Day 4

IP 700
Physical properties of rocks
• The evaluation of a reservoir requires three basics data requirements:
porosity, permeability and fluid saturation.
• Porosity
Porosity is the first of the three essential attributes of a reservoir. It is
a measure of the void space within a rock, expressed as a fraction (or
percentage) of the bulk volume of that rock. It is conventionally
symbolized by the Greek lowercase letter phi (φ).
Porosity cnt’d
• The general expression for porosity is:
•  () =
• Volumes of voids or pores are of three morphological types: catenary,
cul-de-sac and closed.
• Catenary pores are those that communicate with other by more than
one throat passage.
• Cul-de-sac or dead-end pores have only one throat passage
connecting with another pore.
• Closed pores have no communication with other pores.
Porosity cnt’d
Porosity may be measured in three ways:
directly from cores, indirectly from
geophysical well logs, or from seismic data.
Porosity cnt’d
• Volume of shale
• The shale volume is needed to correct the porosity and water
saturation, for their biased effects. It is considered as an indicator of
reservoir quality in which the lower shale content usually reveals a
better reservoir.
• The value of clay content is derived from different shale indicators
such as gamma-ray, neutron, and resistivity. Only the GR method will
be developed during this course.
Porosity cnt’d
Gamma Ray Method
• It is one of the best methods used for identifying and determining shale
volume, principally due to its sensitive response to radioactive minerals
normally concentrated in the shaly formation.
• According to figure below, considering the maximum average gamma ray
log value to be pure 100% shale (shale line) and lowest value to indicate no
shale at all (sand line), a scale from 0-100% shale can be constructed. If the
scale is considered to be linear, any value (GR) of the gamma-ray log will
give the gamma-ray index from the linear equation:
GR (log)−GR(min)
• IGR = GR(max)−GR(min)
Porosity cnt’d
= Gamma-ray Index
GR (log) = Gamma-ray reading from the log
GR (min) = Gamma-ray sand line
GR (max) = Gamma-ray shale line
Porosity cnt’d
Porosity cnt’d
• Generally, the value IGR is not very accurate and tends to give an upper
limit to the volume of shale. Moreover, there is no scientific basis for
assuming that the relationship between gamma-ray value and shale
volume should be linear. Thus, Dresser Atlas proposed a new approach as a
result of empirical correlation where the relationship changes according to
the age or volume content of the formation.
• Older rocks (Paleozoic and Mesozoic), consolidated:
• Vsh = 0.33 (22IGR -1)
• Younger rocks (Tertiary), unconsolidated:
• Vsh = 0.083 (23.7IGR -1)
• Steiber also suggested an empirical equation:
• Vsh = 0.5 (IGR / (1.5 – IGR))
Porosity cnt’d
• As per porosity classification, formation are ranged according to their
• If Vsh ≤ 10 %
we are in a clean zone
• If 10 % <Vsh ≤ 35 %
We are in a shaly zone
• If Vsh> 35 %
we are in a shale zone
Porosity cnt’d
• Porosities in the reservoir rocks usually range from 5 % to 48 % depending
of the arrangement (cubic or rhombohedral), size and sorting of the rock.
In general, porosities tend to be lower in deeper and older (consolidated)
formations, due to cementation and overburden pressure stress on the
rock. Likewise, the porosity of shale decreases rapidly with depth than
• As emphasized, there are many descriptions of porosity but the two
common are the total and the effective porosity.
• Total porosity can be estimated from a single log (sonic, density and
neutron) or the combination of two logs (neutron – density), while
effective porosity involves subtraction between total porosity and volume
of shale.
Porosity cnt’d
• Sonic porosity
• The porosity estimated from the sonic log does not see fractures and vugs; therefore it
only reacts to primary porosity.
• The determination of porosity depends on Wylie’s et al. (1958) equation:
ΔTlog− ΔTma
ФS= ΔTf− ΔTma
In the case the compaction factor is considered, the equation became:
With: CP =
ΔTlog− ΔTma
× CP
ΔTf− ΔTma
• The effective porosity formula derived was suggested by Dresser Atlas:
ΔTlog− ΔTma 1
× CP)
ΔTf− ΔTma
ФSeff= (
ΔTsh− ΔTma
- ( ΔTf− ΔTma ) (15)
Porosity cnt’d
• Where:
= Sonic porosity
ФSeff = effective porosity
ΔTlog = Formation of interest sonic log reading
ΔTma = Matrix travel-time
ΔTf = Mud fluid travel-time (189 µs / ft).
ΔTsh = Transit time within shale material
CP = Compaction factor
Vsh = Volume of shale.
Porosity cnt’d
• Density porosity
Density tool reads extremely high porosity values.
i. Density porosity can be determined from the relationship
Ф D=
ρma− ρb
ρma− ρf
ii. The effective porosity derived is expressed as follows:
ФDeff= (
ρma− ρb
ρma− ρf
) – Vsh (
ρma− ρsh
ρma− ρf
Porosity cnt’d
• Where:
ФD = Density porosity
φDeff = Effective porosity
ρma = Matrix density
ρb = Bulk density measured by the tool
ρsh = Shale zone density
Vsh = Volume of shale
ρf = Fluid density.
Porosity cnt’d
• Fluid density ρf and matrix density ρma varies respectively according
to the fluid injected during drilling and the lithology of the formation.
• For:
• Fresh water mud, ρf = 1.0 g/cm3
• Salt water mud, ρf = 1.1 g/cm3
• Gas mud, ρf = 0.7 g/cm3.
Porosity cnt’d
Range (g/cm3)
Matrix (g/cm3)
1.8 – 2.75
Varies (Av. 2.65 – 2.70)
1.9 – 2.65
2.2 – 2.71
2.3 – 2.87
• Neutron Porosity
• Neutron logs give directly the porosity values on the log track in a clean
formation. It is different from the density and sonic tools because it can
read extremely low porosity within a formation. However in shaly
formations, the effect of clays must be corrected through the following
ФNc= ФNlog – Vsh × ФNsh
• Where:
ФNc= Neutron porosity corrected
ФNlog = Formation of interest neutron log reading
ФNsh = Neutron shale zone
Vsh = Volume of shale.
Porosity cnt’d
• Neutron-Density Porosity.
• The combination of a neutron log which measures the Hydrogen Index (fluid content) of
a formation, and bulk density log which reads both the matrix and fluid content of a
formation is considered as a good approach for determining porosity.
i. The total porosity is calculated from the method below:
φN-D= 0.5 (φN– φD)
ii. The effective porosity is:
φN-Deff = (0.5 × (φNC2+ φDC2))0.5
• Where:
• φNC = φN– (0.45
) × 0.30 × Vsh
• φDC = φD– (0.45
) × 0.13 × Vsh
• The second essential requirement for a reservoir rock is permeability.
Porosity alone is not enough, the pores must be connected.
Permeability is the ability of fluids to pass through a porous material.
It is controlled by the size of the available pores and the connecting
passage between them.
• The unit of permeability is the Darcy. Darcy’s law is used to calculate
permeability. It is defined as the permeability (symbolized by K), that
allows a fluid of 1 centipoise (cP) viscosity to flow at a velocity of
1cm/s for a pressure drop of 1atm/cm.
Permeability cnt’d
• . Because most reservoirs have permeabilities much less than a Darcy, the millidarcy
(mD) is commonly used. The formula of Darcy’s law is:
(P1 – P2)
K P1 − P2 A
rate of flow
Pressure drop across the sample
cross-sectional area of the sample
length of the sample
viscosity of the fluid
Permeability cnt’d
• The absolute permeability is the ability of a rock to transmit a fluid
100% saturated with one fluid. It is when a single fluid flow through
the formation. However, since petroleum reservoirs contain gas and/
or oil and water, the effective permeability for given fluids in the
presence of others must be considered. It is the ability of a rock to
transmit a fluid in the presence of another fluid when the two are
• The ratio of effective permeability of a fluid at partial saturation to its
permeability at 100% saturation (absolute permeability) is the relative
Permeability cnt’d
• It is also defined as the ratio of the amount of a specific fluid that will
flow at a given saturation, in the presence of other fluids, to the
amount of the same fluid that will flow at a saturation of 100%, other
factors remaining the same.
• It should be noted that the sum of effective permeability will always
be less than the absolute permeability. This is due to the mutual
interference of the several flowing fluids.
• The permeability of a reservoir can be measured in three ways: by
means of drill-stem or production test, from wireline logs, and using a
Permeability cnt’d
• The permeability can be predicted from different models:
• The Wyllie and Rose equation:
• √ K = C × Φ3 / Swir
• Where:
• K = Permeability
• C = Factor that depends on the density of the hydrocarbon.
• Ф = Porosity
• Swir = Irreducible water Saturation
Permeability cnt’d
• The Morris and Biggs (1967) as model modified by Timur in 1968 and Schlumberger in 1972 as
K = a × (Фb / Swirc)
• Where:
K = Permeability
Ф= Porosity
Swir = Irreducible water saturation
• The constants a, b and c for Timur, Morris-Biggs, and Schlumberger models are given below:
• Morris-Biggs for gas:
a= 6241; b = 6 and c = 2
• Timur:
a = 8581; b = 4.4 and c = 2
• Schlumberger:
a = 10000; b = 4.5 and c = 2
Permeability cnt’d
• In the case where laboratory measurements are available, a function
can be estimated from the crossplot of core porosity against core
permeability, and then applied to the non-core wells for permeability
Fluid saturation
• Porosity can be stated as the capacity to hold fluid. Fluid saturation is
the fraction (or percentage) of the storage capacity of a rock occupied
by a specific fluid. It is generally defined by:
• Fluid saturation (Sf ) =
Formation fluid occupying pores
Total pore spaces in the rock
• The fluid in the pore spaces of a rock may be wetting or non-wetting.
In most reservoirs, water is the wetting phase while few reservoirs are
known to be oil wet. The wetting phase exists as an adhesive film on
the solid surface.
Fluid saturation cnt’d
• Water saturation (Sw) is the fraction of the pore volume occupied by
a specific fluid; 1-Sw is the fraction of the pore volume occupied by
hydrocarbons (Sh); it is measured in percentage.
• Some of the fluids in the reservoir cannot be produced. This portion
of the fluid is referred to as residual or irreducible saturation (Swirr).
It is the water saturation, at which the water is absorbed on the
grains in the rock, or held in capillaries by capillary pressure. At
irreducible water saturation, water (wetting phase) will not move
implying a zero relative permeability and the non-wetting phase is
usually continuous and is producible under a pressure gradient of the
well bore
Fluid saturation
• Formation water resistivity
• The formation water resistivity is the resistivity value of the water,
uncontaminated by the drilling mud and that saturates the porous
• It is estimated during reservoir core analysis, from clean non-shaly
water filled sandstone using the relationship between formation
factor and shale free, water filled rock defined by Archie in 1942.
• The method consists of saturating cores of different porosities with
varieties of brines. The resistivity of the water (Rw) and the resistivity
of the 100 % water saturated rock (Ro) are measured.
Fluid saturation cnt’d
• Then, the results are plotted and the series of straight lines of slopes
are referred to as the electrical formation factor F.
• Archie also discovered from other experiments that the rock
formation factor could be related to the porosity of the rock .
Therefore, the rock formation factor F is defined as the resistivity of a
rock sample completely saturated with water (Ro) to the resistivity of
the water (Rw). The relationship derived is:
(21) Related to F =
Fluid saturation cnt’d
• Where:
F = Rock formation factor
Ro = Resistivity of a rock 100 % water saturated
Rw = Resistivity of water
Ф = Porosity
m = Cementation exponent.
Fluid saturation
• Few years later, Winsauer and McCardell (1953) also conducted some
experimental measurements on cores, and this resulted in another
equation relating F and Ф of the form:
F= m
• Where:
F = Rock formation factor
a = Tortuosity factor
Ф = Porosity
m = Cementation exponent.
Fluid saturation cnt’d
• Rw= (
) × Ro
by rearranging equations
• In shaly zones, Crain recommended the following parameters:
• For tight sandstones, a = 0.81 and m = 2.00 (F < 15 %)
• For porous sandstones, a = 0.062 and m = 2.15 (F > 15 %)
• For carbonates, a = 1 and m = 2.
• The water resistivity can also be estimated from Spontaneous
Potential log in water bearing clean sandstone.
Fluid saturation cnt’d
Fluid saturation cnt’d
• Formation resistivity
• The formation resistivity Rt and Rxo are taken directly from the logs.
Rxo represents the invaded or flushed zone resistivity and is directly
read from Spherically Focused Log (SFLU), Microspherically Focused
Log (MSFL) and Shallow Laterolog (LLS), while Rt refers to the
uninvaded zone resistivity or true formation resistivity recorded by
Deep Induction Log (ILD) and Deep Laterolog (LLD).
Fluid saturation cnt’d
• Water saturation
• Different methods can be used to evaluate the water saturation of a
reservoir formation:
• The Archie method which involves clean sandstone formations.
• The shaly sand method comprising the resistivity approach
(Simandoux model, Poupon and Leveaux model, Schlumberger
model, Indonesian model) and the conductivity approach (Waxmansmith model, Dual-water model, Juhasz model).
• In this study, only Archie and resistivity (Poupon and Leveaux,
Simandoux) methods will be developed.
Fluid saturation cnt’d
• Archie developed an equation resulting from his experiment on voids
saturation. He found that water saturation of the rocks could be
related to their resistivity. The formula showed that increasing
porosity will reduce the water saturation for the same resistivity in a
clean (homogenous) formation. Thus, the relationship between those
parameters was mathematically expressed as:
Sw = (
Rw 1/n
Fluid saturation cnt’d
• Where:
= Water saturation
= Tortuosity factor
= Cementation factor
= Saturation exponent
= Porosity of the formation
= Deep resistivity of the formation.
Fluid saturation cnt’d
• Poupon and Leveaux proposed an empirical model based on
characteristic of fresh water and high degree of shaliness that were
present in many oil reservoirs in Indonesia:
√ Фem Vsh
(a × Rw+ √Rsh
Fluid saturation cnt’d
• Simandoux equation
Simandoux developed adequate equation for shaly (heterogeneous)
formations, shown as follow:
Vsh ×Sw
a × Rw
Rsh = Resistivity of a thick shale unit.
Fluid saturation
• Hydrocarbon saturation
• The hydrocarbon saturation can be deduced from water saturation by
the following relationship:
• Shc = 1 – Sw
• It is normally differentiated into the non-exploitable or residual
hydrocarbon (Shr) and the exploitable or movable hydrocarbon (Shm),
as follow:
• Shc = Shr + Shm
Fluid saturation cnt’d
• Irreducible water saturation
• It is the residual water around the grain of rocks that cannot be
moved out of the reservoir with oil or water.
• In a clean formation,
Swir = Фe × Sw
• In shaly formation,
Swir =
ФT × Sw
1−ℎ 2
× Фe
Fluid saturation cnt’d
• Where:
Swir = Irreducible water saturation
ФT = Total porosity
Sw = Water saturation
Vsh = Volume of shale
Фe= Effective porosity
Wireline log correlation
• Definition
• A wireline log correlation is the identification and linkage of similar
marker horizons along different wells, which maybe a distinctive peak
(unconformities), distinctive shape (stratigraphy) or distinctive
lithology with unique log response. It is a combination of basic
geological principles which include the understanding of depositional
environment, concepts of logging tools and measurements, and
qualitative log analysis.
Wireline log correlation cnt’d
• Well log correlation is used in reservoir characterization to
understand the lateral extent of sandstone reservoirs within a specific
sequence. Therefore, the accuracy of a prepared geological
interpretation is determined by the correctness of correlations
• Since the gamma ray log value in shale remains constant laterally at
the same stratigraphic level and the gamma ray value of sandstone is
rather constant vertically, wireline logs correlation is an appropriate
method to understand the thickness of sandstone formations.
Wireline log correlation cnt’d
• Distinctive shapes:
• Bell shape consists of a regular increase in gamma-ray value upwards
from a minimum value and corresponds to an increase in clay content
upwards. It is associated with an alluvial or a fluvial channel, but also
with a transgressive shelf sand which indicates a finning up sequence.
• Funnel shape characterizes a deltaic or shallow marine environment.
It corresponds to a coarsening up succession materialized by a regular
decrease in gamma-ray value upwards from a maximum value.
• Cylinder or block shape is more complex. It indicates a constant
energy throughout the cycle.
Wireline log correlation cnt’d
Wireline log correlation cnt’d
• Recovery of hydrocarbons from an oil reservoir is commonly
recognized to occur in several recovery stages. These are:
(i) Primary recovery
(ii) Secondary recovery
(iii) Tertiary recovery (Enhanced Oil Recovery, EOR)
(iv) Infill recovery
Introduction cnt’d
• Primary recovery
This is the recovery of hydrocarbons from the reservoir using the natural
energy of the reservoir as a drive.
• Secondary recovery
This is recovery aided or driven by the injection of water or gas from
the surface.
• Tertiary recovery (EOR)
There are a range of techniques broadly labelled ‘Enhanced Oil
Recovery’ that are applied to reservoirs in order to improve flagging
Introduction cnt’d
• Infill recovery Is 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.
• This part will discuss primary, secondary and EOR drive mechanisms
and techniques.
Primary Recovery Drive Mechanisms
• During primary recovery the natural energy of the reservoir is used to
transport hydrocarbons towards and out of the production wells.
There are several different energy sources, and each gives rise to a
drive mechanism. Early in the history of a reservoir the drive
mechanism will not be known. It is determined by analysis of
production data (reservoir pressure and fluid production ratios). The
earliest possible determination of the drive mechanism is a primary
goal in the early life of the reservoir, as its knowledge can greatly
improve the management and recovery of reserves from the reservoir
in its middle and later life.
Primary Recovery Drive Mechanisms cnt’d
• There are five important drive mechanisms (or combinations). These
(i) Solution gas drive
(ii) Gas cap drive
(iii) Water drive
(iv) Gravity drainage
(v) Combination or mixed drive
• Table 1 shows the recovery ranges for each individual drive
Primary Recovery Drive Mechanisms cnt’d
Drive Mechanism
Energy Source
Recovery, % OOIP
Solution gas drive
Evolved gas
Gas expansion
Evolved solution gas
20 – 30
18 – 25
Gas cap drive
Gas cap expansion
20 – 40
Water drive
Aquifer expansion
20 – 60
20 – 40
35 – 60
Gravity drainage
50 – 70
Primary Recovery Drive Mechanisms cnt’d
• 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. The reservoir pressure and GOR
trends for each of the main (first) three drive mechanisms is shown as
Figures 1 and 2. Note particularly that water drive maintains the
reservoir pressure much higher than the gas drives, and has a
uniformly low GOR.
Primary Recovery Drive Mechanisms cnt’d
Fig1: Reservoir
pressure trends for
drive mechanisms.
Primary Recovery Drive Mechanisms cnt’d
Fig 2: GOR trends for
drive mechanisms
Primary Recovery Drive Mechanisms cnt’d
• Solution gas drive
• This drive mechanism requires the reservoir rock to be completely
surrounded by impermeable barriers. As production occurs the
reservoir pressure drops, and the exsolution and expansion of the
dissolved gases in the oil and water provide most of the reservoirs
drive energy. Small amounts of additional energy are also derived
from the expansion of the rock and water, and gas exsolving and
expanding from the water phase.
Primary Recovery Drive Mechanisms cnt’d
• The process is shown schematically in Figure 3. A solution gas drive
reservoir is initially either considered to be undersaturated or
saturated depending on its pressure:
· Undersaturated: Reservoir pressure > bubble point of oil.
· Saturated: Reservoir pressure £ bubble point of oil.
For an undersaturated reservoir no free gas exists until the reservoir
pressure falls below the bubblepoint. In this regime reservoir drive
energy is provided only by the bulk expansion of the reservoir rock and
liquids (water and oil).
Primary Recovery Drive Mechanisms cnt’d
• For a saturated reservoir, any oil production results in a drop in
reservoir pressure that causes bubbles of gas to exsolve and expand.
When the gas comes out of solution the oil (and water) shrink slightly.
However, the volume of the exsolved gas, and its subsequent
expansion more than makes up for this. Thus gas expansion is the
primary reservoir drive for reservoirs below the bubble point.
Primary Recovery Drive Mechanisms cnt’d
• Solution gas drive reservoirs show a particular characteristic
pressure, GOR and fluid production history. If the reservoir is
initially undersaturated, the reservoir pressure can drop by a
great deal (several hundred psi over a few months), see Figures
1 and 2. This is because of the small compressibilities of the
rock water and oil, compared to that of gas. In this
undersaturated phase, gas is only exsolved from the fluids in
the well bore, and consequently the GOR is low and constant.
Primary Recovery Drive Mechanisms cnt’d
• When the reservoir reaches the bubble point pressure, the
pressure declines less quickly due to the formation of gas
bubbles in the reservoir that expand taking up the volume
exited by produced oil and hence protecting against pressure
drops. When this happens, the GOR rises dramatically (up to
10 times).
Primary Recovery Drive Mechanisms cnt’d
Fig 3: Solution
gas reservoir.
Primary Recovery Drive Mechanisms cnt’d
Further fall reservoir pressure, as production continues, can, however,
lead to a decrease in GOR again when reservoir pressures are such that
the gas expands less in the borehole. When the GOR initially rises, the
oil production falls and artificial lift systems are then instituted. Oil
recovery from this type of reservoir is typically between 20% and 30%
of original oil in place (i.e. low). Of this only 0% to 5% of oil is recovered
above the bubblepoint. There is usually no production of water during
oil recovery unless the reservoir pressure drops sufficiently for the
connate water to expand sufficiently to be mobile. Even in this scenario
little water is produced.
Primary Recovery Drive Mechanisms cnt’d
• Gas Cap drive
• A gas cap drive reservoir usually benefits to some extent from
solution gas drive, but derives its main source of reservoir energy
from the expansion of the gas cap already existing above the
• The presence of the expanding gas cap limits the pressure decrease
experienced by the reservoir during production. The actual rate of
pressure decrease is related to the size of the gas cap.
Primary Recovery Drive Mechanisms cnt’d
• The GOR rises only slowly in the early stages of production from such
a reservoir because the pressure of the gas cap prevents gas from
coming out of solution in the oil and water. As production continues,
the gas cap expands pushing the gas-oil contact (GOC) downwards
(figure 4). Eventually the GOC will reach the production wells and the
GOR will increase by large amounts (Figures 1 and 2). The slower
reduction in pressure experienced by gas cap reservoirs compared to
solution drive reservoirs results in the oil production rates being
much higher throughout the life of the reservoir, and needing
artificial lift much later than for solution drive reservoirs. Gas cap
reservoirs produce very little or no water.
Primary Recovery Drive Mechanisms cnt’d
Fig 4: Gas cap Drive reservoir
Primary Recovery Drive Mechanisms cnt’d
• The recovery of gas cap reservoirs is better than for solution drive
reservoirs (20% to 40% OOIP). The recovery efficiency depends on the
size of the gas cap, which is a measure of how much latent energy
there is available to drive production, and how the reservoir is
managed, i.e. how the energy resource is used bearing in mind the
geometric characteristics of the reservoir, economics and equity
Primary Recovery Drive Mechanisms cnt’d
• Points of importance to bear in mind when managing a gas cap
reservoir are:
· Steeply dipping reservoir oil columns are best.
· Thick oil columns are best, and are perforated at the base, as far away
from the gas cap as possible. This is to maximise the time before gas
breaks through in the well.
· Wells with increasing GOR (gas cap breakthrough) can be shut in to
reduce field wide GOR.
· Produced gas can be separated and immediately injected back into
the gas cap to maintain gas cap pressure.
Primary Recovery Drive Mechanisms cnt’d
• Water drive
• The drive energy is provided by an aquifer that interfaces with the oil
in the reservoir at the oil-water contact (OWC). As production
continues, and oil is extracted from the reservoir, the aquifer expands
into the reservoir displacing the oil. Clearly, for most reservoirs,
solution gas drive will also be taking place, and there may also be a
gas cap contributing to the primary recovery.
• Two types of water drive are commonly recognized:
· Bottom water drive (Figure 5)
· Edge water drive (Figure 5)
Primary Recovery Drive Mechanisms cnt’d
Fig 5: Water drive reservoir
Primary Recovery Drive Mechanisms cnt’d
• The pressure history of a water driven reservoir depends critically upon:
(i) The size of the aquifer.
(ii) The permeability of the aquifer.
(iii) The reservoir production rate.
• If the production rate is low, and the size and permeability of the aquifer is
high, then the reservoir pressure will remain high because all produced oil
is replaced efficiently with water. If the production rate is too high then the
extracted oil may not be able to be replaced by water in the same
timescale, especially if the aquifer is small or low permeability. In this case
the reservoir pressure will fall (Figure 1).
Primary Recovery Drive Mechanisms cnt’d
• The GOR remains very constant in a strongly water driven reservoir
(Figure 2), as the pressure decrease is small and constant, whereas if
the pressure decrease is higher (weakly water driven reservoir) the
GOR increases due to gas exsolving from the oil and water in the
reservoir. Likewise the oil production from a strongly water driven
reservoir remains fairly constant until water breakthrough occurs.
Primary Recovery Drive Mechanisms cnt’d
• Using analogous arguments to the gas cap drive, it can be seen that
thick oil columns are again an advantage, but the wells are perforated
high in the oil zone to delay the water breakthrough. When water
breakthrough does occur the well can either be shut-down, or
assisted using gas lift. Reinjection of water into the aquifer is seldom
done because the injected water usually just disappears into the
aquifer with no effect on aquifer pressure.
Primary Recovery Drive Mechanisms cnt’d
• The recovery from water driven reservoirs is usually good (20-60%
OOIP, Table 1), although the exact figure depends on the strength of
the aquifer and the efficiency with which the water displaces the oil
in the reservoir, which depends on reservoir structure, production
well placing, oil viscosity, and production rate. If the ratio of water to
oil viscosity is large, or the production rate is high then fingering can
occur which leaves oil behind in the reservoir (Figure 6).
Primary Recovery Drive Mechanisms cnt’d
Fig 6: A schematic
example of fingering in a
water drive reservoir
Primary Recovery Drive Mechanisms cnt’d
• Gravity drainage
• 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. Figure 7 shows production
by gravity drainage.
Primary Recovery Drive Mechanisms cnt’d
Fig 7: Gravity drainage
Primary Recovery Drive Mechanisms cnt’d
• The best conditions for gravity drainage are:
· Thick oil zones.
· High vertical permeabilities.
• The rate of production engendered by gravity drainage is very low
compared with the other drive mechanisms examined so far.
However, it is extremely efficient over long periods and can give rise
to extremely high recoveries (50-70% OOIP, Table 1). Consequently, it
is often used in addition to the other drive mechanisms.
Primary Recovery Drive Mechanisms cnt’d
• Combination or mixed drive:
• In practice a reservoir usually incorporates at least two main drive
mechanisms. For example, in the case shown in Figure 8. We have
seen that the management of the reservoir for different drive
mechanisms can be diametrically opposed (e.g. low perforation for
gas cap reservoirs compared with high perforation for water drive
reservoirs). If both occur as in Figure 8, a compromise must be
sought, and this compromise must take into account the strength of
each drive present, the size of the gas cap, and the size/permeability
of the aquifer.
Primary Recovery Drive Mechanisms cnt’d
Fig 8: Mixed drive reservoir
Primary Recovery Drive Mechanisms cnt’d
• It is the job of the reservoir manager to identify the strengths of the
drives as early as possible in the life of the reservoir to optimize the
reservoir performance.
Secondary drive mechanisms
• 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:
(i) Waterflooding
(ii) Gasflooding
Secondary drive mechanisms cnt’d
• Waterflooding
• This method involves the injection of water at the base of a reservoir to;
(i) Maintain the reservoir pressure, and
(ii) Displace oil (usually with gas and water) towards production wells.
The detailed treatment of waterflood recovery estimation, mathematical
modelling, and design are beyond the scope of these notes. However, it
should be noted that the successful outcome of a waterflood process
depends on designs based on accurate relative permeability data in both
horizontal directions, on the choice of a good injector/producer array, and
with full account taken of the local crustal stress directions in the reservoir.
Secondary drive mechanisms cnt’d
• 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.
Again accurate relperms are needed in the design, as well as
injector/producer array geometry and crustal stresses. There is an
additional complication in that re-injected lean gas may strip light
hydrocarbons from the liquid oil phase. At first sight this may not
seem a problem, as recombination in the stock tank or afterwards
may be carried out. However, equity agreements often give different
percentages of gas and oil to different companies. Then the decision
whether to gasflood is not trivial. (e.g. Prudhoe Bay, Alaska).
Tertiary drive mechanisms
• 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; (i) thermal, (ii) chemical, and (iii) miscible gas.
All are extremely expensive, are only used when economical, and are
implemented after extensive SCAL studies have isolated the reservoir
rock characteristics that are causing oil to remain unproduced by
conventional methods.
Tertiary drive mechanisms cnt’d
• Thermal EOR
• These processes use heat to improve oil recovery by reducing the viscosity of
heavy oils and vaporizing lighter oils, and hence improving their mobility. The
techniques include:
(i) Steam injection (Figure 9).
(ii) In situ combustion (injection of a hot gas that combusts with the oil in place,
(Figure 10).
(iii) Microwave heating downhole (Figure 11).
(iv) Hot water injection.
It is worth noting that the generation of large amounts of heat and the treatment
of evolved gas has large environmental implications for these methods. However,
thermal EOR is probably the most efficient EOR approach.
Tertiary drive mechanisms cnt’d
Fig 9: Schematic diagram
of steam flooding EOR
(Heat reduces the
viscosity of oil and
increases its mobility).
Tertiary drive mechanisms cnt’d
Fig 10: Schematic
diagram of in situ
combustion EOR
(Heat and solution
of combustion
gases reduce the
viscosity of oil and
increase it mobility)
Tertiary drive mechanisms cnt’d
Fig 11: Schematic
diagram of
Tertiary drive mechanisms cnt’d
• Chemical EOR
• 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:
(i) Increasing water viscosity (polymer floods).
(ii) Decreasing the relative permeability to water (cross-linked polymer
(iii) Increasing the relative permeability to oil (micellar and alkaline floods).
(iv) Decreasing Sor (micellar and alkaline floods).
(v) Decreasing the interfacial tension between the oil and water phases
(micellar and alkaline floods).
Tertiary drive mechanisms cnt’d
Fig 12: Schematic
diagram of chemical
EOR (Heat and
solution of combustion
gases reduce viscosity
and increase mobility).
Tertiary drive mechanisms cnt’d
Fig 13: The chemical EOR process
Tertiary drive mechanisms cnt’d
• Chemical flood additives, especially surfactants designed to reduce
surface or interfacial tension, are extremely expensive. Thus the
whole chemical EOR flood is designed to minimise the amount of
surfactants needed, and to ensure that the EOR process is
economically successful as well as technically. Chemical flooding is
therefore not a simple single stage process.
Tertiary drive mechanisms cnt’d
• Initially the reservoir is subjected to a preflush of chemicals designed
to improve the stability of the interface between the in-situ fluids and
the chemical flood itself. Then the chemical surfactant EOR flood is
carried out. Commonly polymers are injected into the reservoir after
the chemical flood to ensure that a favourable mobility ratio is
maintained. A buffer to maintain polymer stability follows, then a
driving fluid, which is usually water, is injected. Figure 13 shows a
typical flood sequence. Note that the mobilised oil bank moves ahead
of the surfactant flood, and how the total process has reduced the
amount of the surfactant fluid used.
Tertiary drive mechanisms cnt’d
• Miscible gas flooding
• 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:
(i) CO2
(ii) N2
(iii) Hydrocarbon gases.
Tertiary drive mechanisms cnt’d
Fig 14: Schematic
diagram of a
miscible WAG
flooding EOR
Tertiary drive mechanisms cnt’d
• All of these are relatively cheap to obtain either from the atmosphere or
from evolved reservoir gases. The high mobility of gases can cause a
problem in the reservoir flooding process, since gas breakthrough may be
early due to fingering, leading to low sweep efficiencies. Effort is then
concentrated on trying to improve the sweep efficiency. One such
approach is called a miscible WAG (water alternating gas). In this approach
water slugs and CO2 slugs are alternately injected into the reservoir; the
idea being that the water slugs will lower the mobility of the CO2 and lead
to a more piston-like displacement with higher flood efficiencies. An
additional important advantage of miscible gasflooding is that the gas
dissolves in the oil, and this process reduces the oil viscosity, giving it
higher mobilities and easier recovery.
Infill recovery
• Towards the end of the reservoir life (after primary, secondary and
enhanced oil recovery), the only thing that can be done to improve
the production rate is to carry out infill drilling, directly accessing oil
that may have been left unproduced by all the previous natural and
artificial drive mechanisms. Infill drilling can involve very significant
drilling costs, while the resulting additional production may not be
• Reservoir characterization parameters and drive mechanisms of the
Prudhoe Bay field, Alaska.
• 6pages
• Submission date 03/02/2018.
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