within the rock and the transmissibility requires that there should be continuity of those void spaces.
Porosity
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CHAPTER 3: ROCK & FLUID PROPERTIES (4) MOHD FAUZI HAMID
Petroleum is not found in underground rivers or caverns, but in pore spaces between the grains of porous sedimentary rocks.
A piece of porous sedimentary rock. The pore spaces are the white areas between the dark grains. It is within such pore spaces that fluids such as oil, natural gas, or water can be found in the subsurface.
Porosity (cont’d)
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CHAPTER 3: ROCK & FLUID PROPERTIES (5) MOHD FAUZI HAMID
Porosity () is defined as a percentage or fraction of void to the bulk volume of a material.
Porosity of commercial reservoirs may range from about 5% to about 30% of bulk volume.
%100xVV
V%100x
V
VV%100x
V
V
gp
p
b
gb
b
p
where:
Vp = pore or void volume Vb = bulk volume of rock
Vg = grain volume
Factors Affecting Porosity
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CHAPTER 3: ROCK & FLUID PROPERTIES (6) MOHD FAUZI HAMID
Grain size: grain size has no effect on porosity. Well rounded sediments that are packed into the same arrangement generally have porosities from 26% to 48% depending on the packing.
Sorting: Well sorted sediments generally have higher porosities than poorly sorted sediments for the simple reason that if a sediment is a range of particle sizes then the smaller particles may fill in the voids between the larger particles.
Grain shape: Irregularly shaped particles tend not to pack as neatly as rounded particles, resulting in higher proportions of void space.
Total and Effective Porosity
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CHAPTER 3: ROCK & FLUID PROPERTIES (7) MOHD FAUZI HAMID
Total porosity is defined as the ratio of the volume of all pores to the bulk volume of a material, regardless of whether or not all of the pores are interconnected.
Effective porosity is defined as the ratio of the interconnected pore volume to the bulk volume.
Isolated pores
Primary and Secondary Porosity
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CHAPTER 3: ROCK & FLUID PROPERTIES (8) MOHD FAUZI HAMID
Primary porosity is defined as a porosity in a rock due to sedimentation process.
Secondary porosity is defined as a porosity in a rock which happen after sedimentation process, for example fracturing and re-crystallization.
Porosity Measurement
SKPP 1313: FUND. OF PETROLEUM ENGINEERING
CHAPTER 3: ROCK & FLUID PROPERTIES (9) MOHD FAUZI HAMID
Boyle’s Law porosimeter.
Wet and dry weight method (also known as Water Evaporation method) : pore volume = (weight of saturated sample − weight of dried sample)/density of water.
Summation of fluids (also known as Water Saturation method) : pore volume = total volume of water − volume of water left after soaking.
Direct methods (determining the bulk volume of the porous sample, and then determining the volume of the skeletal material with no pores (pore volume = total volume − material volume)).
Porosity Measurement
SKPP 1313: FUND. OF PETROLEUM ENGINEERING
CHAPTER 3: ROCK & FLUID PROPERTIES (10) MOHD FAUZI HAMID
Boyle’s Law porosimeter.
Suppose the rock sample is placed in the sample chamber at zero gauge pressure and the reference chamber is filled with gas at pressure P1, then the valve between the two chambers is open and the system is brought to equilibrium.
Porosity Measurement
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CHAPTER 3: ROCK & FLUID PROPERTIES (11) MOHD FAUZI HAMID
Using Boyle’s Law:
1 2
2 2 1
2
( )ref res sam g
ref sam ref
g
PV P V V V
P V P V PVV
P
Vg = grain volume in the sample
Vref = volume of the reference chamber
Vsam = volume of the sample chamber
P1 = pressure before opening the valve
P2 = pressure at equilibrium afteropening the valve
where:
Bulk Volume Measurement
SKPP 1313: FUND. OF PETROLEUM ENGINEERING
CHAPTER 3: ROCK & FLUID PROPERTIES (12) MOHD FAUZI HAMID
Linear measurement:
physically measuring the sample with vernier caliper and then applying appropriate formula.
quick and easy, but is subject to human error and measurement error if the sample is irregularly shaped.
Displacement methods: rely on measuring either volumetrically or gravimetrically the fluid displaced by the sample.
Gravimetric methods observe the loss in weight of the sample when immersed in a fluid, or observe the change in weight of a pycnometer filled with mercury and with mercury and the sample.
Volumetric methods measure the change in volume when the sample is immersed in fluid.
Example
SKPP 1313: FUND. OF PETROLEUM ENGINEERING
CHAPTER 3: ROCK & FLUID PROPERTIES (13) MOHD FAUZI HAMID
A clean, dry sample weighed 20 gms. This sample was saturated in water of density 1.0 gm/cc and then reweighed in air, resulting in an increase in weight to 22.5 gms. The saturated sample was immersed in water of the same density and subsequently weighed 12.6 gms. What is the bulk volume of the sample?
Weight of water displaced: Wdisplaced = 22.5g – 12.6g = 9.9g
Bulk volume: Vb = Wdisplaced/w = 9.9g/1g/cc = 9.9cc
Permeability
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CHAPTER 3: ROCK & FLUID PROPERTIES (14) MOHD FAUZI HAMID
The permeability of a rock is a measure of the ease with which fluids can flow through a rock. This depends on how well the pore spaces within that rock are interconnected.
Good Permeability Poor Permeability
Permeability (cont’d)
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CHAPTER 3: ROCK & FLUID PROPERTIES (15) MOHD FAUZI HAMID
Permeability is a measure of the ability of a porous material to transmit fluid under a potential gradient.
The unit for permeability (k) is darcy named after a French scientist, Henry Philibert Gaspard Darcy who investigated flow of water through filter beds in 1856.
1 Darcy = 0.987 x 10-12 m2.
Permeability (cont’d)
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CHAPTER 3: ROCK & FLUID PROPERTIES (16) MOHD FAUZI HAMID
The general darcy’s equation is:
dL
dPk
A
QQ = flowrate (cm3/sec)
k = permeability (darcy)
A = cross section area (cm2)
= fluid viscosity (cp)
P = pressure (atm)
L = length (cm)
where:
Q
L
P1 P2
A
Permeability (cont’d)
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CHAPTER 3: ROCK & FLUID PROPERTIES (17) MOHD FAUZI HAMID
1 darcy is defined as the permeability that will permit a fluid of 1 centipoise viscosity to flow at a rate of 1 cubic centimeter per second through a cross sectional area of 1 square centimeter when the pressure gradient is 1 atmosphere per centimeter.
Q
L
A
P1 P2
Q = 1cm3/sec
A = 1cm2
= 1 cp
P = 1atm
L = 1cm
Find k ?
Permeability (cont’d)
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CHAPTER 3: ROCK & FLUID PROPERTIES (18) MOHD FAUZI HAMID
There are four conditions that are required for this equation to be valid:
Laminar flow.
No accumulation.
Single-phase liquid flow.
The porous media is not reactive with the flowing fluid.
Plot of Q/A against dP/dL should yield a single straight line as shown below where the slope = k/ = fluid mobility.
dP/dL
Q/A
k/
Linear Flow
SKPP 1313: FUND. OF PETROLEUM ENGINEERING
CHAPTER 3: ROCK & FLUID PROPERTIES (19) MOHD FAUZI HAMID
Q
L
P1P2
L
PPkAQ 21
sing
L
PPkAQ 21
sing
L
PPkAQ 21
Radial Flow
SKPP 1313: FUND. OF PETROLEUM ENGINEERING
CHAPTER 3: ROCK & FLUID PROPERTIES (20) MOHD FAUZI HAMID
2
2
2
2ln
2
ln
wfw
e e
pr
r p
wwf e
e
e wf
e w
kA dPQ
dR
k h dPQ R
dR
dR khdP
R Q
dR khdP
R Q
r khP P
r Q
kh P PQ
r r
Pe
h
rwre
Pwf
Q = flowrate (cm3/sec)
k = permeability (darcy)
h = reservoir thickness (cm)
= fluid viscosity (cp)
P = pressure (atm)
r = radius (cm)
where:
Radial Flow (cont’d)
SKPP 1313: FUND. OF PETROLEUM ENGINEERING
CHAPTER 3: ROCK & FLUID PROPERTIES (21) MOHD FAUZI HAMID
Pe
h
rwre
Pwf
7.08
ln
e wf
e w
kh P PQ
r r
Q = flowrate (bbl/day)
k = permeability (darcy)
h = reservoir thickness (ft)
= fluid viscosity (cp)
P = pressure (psi)
r = radius (ft)
where:
In field unit:
1 bbl = 159,000 cc
1 ft = 30.48 cm
1 atm = 14.7 psi
Averaging Permeability (Parallel Sand)
SKPP 1313: FUND. OF PETROLEUM ENGINEERING
CHAPTER 3: ROCK & FLUID PROPERTIES (22) MOHD FAUZI HAMID
Arithmetic averages
Q n21
ni
1i
i QQQQQ
i
ii
i
ii
iii
nn2211
ni
1i
i
h
hk or
A
Akk
AkAk
L
PAk
L
PAk
L
PAk
L
PAk
k1, h1, Q1
LA1
An
A2k2, h2, Q2
kn, hn, Qn
Averaging Permeability (Series Sand)
SKPP 1313: FUND. OF PETROLEUM ENGINEERING
CHAPTER 3: ROCK & FLUID PROPERTIES (23) MOHD FAUZI HAMID
k1
L1
P1
k2
L2
P2
kn
Ln
Pn
AQ
ni
1i
n21i PPPPP
Harmonic averages
ni
1i i
i
ni
1i
i
k
L
L
k Prove it ?
L
Given:
Porosity = 0.19
Effective horizontal permeability, md = 8.2
Pay zone thickness, ft = 53
Reservoir pressure (Pavg), psi = 5,651
Flowing Bottomhole pressure (Pwf), psi = 1,000
Bubble point pressure, psi = 5,651
Oil formation volume factor, bbl/STB = 1.1
Oil viscosity, cp = 1.7
Drainage area, acres = 640
Wellbore radius, ft = 0.328
Calculate the flow rate.24
Example
SKPP 1313: FUND. OF PETROLEUM ENGINEERING
CHAPTER 3: ROCK & FLUID PROPERTIES (24) MOHD FAUZI HAMID
25
Permeability Measurement
SKPP 1313: FUND. OF PETROLEUM ENGINEERING
CHAPTER 3: ROCK & FLUID PROPERTIES (25) MOHD FAUZI HAMID
Permeability of core sample can be measured by liquid permeameter and gas permeameter.
Liquid permeameter:
Non reactive liquid (paraffin oil) is forced to flow through a core sample in a core holder.
A flow rate is measured, and permeability is calculated using general Darcy equation.
Gas permeameter:
Non reactive gas (typically helium) is used in the measurement of permeability.
The gas is flow through the sample, and the flow rate of gas is measured.
26
Permeability Measurement (cont’d)
SKPP 1313: FUND. OF PETROLEUM ENGINEERING
CHAPTER 3: ROCK & FLUID PROPERTIES (26) MOHD FAUZI HAMID
Figure below illustrates the schematic diagram of the Hassler-type permeability measurement under steady state flow conditions.
27
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CHAPTER 3: ROCK & FLUID PROPERTIES (27) MOHD FAUZI HAMID
The permeability is calculated using following modified form of darcy equation which takes into account the gas compressibility during flow.
LP2
PPk
A
Q
a
2
2
2
1g
2
2
2
1
a
gPPA
LPQ2k
Q = gas flowrate (cm3/sec)kg = gas permeability (darcy)A = cross section area (cm2) = fluid viscosity (cp)P1 = inlet pressure (atm)P2 = outlet pressure (atm)Pa = atmospheric pressure (atm)L = length (cm)
where:
28
Slippage Phenomenon during k Measurement
SKPP 1313: FUND. OF PETROLEUM ENGINEERING
CHAPTER 3: ROCK & FLUID PROPERTIES (28) MOHD FAUZI HAMID
Gas permeability dependent on the mean pressure of the gas existing at the time of measurement.
At low mean gas pressure, gas permeability exceeds liquid permeability.
At high mean gas pressure, gas permeability approaches liquid permeability.
Slippage effect is a laboratory phenomenon due to low flowing gas pressure, but negligible for gas flow at reservoir conditions.
v (wall) = 0
liquid
finite velocity at wall
gas
Klinkenberg Correction
Plot of kg versus the inverse of mean flow pressure (1/Pm) yields a straight line with slope k b and an intercept of k. “b” is klinkenberg slippage function.
Slope is a function of molecular weight and molecular size.
1/Pm
kg
k
m
gP
b1kk
2
PPP 21
m
29
SKPP 1313: FUND. OF PETROLEUM ENGINEERING
CHAPTER 3: ROCK & FLUID PROPERTIES (29) MOHD FAUZI HAMID
The klinkenberg effect plot
kL
30
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CHAPTER 3: ROCK & FLUID PROPERTIES (30) MOHD FAUZI HAMID
Rock and Fluid Interaction
Interfacial tension.
Capillary pressure.
Wettability.
Relative permeability.
Stock tank oil initially in place (STOIIP).
31
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CHAPTER 3: ROCK & FLUID PROPERTIES (31) MOHD FAUZI HAMID
Interfacial Tension
32
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CHAPTER 3: ROCK & FLUID PROPERTIES (32) MOHD FAUZI HAMID
Interfacial tension is a force at the interface that acts to decrease the area of the interface.
A drop of water can hang down from the edge of a glass tube using the force at the interface.
However, when the interfacial tension is weaker, only a smaller (lighter) drop can hang down from the edge of the glass.
The interfacial tension can be measured using this phenomenon.
33
SKPP 1313: FUND. OF PETROLEUM ENGINEERING
CHAPTER 3: ROCK & FLUID PROPERTIES (33) MOHD FAUZI HAMID
The reason why surface tension is decreased when something is adsorbed on the surface.
The attractive force between water molecules is greater than that between other molecules because of the hydrogen bonding.
At the surface, the attractive force works only from inside since there is no water on the outside (air side), so a water molecule on the surface is strongly attracted toward the inside.
This force is called “surface tension”. However, when something is adsorbed on the water surface, interactions between the adsorbed molecules themselves and also the adsorbed molecules and the water occur at the surface, so that the surface tension decreases.
34
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CHAPTER 3: ROCK & FLUID PROPERTIES (34) MOHD FAUZI HAMID
Wettability
35
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CHAPTER 3: ROCK & FLUID PROPERTIES (35) MOHD FAUZI HAMID
The wettability of a liquid is defined as the contact angle between a droplet of the liquid in thermal equilibrium on a horizontal surface.
The wetting angle is given by the angle between the interface of the droplet and the horizontal surface.
The liquid is seemed wetting when 90<<180 and non-wetting when 0<<90.
.
Oil θ θ
“Water wet” “Oil wet”
36
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CHAPTER 3: ROCK & FLUID PROPERTIES (36) MOHD FAUZI HAMID
The wetting phase will tend to spread on the solid surface and a porous solid will tend to imbibe the wetting phase.
Rocks can be water wet, oil wet or intermediate wet.
The intermediate state between water wet and oil wet can be caused by a mixed-wet system, in which the surfaces are not strongly wet by either water or oil.
Capillary Pressure
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CHAPTER 3: ROCK & FLUID PROPERTIES (37) MOHD FAUZI HAMID
Capillary pressure is the pressure difference existing across the interface separating two immiscible fluids.
It is defined as the difference between the pressures in the non-wetting and wetting phases. That is:
For an oil-water system (water wet):
For a gas-oil system (oil-wet):
Pc = Pnw - Pw
Pc = Po - Pw
Pc = Pg - Po
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CHAPTER 3: ROCK & FLUID PROPERTIES (38) MOHD FAUZI HAMID
Oil-water system.
o2 w 2
w 2 w1 w
o2 o1 o
w 2 o2
w1 w o1 o
o1 w1 w 0
c w o
P P
P P h g
P P h g
Since, P P
Then, P h g P h g
There fore, P P hg
That is, P hg
Relative Permeability
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CHAPTER 3: ROCK & FLUID PROPERTIES (39) MOHD FAUZI HAMID
Relative permeability measurements are made routinely on core samples, to define the relative amounts of fluids that will flow through the rocks when more than one fluid phase is flowing.
Definitions are:
a
o
rok
kk
a
w
rwk
kk
a
g
rgk
kk
o, w, g = oil, water, gas
kr = relative permeability
k = permeability to a specific fluid, o, w, or g
ka = theoretical “air” permeability
where:
STOIIP
40
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CHAPTER 3: ROCK & FLUID PROPERTIES (40) MOHD FAUZI HAMID
In place volumes of oil is always quoted at surface conditions.
o
oB
1 x S x x
G
N x GRV x 7758 STOIIP
STOIIP = Stock tank oil initially in place, barrels
GRV = Gross volume of rock, acre-ft
N/G = Net to gross ratio
= Porosity
So = Oil saturation
Bo = Oil formation volume factor, reservoir bbl/STB
where:
STOIIP
41
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CHAPTER 3: ROCK & FLUID PROPERTIES (41) MOHD FAUZI HAMID
In most cases, it’s convenient to simplify to:
1 7758 x o
o
STOIIP BV x x S xB
BV = Bulk volume of reservoir, acre-ft
where:
1 acre = 43,560 ft2
1 acre-ft = 43,560 ft3
1 bbl = 42 gal = 5.61 cuft1 acre-ft = 43,560/5.61 = 7758 bbl
Example
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CHAPTER 3: ROCK & FLUID PROPERTIES (42) MOHD FAUZI HAMID
An oil well has been drilled and completed. The production zone has been encountered at depth 5,220 – 5,354 ft. The log analysis showed that:
Average porosity = 21%
Water saturation = 24%
Formation volume factor = 1.476 bbl/STB
Area = 93 acres
Calculate the STOIIP.
OGIP
43
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CHAPTER 3: ROCK & FLUID PROPERTIES (43) MOHD FAUZI HAMID
OGIP:
1 43,560 x gi
gi
OGIP BV x x S xB
BV = Bulk volume of reservoir, acre-ft
Sgi = Initial gas saturation
Bgi = Initial gas formation volume factor, cu.ft/SCF
where:
Type of Reservoir
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CHAPTER 3: ROCK & FLUID PROPERTIES (44) MOHD FAUZI HAMID
Oil Reservoir.
Contain mainly oil with or without free gas (gas cap).
Can be divided into two:
Undersaturated Oil Reservoir (Pres > Pb) - no free gas exists until the reservoir pressure falls below the bubblepoint pressure.
Saturated Oil Reservoir (Pres < Pb) – free gas (gas cap) exists in the reservoir.
Gas Reservoir
Recovery
45
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CHAPTER 3: ROCK & FLUID PROPERTIES (45) MOHD FAUZI HAMID
Recovery of hydrocarbons from an oil reservoir is commonly recognised to occur in several recovery stages. These are:
Primary Recovery.
the recovery of hydrocarbons from the reservoir using the natural energy of the reservoir as a drive.
Secondary Recovery.
the recovery aided or driven by the injection of water or gas from the surface.
Recovery (cont’d)
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CHAPTER 3: ROCK & FLUID PROPERTIES (46) MOHD FAUZI HAMID
Tertiary Recovery (Enhance Oil Recovery – EOR).
A range of techniques broadly labelled ‘Enhanced Oil Recovery’ that are applied to reservoirs in order to improve flagging production.
Infill Recovery.
Carried out when recovery from the previous three phases have been completed. It involves drilling cheap production holes between existing boreholes to ensure that the whole reservoir has been fully depleted of its oil.
Drive Mechanism
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CHAPTER 3: ROCK & FLUID PROPERTIES (47) MOHD FAUZI HAMID
The natural energy of the reservoir used to transport hydrocarbons towards and out of the production wells.
There are five important drive mechanisms (or combinations).
Solution Gas Drive.
Gas Cap Drive.
Water Drive.
Gravity Drainage.
Combination or Mixed Drive
A combination or mixed drive occurs when any of the first three drives operate together or when any of the first three drives operate with the aid of gravity drainage.
Solution Gas Drive
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CHAPTER 3: ROCK & FLUID PROPERTIES (48) MOHD FAUZI HAMID
This mechanism (also known as depletion drive) depends on the associated gas of the oil.
The virgin reservoir may be entirely liquid, but will be expected to have gaseous hydrocarbons in solution due to the pressure.
As the reservoir depletes (due to production), the pressure falls below the bubble point, and the gas comes out of solution to form a gas cap at the top. This gas cap pushes down on the liquid helping to maintain pressure.
The exsolution and expansion of the dissolved gases in the oil and water provide most of the reservoirs drive energy.
Solution Gas Drive
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CHAPTER 3: ROCK & FLUID PROPERTIES (49) MOHD FAUZI HAMID
Solution Gas Drive Reservoir
Gas Cap Drive
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CHAPTER 3: ROCK & FLUID PROPERTIES (50) MOHD FAUZI HAMID
In reservoirs already having a gas cap (the virgin pressure is already below bubble point), the gas cap expands with the depletion of the reservoir, pushing down on the liquid sections applying extra pressure.
The presence of the expanding gas cap limits the pressure decrease experienced by the reservoir during production.
Gas Cap Drive
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CHAPTER 3: ROCK & FLUID PROPERTIES (51) MOHD FAUZI HAMID
Gas Cap Drive Reservoir
Water Drive
52
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CHAPTER 3: ROCK & FLUID PROPERTIES (52) MOHD FAUZI HAMID
The drive energy is provided by an aquifer that interfaces with the oil in the reservoir at the oil-water contact (OWC).
As the hydrocarbons depleted (production continues), and oil is extracted from the reservoir, the aquifer expands slightly. If the aquifer is large enough, this will translate into a large increase in volume, which will push up on the hydrocarbons, and thus maintaining the reservoir pressure.
Two types of water drive are commonly recognised: Bottom water drive and Edge water drive.
Water Drive
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CHAPTER 3: ROCK & FLUID PROPERTIES (53) MOHD FAUZI HAMID
Gravity Drainage
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CHAPTER 3: ROCK & FLUID PROPERTIES (54) MOHD FAUZI HAMID
The density differences between oil and gas and water result in their natural segregation in the reservoir. This process can be used as a drive mechanism, but is relatively weak, and in practice is only used in combination with other drive mechanisms.
Combination
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CHAPTER 3: ROCK & FLUID PROPERTIES (55) MOHD FAUZI HAMID
In practice a reservoir usually incorporates at least two main drive mechanisms.
Mixed Drive Reservoir
Secondary Recovery
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CHAPTER 3: ROCK & FLUID PROPERTIES (56) MOHD FAUZI HAMID
Secondary recovery is the result of human intervention in the reservoir to improve recovery when the natural drives have diminished to unreasonably low efficiencies.
Two techniques are commonly used:
Waterflooding – involve injection of water at the base of a reservoir to:
Maintain the reservoir pressure, and
Displace oil towards production wells.
Gas Injection - This method is similar to waterflooding in principal, and is used to maintain gas cap pressure even if oil displacement is not required
Tertiary Recovery (EOR)
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CHAPTER 3: ROCK & FLUID PROPERTIES (57) MOHD FAUZI HAMID
Primary and secondary recovery methods usually only extract about 35% of the original oil in place. Clearly it is extremely important to increase this figure.
Many enhanced oil recovery methods have been designed to do this, and a few will be reviewed here. They fall into three broad categories:
Thermal EOR
Chemical EOR
Miscible Gas
All are extremely expensive, are only used when economical.
Thermal EOR
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CHAPTER 3: ROCK & FLUID PROPERTIES (58) MOHD FAUZI HAMID
These processes use heat to improve oil recovery by reducing the viscosity of heavy oils and vaporising lighter oils, and hence improving their mobility.
The techniques include:
Steam Injection.
In-situ combustion (injection of a hot gas that combusts with the oil in place.
Increasing the relative permeability to oil (micellar and alkaline floods).
Thermal EOR is probably the most efficient EOR approach.
Thermal EOR
Schematic Diagram of Steam Flooding EOR
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CHAPTER 3: ROCK & FLUID PROPERTIES (59) MOHD FAUZI HAMID
Schematic Diagram of In Situ Combustion EOR
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CHAPTER 3: ROCK & FLUID PROPERTIES (60) MOHD FAUZI HAMID
Thermal EOR (cont’d)
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CHAPTER 3: ROCK & FLUID PROPERTIES (61) MOHD FAUZI HAMID
Schematic Diagram of Microwave EOR
Chemical EOR
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These processes use chemicals added to water in the injected fluid of a waterflood to alter the flood efficiency in such a way as to improve oil recovery.
This can be done in many ways, examples are listed below:
Increasing water viscosity (polymer floods).
Decreasing the relative permeability to water (cross-linked polymer floods).
Microwave heating downhole.
Hot water injection.
Chemical EOR (cont’d)
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Miscible Gas Flooding
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This method uses a fluid that is miscible with the oil. Such a fluid has a zero interfacial tension with the oil and can in principal flush out all of the oil remaining in place.
In practice a gas is used since gases have high mobilities and can easily enter all the pores in the rock providing the gas is miscible in the oil.
Three types of gas are commonly used:
CO2
N2
Hydrocarbon gases.
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Schematic Diagram of Miscible WAG Flooding EOR
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Natural depletion– Fluid expansion
– Solution gas drive
– Gas cap drive
– Water drive
– Compaction drive
– Combination drive
Primary recovery factors– Solution gas drive 5% – 20%
– Gas cap drive 20% – 40%
– Water drive 40% – 60%
– Compaction drive up to +10%
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Enhanced recovery:– Water injection
– Gas injection
– Steam injection
– WAG injection
– etc.
Degree of improvement dependent on:– Type of scheme implemented
– Properties of the reservoir rock
– Properties of the oil
– Well spacing
– Economics