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10/29/2012
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1
RESERVOIR ENGINEERING
Arthur G. Batte
Petroleum Geology
LECTURE 1
2
1.1. How is petroleum formed?

Petroleum is result of the deposition of
plant or animal matter in areas which are
slowly subsiding.
These areas are usually in the sea or
along its margins in coastal lagoons or
marshes, occasionally in lakes or inland
swamps.
3
Sediments are deposited along with that at
least part of the organic matter is preserved by
burial before being destroyed by decay.
As time goes on and the areas continue to sink
slowly, the organic material is buried deeper
and hence is exposed to higher temperatures
and pressures.
Eventually chemical changes result in the
generation of petroleum, a complex, highly
variable mixture of hydrocarbons. 4
1.2. where can we find petroleum ?
Hydrocarbons such as crude oil and
natural gas are found in certain layers of
rock that are usually buried deep beneath
the surface of the earth.
5
Before we proceed to discuss where oil is
found in the subsurface, we must become
familiar with some new terminology; namely,
the four types of rocks; igneous, volcanic
sedimentary and metamorphic.

Igneous rocks are rocks that have solidified
from a molten or liquid state. These rocks can
be formed deep in the earth. Igneous rocks do
not normally contain hydrocarbons.
6
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Molten rock material solidifies at the
surface, it is termed as a volcanic
rock. Similarly, volcanic rocks do not
normally contain hydrocarbons.
7
Sedimentary rocks are formed by the laying
down of sediment in seas, rivers or lakes.

The particles of sediment that accumulate
are eventually cemented together to form
sedimentary rock by the percolation of
mineral rich waters through the spaces
between the particles.

It is these sedimentary rocks in which
hydrocarbons are normally found.
8
Metamorphic rock is formed by the
metamorphosis of existing rock, be it
igneous or sedimentary, by extreme heat
and pressure.

These factors cause recrystallization of the
minerals in the rock. Metamorphic rocks do
not normally contain hydrocarbons.

9
Petroleum is not found in underground
rivers or caverns, but in pore spaces
between the grains of porous sedimentary
rocks.

But what does the word porous mean?
This is most easily explained by
illustration.
10
- 99% of the world petroleum reservoirs are found in

SECONDARY ROCKS

- Less than 1% of the world oil is found in igneous or
metamorphic rocks e.g. Serpentine plugs of South
Central Texas.

- 60% of the world reserves are sandstone rocks.

- 1/3
rd
of world reserves are Carbonates.

- Evaporates (rock salt, anhydrite, gypsum). Few
reservoirs in anhydrites.
11
1.3. what is “trap” ?
The term “trap” was first applied to a
hydrocarbon accumulation by Orton: “…stocks
of oil and gas might be trapped in the summits
of folds or arches.”
“… the place where oil and gas are barred from
further movement …” (Levorsen, 1967) .
“… any geometric arrangement of strata that
permits the accumulation of oil or gas, or both
…” (North, 1985) .

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“… a closed volume of rock within which
hydrocarbons might accumulate …” (Milton &
Bertam, 1992)

A detailed historical account of the subsequent
evolution of the concept and etymology of the
term trap is found in Dott and Reyonlds(1969).

13
Previously, we saw how oil and gas are
found in porous sedimentary rocks within
sedimentary basins.

But does this mean that if you drill a well
anywhere at all in a sedimentary basin
you will strike oil or gas?

The answer to this question is, of course,
no.
14
There are only certain places within
sedimentary basins where hydrocarbons
will tend to accumulate or become
“trapped”.

15
Traps have two essential components
• Reservoir unit(s)‏
– Porous and permeable
rocks into which oil
and gas can migrate
and accumulate.
– The reservoir is
usually a sedimentary
rock, but even granites
can function as a
reservoir in special
circumstances.
• Seal
– A low-permeability
rock which prevents
the hydrocarbons from
migrating out of the
trap.
– The seal can be
sedimentary, igneous
or metamorphic, or a
fault zone.
16
A typical trap
SEAL
RESERVOIR
… in this case a
simple fold.
Hydrocarbons are
trapped in the
highest part of
the structure.
17
The seal
We tend to think of
seals as defining the
top of a reservoir –
hence the term cap
rock – but many
reservoirs are also
dependent upon side
and even bottom
seals. We will see
examples later in the
course.
(Milton and Bertram, 1992)
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Some basic terminology (1)
As the volume of hydrocarbons (oil + gas) in the trap increases, the oil-
water contact will move downwards. The total volume of hydrocarbons
that can be stored in the reservoir is thus defined by the highest point at
which hydrocarbons start to leak from the reservoir – the spill point.
19
Spillage …
That a reservoir reaches the spill point does not mean the oil is lost. In
many oil fields, reservoirs are connected via their spill points.
(Gluyas and Swarbrick, 2004)
20
But loss can occur either because the
reservoir is full or the seal is leaky
Oil seeps – an indication of oil in the
sub-surface. Above: leakage along a
fault zone, Australia. Right: oozing
from an oil-impregnated sand, U.
Jurassic, Dorset, England.
21
Leaky seals – a source of natural oil
pollution
Heavy oil from a natural seep 22
Some basic terminology (2)
A pool is a discrete
accumulation of oil. A
field is made up of one
or more oil pools (the
example on the right
has two, with different
oil-water contacts).
In the upper pool the
net pay is less than the
gross pay because the
volume of permeable
strata is less than the
total volume of the
trap.
23
The oil-water contact is usually horizontal …
… but may be tilted, for a
variety of reasons. In the top
example it is dragged
downwards by flowing water.
The middle example shows the
effect of later tilting of a
cemented layer that formed at
the original OWC. The bottom
figure shows examples of
sedimentological effects (facies
change) which may produce an
apparently tilted OWC.
24
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Trap classification
25
Figure shows some examples of geologic structures
that commonly form hydrocarbon traps.




Hydrocarbon Traps A and B are both examples of
structural traps.

C is an example of a stratigraphic trap formed when a
porous rock layer is encased in nonporous
impermeable rock.

26
Structural traps are caused by the
bending or breaking of the sedimentary
layer.

The most common and simplest type of
structural trap is the anticline which is a
structure formed when the layers of rock
have been buckled upward.
Typical structural and diapiric
traps
27
Structural traps (1)
The simple anticline, a classic hydrocarbon
trap. Western Iran, for example, has many oil
fields in the crests of anticlines that formed
during the development of the Zagros mountain
belt.
28
Fault traps Compressional
anticline
Compactional
anticline
Salt diapir
trap
Mud diapir
trap
Compactional
anticlines
Fault traps
Fault trap
29
Stratigraphic traps are those that are
formed by changes in the characteristics
of the rock formation such as a loss of
permeability or porosity or a break in
continuity of a layer.
Stratigraphic Traps
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Some stratigraphic traps
(a) Reef with lagoonal muds as
lateral seal and basinal shales
as top seal.
(b) pinchout of deepwater
submarine-fan lobe encased in
basinal mudstones.
(c) channel sands of a meandering
river enclosed in floodplain fines.
(d) a coast-parallel sand bar.

(e) dipping sands sealed by an
unconformity.
(f) onlap of sands onto an
unconformity surface.
Unc.
Unc.
onlap
31
…‏and‏even‏more‏complex:
In this example from
Trinidad, overfolding
has produced a
double recumbent
fold, allowing a well
to encounter the
same reservoir
formation (3) three
times.
32
Salt diapirs at the surface
Below, salt dome just breaking
the surface. Note the
extensive, in part radial
fracturing. Right, salt glaciers
flowing from points where salt
has breached anticlines. Iran.
Salt dome
Salt glaciers
33
Salt diapirs
Structures associated with
salt diapirs can be
extremely complex, traps
can be difficult to find,
especially if the diapir has
begun to expand laterally
34
Diapirs in the North Sea
Zechstein (Permian) salt has produced many diapirs in the
southern and central North Sea. These are of great economic
importance because of the central role they have played in
producing the traps which led to the formation of Ekofisk and
related oil fields.
Permian salt diapirs
35
Salt as a seal
While on the subject of salt, we should also remember that salt is a
particularly effective seal. It tends to have little or no porosity and flows
or recrystallises to heal fractures. Salt forms the cap rock to most of the
gas fields in the southern North Sea.
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Mud volcanoes, Columbia
Mud volcano and mudflow, Azerbaijan
Mudflow
Mud diapirs are similar in morphology and behaviour to salt diapirs. The low density of the mud may
be enhanced by high concentrations of biogenic methane. Where mud diapirs breach the surface
they often form mud volcanoes. Mud diapirs are a prominent feature in oil fields around the Caspian
Sea.
Mud diapirs
37
Fault-related traps (1)‏
38
Fault-related traps (2)‏
39
Rotated fault blocks
Fault blocks that have rotated as a result of crustal
extension are a particularly important trap type in the
North Sea. In many cases, sealing is due to an
unconformable cover of low-permeability deposits
overlying the eroded, truncated top of the blocks.
unconformity
40
Stratigraphic traps
41
Unconformity-related traps‏
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Diagenetic traps
Oil migrating to the surface is
biodegraded where it meets
downward-flowing water. The
resulting asphalt eventually
forms a seal
43
Hydrodynamic traps
In almost all cases
hydrodynamic traps are
characterised by a tilted oil-
water contact due to the drag
of the downward-flowing water.
44
The fact that downdip water flow is a requirement for this type
of trap means that the reservoir unit must be in hydrological
contact with the surface.
45
1.3.1. Reservoirs
”A subsurface volume of rock that has
sufficient porosity and permeability to
permit the accumulation of crude oil and
natural gas under adequate trap conditions”
(Bate & Jackson, Glossary of Geology)

If you wanted to find a large supply of water,
where would you look? You would, of course,
go out and look for a lake or a pond.

But, have you ever thought of why ponds and
lakes are located where they are?

To understand why water collects where it
does, we must consider the forces that are
acting upon it.
46
The force of gravity makes water run
downhill.

Therefore, water collects in low bowl-
shaped depressions in the land.

These bowl-shaped depressions provide
traps in which water collects and become
lakes and ponds.

47

In a similar fashion, when we look for oil, we
must look for places that oil is likely to
accumulate in large quantities.

To understand where oil will collect, we must
consider the forces that are acting on droplets
of oil buried deep within the earth.
48
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1.3.2. Oil Floats

Anyone who has ever seen oil spilled in a
water puddle will notice that it creates colorful
patterns in the sunlight.

This is because the oil, which is less dense
than water, forms a separate layer which
actually floats on the surface of the water.

The different light refracting properties of the
two layers create a prism effect, and hence,
the color patterns.


49
Droplets of oil in rocks buried deep
underground will also float above the
water that is also present within these
rocks.

Earlier, we explained how the
sedimentary rocks containing these oil
droplets formed under water.

Hence, these rocks must still contain
some water.
50
So, instead of running downhill as
surface water does under the force of
gravity, oil droplets in the subsurface tend
to move upward, under the force of
buoyancy, so as to float above the water
that shares the same pore spaces.

Driven by buoyancy, these oil droplets
migrate upwards toward the surface
through pores and cracks within the
layers of rock.


51
If these drops of oil encounter an
impermeable surface through which they
cannot flow, they will continue to flow
upward along the underside of this
impermeable sealing rock and collect in
traps as shown.

If no traps are encountered, the oil
droplets will migrate all the way to the
surface creating an oil seep.
52
Reservoirs occur in places where fluids
tend to collect.
53
Oil seeps are quite common in areas of
petroleum potential and were used by
the earliest oil prospectors to identify
drilling locations.

Oil reservoirs in the subsurface in many
ways resemble inverted ponds or lakes.

Unlike ponds and lakes however,
accumulations of hydrocarbons are
contained inside the pore spaces of solid
rock.
54
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1.3.3. Natural Gas Reservoirs

Natural gas, being less dense than either oil
or water, tends to float above water and oil in
the subsurface.

Sometimes, the natural gas is dissolved in the
oil, but it very often forms a separate layer of
its own which floats above the oil layer.

In such a case, we get a layer of natural gas
floating upon a layer of oil which is in turn
underlain by a layer of water.
55
1.3.4. Geologic structures become
hydrocarbon traps

Earlier, we talked about how sedimentary
rocks are formed from sediment settling
on the floors of oceans and lakes.

Common sense suggests that these
sedimentary layers will tend to be laid
down more or less horizontally over large
areas.

56
We also know, however, that we need
traps to provide areas in which oil and
gas can collect.

This means that the layers of rock must
somehow become buckled and bend to
provide the geologic structures that may
become traps.

Fortunately for oil prospectors, forces
within the earth itself create these
geologic structures.
57
These powerful forces that tend to
stretch, squeeze, bend and break the
rock layers are the same forces that
cause earthquakes.

The geologic structures that are created
(ie., bends and breaks or faults in the
rock layers) can become hydrocarbon
traps where certain conditions are
present:

58
There must be hydrocarbon source rock in the
area. Source rock is the fine grained rock in
which the organic material originally present
has been converted into hydrocarbons.

There must be a porous and permeable rock
layer to provide a reservoir in which the
hydrocarbons can accumulate.

There must be an impermeable sealing rock
overlying the reservoir rock to trap the
hydrocarbons.
59
In oil exploration, it is the job of the
geologist and geophysicist to find these
geologic structures which are potential
hydrocarbon traps and thereby
recommend drilling locations.


60
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11
We speak of "potential" hydrocarbon traps
because not all structures contain
hydrocarbons.

Many structures contain no reservoir rock,
and so no oil or gas can accumulate
61
Many contain excellent reservoir rocks, but are
full of water.

In other structures, the lack of a good sealing
layer prevents oil and gas from accumulating.

In other areas, the lack of a good source rock
could be the problem.

The only way to know for sure if oil or gas is
present in a structure is to drill a well.
62
Absolute and Effective Porosity
LECTURE 2
63
For rock to contain petroleum and later
allow petroleum to flow, it must have
certain physical characteristics.

Obviously, there must be some spaces in
the rock in which the petroleum can be
stored.

64
If rock has openings, voids, and spaces in
which liquid and gas may be stored, it is
said to be porous.

For a given volume of rock, the ratio of
the open space to the total volume of the
rock is called porosity, the porosity may be
expressed a decimal fraction but is most
often expressed as a percentage.

65
For example, if 100ft
3
of rock contains
many tiny pores and spaces which
together have a volume of 10ft
3
, the
porosity of the rock is 10%.
66
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POROSITY
The porosity of a rock is a measure of the storage
capacity (pore volume) that is capable of holding
fluids. Quantitatively, the porosity is the ratio of the
pore volume to the total volume (bulk volume). This
important rock property is determined mathematically
by the following generalized
relationship:




where | = porosity
67 68
Catenary
(= connected)
Cul-de-sac
Closed
Effective porosity
Ineffective
porosity
There are 3 basic pore types:
69 70
Selley page 240
71
S
e
l
l
e
y

p
a
g
e

2
4
1

72
S
e
l
l
e
y

p
a
g
e

2
4
2

A
10/29/2012
13
73 74
Bulk Volume: Total volume of rock body (pore + rock).

Pore Volume: Volume of all pores contained in rock
body.

Grain / Solid Volume: The volume of solids or sand
grains in rock body.
75
Connected Pores: Pores
that are in communication
with each other.

Isolated (Dead) Pores:
Pores isolated from the
body of connected pores.
In other words, porosity is an ability of the porous
medium to store fluids (Container).
76
As the sediments were deposited and the
rocks were being formed during past
geological times, some void spaces that
developed became isolated from the other
void spaces by excessive cementation.
How are porous sedimentary rocks formed??
77
Porosity Estimation
1. Draw from the rock by creating a vacuum.
2. Imbibe fluid into the rock.
3. Volume of the fluid imbibed in the porosity.
(It may not access all pores but it is good enough for
you, the Reservoir engineers!)
78
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Thus, many of the void spaces are
interconnected while some of the pore
spaces are completely isolated.

This leads to two distinct types of porosity,
namely:

• Absolute porosity
• Effective porosity
79
Absolute porosity

The absolute porosity is defined as the ratio of
the total pore space in the rock to that of the
bulk volume.

A rock may have considerable absolute
porosity and yet have no conductivity to fluid
for lack of pore interconnection.







80
The absolute porosity is generally expressed
mathematically by the following relationships:
or
where |
a
= absolute porosity.
81
Effective porosity

The effective porosity is the percentage of
interconnected pore space with respect to the
bulk volume, or





where | = effective porosity.

82
One important application of the
effective porosity is its use in
determining the original hydrocarbon
volume in place.
83
Porosity Classification
1. Primary (or intergranular) porosity: Porosity
formed at the time of rock/sediments
deposition.

 Pore spaces are between the individual
grains of the sediment.

 Sandstone porosity is generally referred
as the primary porosity.
84
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15
Note:

Both the primary and secondary porosities
can exist in the formation, so are termed
as “dual porosity”

Secondary is difficult to estimate, thus
adds further to uncertainties in the
reservoir engineering calculations
85
2. Secondary porosity: Rock porosity
created after rock formation and
exposure to various diagenetic
processes such as compaction,
cementation, solution, dolomitization,
fissures, fractures, hydration etc.

86
I. Fissures, fractures/joints porosity
(carbonate rocks): formed due to
tectonic movement, compaction or
hydration.
87
Examples of secondary porosity
II. Matrix or total porosity: Matrix porosity
is that of rock matrix, whereas total
porosity includes matrix porosity and
porosity due to fractures, joints, and
fissures
88
III. Solution porosity: The porosity
portion due to the presence of vugs
and cavities created by dissolution of
minerals in a carbonate rock.
89
IV. Dolomitization: A chemical process in
which, a magnesium cation replaces a
calcium cation in each carbonate
molecule of the rock, that results in the
formation of dolomite rock.
90
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Porosity (P): Estimation
100
P
T
V
P
V
= ×
Where V
P
is the total volume of pore space
and V
T
is the total volume of rock or
sediment.
The proportion of any material that is void space, expressed as a
percentage of the total volume of material.
In practice, porosity is commonly based on measurement of the total
grain volume of a granular material:
100
T G
T
V V
P
V
÷
= ×
Where V
G
is the total volume of grains
within the total volume of rock or
sediment.
P T G
V V V = ÷
91
Porosity varies from 0% to 70% in natural sediments but
exceeds 70% for freshly deposited mud. Several factors
control porosity.
a) Packing Density
Packing density: the arrangement of the particles in the
deposit. The more densely packed the particles the lower
the porosity. e.g., perfect spheres of uniform size.


Porosity can vary
from 48% to 26%.
92
Shape has an important effect on packing.
Tabular rectangular particles can vary from 0% to just under 50%:
Natural particles such as shells can have very high porosity:
93
In general, the greater the angularity of the particles the more open the
framework (more open fabric) and the greater the possible porosity.
b) Grain Size
On its own, grain size has no influence on porosity!
Consider a cube of sediment of perfect
spheres with cubic packing.
100
T G
T
V V
P
V
÷
= ×
d = sphere diameter; n = number of
grains along a side (5 in this example).
94
100
T G
T
V V
P
V
÷
= ×
Total number of grains: n x n x n = n
3
Volume of a single grain:
3
6
V d
t
=
Total volume of grains (V
G
):
3 3 3 3
6 6
G
V n d n d
t t
= × =
Length of a side of the cube = d x n = dn

Volume of the cube (V
T
):

3 3
T
V dn dn dn d n = × × =
95
100
T G
T
V V
P
V
÷
= ×
3 3
6
G
V n d
t
=
3 3
T
V d n = Where: and
3 3 3 3
3 3
6
100
d n n d
P
d n
t
÷
= × Therefore:
3 3
3 3
1
6
100
d n
P
d n
t | |
÷
|
\ .
= × Rearranging:
Therefore: 1 100 48%
6
P
t | |
= ÷ × =
|
\ .
d (grain size) does not affect the porosity so that porosity is
independent of grains size. No matter how large or small the spherical
grains in cubic packing have a porosity is 48%.

96
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There are some indirect relationships between grain size and
porosity.

i) Large grains have higher settling velocities than small grains.

When grains settle through a fluid the large grains will impact the
substrate with larger momentum, possibly jostling the grains into
tighter packing (therefore with lower porosity).

ii) A shape effect.



Unconsolidated sands tend to
decrease in porosity with
increasing grain size.

Consolidated sands tend to
increase in porosity with
increasing grain size.

97
Generally, unconsolidated sands undergo
little burial and less compaction than
consolidated sands. Fine sand has slightly
higher porosity. The fine sand tends to be
more angular than coarse sand.

Therefore fine sand will support a more open
framework (higher porosity) than better
rounded, more spherical, coarse sand.


.
98
Consolidated sand (deep burial, well compacted)
has undergone exposure to the pressure of burial
(experiences the weight of overlying sediment).

Fine sand is angular, with sharp edges, and the
edges will break under the load pressure and
become more compacted (more tightly packed with
lower porosity).

Coarse sand is better rounded and less prone to
breakage under load; therefore the porosity is
higher than that of fine sand.


99
c) Sorting
In general, the better sorted the sediment the greater the
porosity.

In well sorted sands, fine grains are not available to fill the
pore spaces.

This figure shows the relationship between sorting and
porosity for clay-free sands.

100
Overall porosity decreases with increasing sorting
coefficient (poorer sorting).

For clay-free sands the reduction in porosity with
increasing sorting coefficient is greater for coarse
sand than for fine sand.

The difference is unlikely if clay was also available
to fill the pores.

101
For clay-free sands, the silt and fine sand
particles are available to fill the pore space
between large grains and reduce porosity.
102
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Because clay is absent, less relatively fine material
is not available to fill the pores of fine sand.

Therefore the pores of fine sand will be less well-
filled (and have porosity higher).
103
d) Post burial changes in porosity.

This includes processes that reduce and increase porosity.

Porosity that develops at the time of deposition is termed
primary porosity. Porosity that develops after deposition is
termed secondary porosity.

Overall, with increasing burial
depth, the porosity of sediment
decreases.

50% reduction in porosity with
burial to 6 km depth due to a
variety of processes.

104
i) Compaction
Particles are forced into closer packing by the weight of
overlying deposits, reducing porosity. May include
breakage of grains. Most effective if clay minerals are
present (e.g., shale).

Freshly deposited mud may have 70% porosity but burial
under a kilometer of sediment reduces porosity to 5 or
10%.

105
ii) Cementation
Precipitation of new minerals from pore waters causes
cementation of the grains and acts to fill the pore spaces,
reducing porosity.

Most common cements are calcite and quartz.

106
iii) Clay formation
Clays may form by the chemical alteration of pre-
existing minerals after burial.

Feldspars are particularly common clay-forming
minerals. Clay minerals are very fine-grained and
may accumulate in the pore spaces, reducing
porosity.

107
iv) Solution
If pore waters are under-saturated with respect
to the minerals making up a sediment, then
some volume of mineral material is lost to
solution.

Calcite, that makes up limestone, is relatively
soluble and void spaces that are produced by
solution range from the size of individual grains
to caverns.

108
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Quartz is relatively soluble when pore waters
have a low Ph.

Solution of grains reduces the total volume of
grains, hence increasing porosity. Solution is
the most effective means of creating
secondary porosity.
109
v) Pressure solution
The solubility of mineral grains increases under
an applied stress (such as burial load) and the
process of solution under stress is termed
Pressure Solution.

The solution takes place at the grain contacts
where the applied stress is greatest.

110
Pressure solution results in a reduction in porosity in two
different ways:

1. It shortens the pore spaces as the grains are dissolved.

2. Insoluble material within the grains accumulates in the
pore spaces as the grains are dissolve.

111
vi) Fracturing
Fracturing of existing rocks creates a small
increase in porosity.

Fracturing is particularly important in producing
porosity in rocks with low primary porosity.

112
113
Porosity Maps

Isoporosity map:

A map showing lines (contours) of
constant porosity. The increment between
any two neighboring lines is constant and
is called contour interval. The contour
lines do not intersect. They are continuous
and terminate at the edge of map or
reservoir.
114
Porosity Measurements: Maps
10/29/2012
20
115 116
Why is porosity important?
Especially because it allows us to make
estimations of the amount of fluid that can be
contained in a rock (water, oil, spilled
contaminants, etc.).

Example from oil and gas exploration:

117
Why is porosity important?
How much oil is contained in the discovered unit?

In this case, assume that the pore spaces of the sediment in
the oil-bearing unit are full of oil.

Therefore, the total volume of oil is the total volume of
pore space (V
P
) in the oil-bearing unit



.
118
100
P
T
V
P
V
= × Total volume of oil = V
P
, therefore solve for V
P
.
100
T
P
P V
V
×
=
3
800 200 1 160, 000
T
V m m m m = × × =
10% P =
Therefore:
10 160, 000
100
P
V
×
=
3
16, 000m = of oil
119
Permeability and Darcy’s Law
LECTURE 3
120
10/29/2012
21
Permeability is a property of the porous
medium that measures the capacity and ability
of the formation to transmit fluids.

The rock permeability, k, is a very important
rock property because it controls the directional
movement and the flow rate of the reservoir
fluids in the formation.
121
Effective, Absolute and Relative permeability
Absolute Permeability (k or k
abs
)

Permeability of a porous media (rock) is when
its pore are saturated with single fluid.

– In practice, the reservoir is filled with more
than one fluid (oil, water and gas).

122
– Therefore, you can no longer
obtain absolute permeability.
Effective permeability (k
eff
)

Permeability of rock to a fluid in a system
when that fluid occupies a fraction of total pore
space.

When more than one phase is present in the
reservoir rock, the resulting permeability to
each phase is called effective permeability (k
w
,
k
o
, k
g
)
123
Effective permeability (k
eff
) Cont…..

• It represents the conductivity of each phase at
a specific saturation.
• It provides an extension of Darcy’s law in the
presence and movement of more than a single
fluid phase within the pore space.
• The fluids interfere with each other, and the
individual effective.
• Permeabilities to each phase as well as their
sum is lower than the absolute permeability.
124
• Multiphase flow in porous media- Darcy’s
law still applicable.
• “ Effective permeability” : permeability of one
fluid in the presence of other fluids in porous
media.
125
Darcy’s Law

This rock characterization was first
defined mathematically by Henry Darcy in
1856.

In fact, the equation that defines
permeability in terms of measurable
quantities is called Darcy’s Law.

126
10/29/2012
22
Darcy developed a fluid flow equation that has
since become one of the standard
mathematical tools of the petroleum engineer.

If a horizontal linear flow of an incompressible
fluid is established through a core sample of
length L and of a cross-section of area A, then
the governing fluid flow equation is defined as
127
where v = apparent fluid flowing velocity, cm/sec
k = proportionality constant, or permeability, Darcys
µ = viscosity of the flowing fluid,
dp/dL = pressure drop per unit length, atm/cm
Linear flow model
128
The apparent velocity is determined by dividing
the flow rate by the cross-sectional area across
which fluid is flowing.

Substituting the relationship, q/A, in place of v
in the Equation above and solving for q results
in



where q = flow rate through the porous medium,
cm
3
/sec.
A = cross-sectional area across which flow occurs,
cm
2
129
One Darcy is a relatively high
permeability as the permeabilities of most
reservoir rocks are less than one Darcy.
In order to avoid the use of fractions in
describing permeabilities, the term
millidarcy is used.

As the term indicates, one millidarcy, i.e.,
1 md, is equal to one-thousandth of one
Darcy or,
1 Darcy = 1000 md


130
The negative sign in Equation is necessary as
the pressure increases in one direction while
the length increases in the opposite direction.




Integrate the above equation



131



where L = length of core, cm
A = cross-sectional area, cm
2

The following conditions must exist during the measurement
of permeability:
• Laminar (viscous) flow
• No reaction between fluid and rock
• Only single phase present at 100% pore space saturation

This measured permeability at 100% saturation of a single
phase is called the absolute permeability of the rock.

132
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23
For a radial flow, Darcy’s equation in a
differential form can be written as:












133
Integrating Darcy’s equation gives:






The term dL has been replaced by dr as
the length term has now become a radius
term.
134
Saturation
LECTURE 4
135
SATURATION
Saturation is defined as that fraction, or percent, of
the pore volume occupied by a particular fluid (oil, gas,
or water). This property is expressed mathematically
by the following relationship:



Applying the above mathematical concept of
saturation to each reservoir fluid gives








136

where

S
o
= oil saturation
S
g
= gas saturation
S
w
= water saturation

S
g
+ S
o
+ S
w
= 1

137 138
Critical oil saturation, S
oc

For the oil phase to flow, the saturation of
the oil must exceed a certain value,
which is termed critical oil saturation.

At this particular saturation, the oil
remains in the pores and, for all practical
purposes, will not flow.
10/29/2012
24
Residual oil saturation, S
or

During the displacing process of the crude
oil system from the porous media by
water or gas injection (or encroachment),
there will be some remaining oil left that
is quantitatively characterized by a
saturation value that is larger than the
critical oil saturation.
139 140
This saturation value is called the
residual oil saturation, S
or
.

The term residual saturation is usually
associated with the non wetting phase
when it is being displaced by a
wetting phase.
Movable oil saturation, S
om

Movable oil saturation S
om
is another
saturation of interest and is defined as the
fraction of pore volume occupied by movable
oil as expressed by the following equation:
S
om
= 1 ÷ S
wc
÷ S
oc
where
S
wc
= connate water saturation
S
oc
= critical oil saturation
141
Critical gas saturation, S
gc

As the reservoir pressure declines below the
bubble-point pressure, gas evolves from the oil
phase and consequently the saturation of the
gas increases as the reservoir pressure
declines.
The gas phase remains immobile until its
saturation exceeds a certain saturation, called
critical gas saturation above which, the gas
begins to move.


142
143
Critical water saturation, S
wc
The critical water saturation,
connate water saturation, and
irreducible water saturation are
extensively used interchangeably
to define the maximum water
saturation at which the water
phase will remain immobile.
Capillary Pressure and Its Curve
LECTURE 5
144
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25
Capillary pressure
If a glass capillary tube is placed
in a large open vessel containing
water, the combination of surface
tension and wettability of tube to
water will cause water to rise in
the tube above the water level in
the container outside the tube.
145 146
The water will rise in the tube until the
total force acting to pull the liquid
upward is balanced by the weight of
the column of liquid being supported
in the tube.
CAPILLARY PRESSURE

The capillary forces in a petroleum reservoir
are the result of the combined effect of the
surface and interfacial tensions of the rock
and fluids, the pore size and geometry, and
the wetting characteristics of the system.

Any curved surface between two immiscible
fluids has the tendency to contract into the
smallest possible area per unit volume.
147 148
This is true whether the fluids are oil and
water, water and gas (even air), or oil and
gas. When two immiscible fluids are in
contact, a discontinuity in pressure exists
between the two fluids, which depends
upon the curvature of the interface
separating the fluids.

We call this pressure difference, the
capillary pressure and it is referred to by
p
c
.

149
p
c
= p
nw
÷ p
w

P
nw
= pressure of the non wetting
phase.

P
w
= pressure of the wetting phase.

Transition Zone
The saturations gradually change from 100%
water in the water zone to the critical water
saturation, some vertical distance above the
water zone.

This vertical area is referred to as the transition
zone, which must exist in any reservoir where
there is a bottom water table.

150
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26
151
Rise of Wetting Phase (height, h) Varies with
Capillary Radius
152
The transition zone is then defined
as the vertical thickness over which,
the water saturation ranges from
100% saturation to critical water
saturation S
wc
.
Water - Oil Contact
The WOC is defined as the “uppermost
depth in the reservoir where a 100%
water saturation exists.”

Gas - Oil Contact
The GOC is defined as the “minimum
depth at which a 100% liquid, i.e., oil +
water, saturation exists in the reservoir.”

153 154
It should be noted that there is a
difference between the free water level
(FWL) and the depth at which 100%
water saturation exists.

From a reservoir engineering standpoint,
the free water level is defined by zero
capillary pressure.
155 156
Obviously, if the largest pore is so
large that there is no capillary rise in
this size pore, then the free water
level and 100% water saturation level,
i.e., WOC, will be the same.
10/29/2012
27
Wettability and Distribution of
Reservoir Fluids
LECTURE 6
157
WETTABILITY
Wettability is defined as the tendency of
one fluid to spread on or adhere to a solid
surface in the presence of other
immiscible fluids.
The concept of wettability is illustrated in
the figure below. Small drops of three
liquids, mercury, oil, and water are placed
on a clean glass plate.
158
The three droplets are then observed
from one side as illustrated in the figure
below. It is noted that the mercury retains
a spherical shape, the oil droplet
develops an approximately hemispherical
shape, but the water tends to spread over
the glass surface.

159
The tendency of a liquid to spread over
the surface of a solid is an indication of
the wetting characteristics of the liquid for
the solid.

This spreading tendency can be
expressed more conveniently by
measuring the angle of contact at the
liquid-solid surface.
160
161
This angle, which is always
measured through the liquid to the
solid, is called the contact angle u.

The contact angle u has achieved
significance as a measure of
wettability.
162
If θ < 90° the fluid is said to wet the
surface. If θ > 90°the fluid is said to be
“non-wetting”.

adhesion > cohesion “wetting”
cohesion > adhesion “non-wetting”

• Water “wets” glass, mercury is “non-
wetting” on a glass surface.
• Interfacial tension creates a curved
interface between two immiscible fluids.
10/29/2012
28
As shown in figure, as the contact
angle decreases, the wetting
characteristics of the liquid increase.
Complete wettability would be
evidenced by a zero contact angle,
and complete non wetting would be
evidenced by a contact angle of
180°.
163 164
There have been various definitions
of intermediate wettability but, in
much of the published literature,
contact angles of 60°to 90°will
tend to repel the liquid.
165
The wettability of reservoir rocks to the
fluids is important in that the distribution of
the fluids in the porous media is a function
of wettability.

Because of the attractive forces, the
wetting phase tends to occupy the smaller
pores of the rock and the non wetting
phase occupies the more open channels.
Classification of Hydrocarbon
Reservoir

LECTURE 7
166
CLASSIFICATION OF RESERVOIRS
AND RESERVOIR FLUIDS
Petroleum reservoirs are broadly
classified as oil or gas reservoirs.
This will depend largely depend on:
• The composition of the reservoir
hydrocarbon mixture.
• Initial reservoir pressure and
temperature.

pressure-temperature diagram
167 168
10/29/2012
29
P-T Diagram
Figure above shows a typical
pressure-temperature diagram of a
multicomponent system with a
specific overall composition.

Although a different hydrocarbon
system would have a different phase
diagram, the general configuration is
similar.

169 170
These multicomponent pressure-
temperature diagrams are essentially
used to:

• Classify reservoirs
• Classify the naturally occurring
hydrocarbon systems.
• Describe the phase behavior of the
reservoir fluid.
• Critical point—The critical point
for a multicomponent mixture is
referred to as the state of
pressure and temperature at
which all intensive properties of
the gas and liquid phases are
equal (point C).
P-T Diagram
171 172
At the critical point, the
corresponding pressure and
temperature are called the
critical pressure (P
c
) and
critical temperature (T
c
) of the
mixture.
• Bubble-point curve - The bubble-point
curve (line AC) is defined as the line
separating the liquid-phase region from
the two-phase region.

• Dew-point curve - The dew-point curve
(line BC) is defined as the line
separating the vapor-phase region from
the two-phase region.
P-T Diagram
173
• Oil reservoirs - If the reservoir
temperature T is less than the critical
temperature T
c
of the reservoir fluid, the
reservoir is classified as an oil reservoir.

• Gas reservoirs - If the reservoir
temperature is greater than the critical
temperature of the hydrocarbon fluid, the
reservoir is considered a gas reservoir.
P-T Diagram
174
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30
Gas Reservoirs
In general, if the reservoir temperature is
above the critical temperature of the
hydrocarbon system, the reservoir is classified
as a natural gas reservoir. On the basis of their
phase diagrams and the prevailing reservoir
conditions, natural gases can be classified into
3 categories:
• Retrograde gas-condensate
• Wet gas
• Dry gas
175
If the reservoir temperature T lies
between the critical temperature T
c

and cricondentherm T
ct
of the
reservoir fluid, the reservoir is
classified as a retrograde gas-
condensate reservoir.
• the gas-oil ratio for a condensate
system increases with time due to
the liquid dropout and the loss of
heavy components in the liquid.
• Condensate gravity above 50°
API
• Stock-tank liquid is usually water-
white or slightly colored.
Retrograde gas-condensate reservoir
176
Temperature of wet-gas reservoir is
above the cricondentherm of the
hydrocarbon mixture.

Because the reservoir temperature
exceeds the cricondentherm of the
hydrocarbon system, the reservoir fluid
will always remain in the vapor phase
region as the reservoir is depleted
isothermally, along the vertical line A-B.
Wet-gas reservoir
177
Wet-gas reservoirs are characterized by the
following properties:
• Gas oil ratios between 60,000 to 100,000
scf/stb
• Stock-tank oil gravity above 60° API
• Liquid is water-white in color
• Separator conditions, i.e., separator pressure
and temperature, lie within the two-phase
region
Wet-gas reservoir
178
The hydrocarbon mixture exists
as a gas both in the reservoir
and in the surface facilities.

Usually a system having a gas-
oil ratio greater than 100,000
scf/stb is considered to be a dry
gas.
Dry-gas reservoir
179
Drives in the Reservoir
LECTURE 8
180
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31
The Water Drive Mechanism
Many reservoirs are bounded on a
portion or all of their peripheries by
water bearing rocks.

181 182
The aquifers may be so large
compared to the reservoir they
adjoin.

They may range down to those so
small as to be negligible in their
effects on the reservoir performance.

These reservoirs have a water drive

Rock and Liquid Expansion
When an oil reservoir initially
exists at a pressure higher than
its bubble-point pressure, the
reservoir is called an under
saturated oil reservoir.
183 184
• Bubble point pressure
determines the point at
which a gas bubble forms.

• The pressure above which
the fluid essentially remains
in the liquid phase and all
volatile components are
dissolved in the liquid.


185
At pressures above the bubble-
point pressure, crude oil, connate
water and rock are the only
materials present.

As the reservoir pressure declines,
the rock and fluids begin to
expand due to their individual
compressibilities.
186
The reservoir rock compressibility
results from two factors:

• Expansion of the individual
rock grains that make up the
reservoir.
• Formation compaction.
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Rock and Liquid Expansion
The above two factors are a result
of the decrease of fluid pressure
within the pore spaces, and both
tend to reduce the pore volume
through the reduction of the
porosity.

187 188
This driving mechanism is
considered the least efficient
driving force and usually results in
the recovery of only a small
percentage of the total oil in place.
Solution-gas drive, Gas-cap
drive and Gravity drive
LECTURE 9
189
The Depletion Drive Mechanism
This driving mechanism may also be
referred to by the following various
terms:
• Solution-gas drive
• Dissolved-gas drive
• Internal-gas drive

190
191
In this type of reservoir, the principal source of
energy is a result of gas liberation from the
crude oil and the subsequent expansion of the
solution gas as the reservoir pressure is
reduced.

As pressure falls below the bubble-point
pressure, gas bubbles are liberated within the
microscopic pore spaces. These bubbles
expand and force the crude oil out of the pore
space as shown conceptually in Figure 1 below.
Figure 1 Solution gas drive reservoir


192
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33
Gas-Cap Drive
Gas-cap drive reservoirs can be
identified by the presence of a gas
cap with little or no water drive as
shown in Figure 2.
Due to the ability of the gas cap to
expand, these reservoirs are
characterized by a slow decline in the
reservoir pressure.
193 194
The natural energy available to
produce the crude oil comes from
the following two sources:

• Expansion of the gas-cap gas.
• Expansion of the solution gas as it is
liberated.
Figure 2 Gas-cap drive reservoir
195
The Gravity-Drainage Drive Mechanism

The mechanism of gravity drainage
occurs in petroleum reservoirs as a result
of differences in densities of the reservoir
fluids.

The effects of gravitational forces can be
simply illustrated by placing a quantity of
crude oil and a quantity of water in a jar
and agitating the contents.
196
197
After agitation, the jar is placed at rest,
and the more denser fluid (normally
water) will settle to the bottom of the
jar, while the less dense fluid
(normally oil) will rest on top of the
denser fluid.

The fluids have separated as a result
of the gravitational forces acting on
them.
The Combination Drive Mechanism

The driving mechanism most commonly
encountered is one in which both water and
free gas are available in some degree to
displace the oil toward the producing wells.

The most common type of drive encountered,
therefore, is a combination-drive mechanism
as illustrated in Figure 4.

198
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34
Figure 4 Combination drive reservoir
199 200
Two combinations of driving forces can be
present in combination drive reservoirs.

These are (1) depletion drive and a weak
water drive and; (2) depletion drive with a
small gas cap and a weak water drive.

Then, of course, gravity segregation can
play an important role in any of the
aforementioned drives.
Derivation of Material Balance
Equation
LECTURE 10
201
When an oil and gas reservoir is
trapped with wells, oil and gas,
and frequently some water, are
produced, thereby reducing the
reservoir pressure and causing
the remaining oil and gas to
expand to fill-up the space left by
the removed fluids.

202
203
When the oil-and gas-bearing strata are
hydraulically connected with water-
bearing strata, water encroaches into the
reservoir as the pressure drops owing to
production.

This water encroachment decreases the
extent to which the remaining oil and gas
expand and accordingly, retards the
decline in reservoir pressure.
As much as the temperature in oil and gas
reservoir remains substantially constant during
the course of production, the degree to which
the remaining oil and gas expand depends
only on the pressure.

By taking bottom-hole samples of the reservoir
fluids under pressure and measuring their
relative volumes in the laboratory at reservoir
temperature and under various pressures ,it is
possible to predict how these fluids behave in
the reservoir as reservoir pressure declines.

204
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35
The general material balance equation is
simply a volumetric balance, which states
that; since the volume of a reservoir is
constant, the algebraic sum of the
volume changes of the oil, free gas,
water and rock volumes in the reservoir
volumes decreases, the sum of these
decreases must be balanced by changes
of equal magnitude in the water and
rock volumes.
205
If the assumption is made that complete
equilibrium is attained at all times in the
reservoir between the oil and its solution
gas, it is possible to write a generalized
material balance expression relating the
quantities of oil, gas and water
produced, the average reservoir
pressure, the quantity of water that
may have encroached from the aquifer,
and finally the initial oil and gas
content of the reservoir.

206
Steady-state and Pseudo
Steady-state Flow
LECTURE 11
207
The area of concern here includes:

• Types of fluids in the reservoir
• Flow regimes
• Reservoir geometry
208
Types of Fluids

In general, reservoir fluids are
classified into three groups:
• Incompressible fluids
• Slightly compressible fluids
• Compressible fluids
209 210
Incompressible fluids

An incompressible fluid is defined as one
whose volume (or density) does not
change with pressure.

Incompressible fluids do not exist; this
behavior, however, may be assumed in
some cases to simplify the derivation and
the final form of many flow equations.
10/29/2012
36
Slightly compressible fluids

These “slightly” compressible fluids
exhibit small changes in volume or
density, with changes in pressure.

It should be pointed out that crude oil
and water systems fit into this
category.



211 212
Compressible Fluids

These are fluids that experience large
changes in volume as a function of
pressure.

All gases are considered compressible
fluids.
Flow Regimes

There are three flow regimes:
• Steady-state flow
• Unsteady-state flow
• Pseudosteady-state flow


213 214
Steady-State Flow

The flow regime is identified as a steady-
state flow, if the pressure at every location
in the reservoir remains constant, i.e.,
does not change with time.

Mathematically, this condition is
expressed as:
(4-1)
The above equation states that the rate of
change of pressure p with respect to time
t at any location i is zero.

In reservoirs, the steady-state flow
condition can only occur when the
reservoir is completely recharged and
supported by strong aquifer or pressure
maintenance operations.


215 216
Unsteady-State Flow

The unsteady-state flow (frequently called
transient flow) is defined as the fluid flowing
condition at which the rate of change of
pressure with respect to time at any position in
the reservoir is not zero or constant.

This definition suggests that the pressure
derivative with respect to time is essentially a
function of both position i and time t, thus

(4-2)
10/29/2012
37
Pseudosteady-State Flow

When the pressure at different locations in the
reservoir is declining linearly as a function of
time, i.e., at a constant declining rate, the
flowing condition is characterized as the
pseudosteady-state flow.

Mathematically, this definition states that the
rate of change of pressure with respect to time
at every position is constant, or


217
(4-3)
218
It should be pointed out that the
pseudosteady-state flow is commonly
referred to as semisteady-state flow and
quasisteady-state flow.

Figure shows a schematic comparison of
the pressure declines as a function of
time of the three flow regimes.
219
Reservoir Geometry

For many engineering purposes however,
the actual flow geometry may be
represented by one of the following flow
geometries:
• Radial flow
• Linear flow
• Spherical and hemispherical flow
220
221
Because fluids move toward the well from
all directions and coverage at the
wellbore, the term radial flow is given to
characterize the flow of fluid into the
wellbore.

Figure 4-1 shows idealized flow lines and
iso-potential lines for a radial flow
system.
Figure 4-1 Ideal radial
flow into a
wellbore






222
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38
Linear Flow
Linear flow occurs when flow paths
are parallel and the fluid flows in a
single direction.

In addition, the cross sectional area to
flow must be constant. Figure 4-2
shows an idealized linear flow system.



223 224
Figure 4-2 Ideal linear flow into vertical fracture
Spherical and Hemispherical Flow
Depending upon the type of wellbore
completion configuration, it is possible to
have a spherical or hemispherical flow
near the wellbore.

A well with a limited perforated interval
could result in spherical flow in the vicinity
of the perforations as illustrated in Figure
4-3.

225 226
Figure 4-3 Spherical flow due to limited entry
227
A well that only partially penetrates the
pay zone, as shown in Figure 4-4, could
result in hemispherical flow. The condition
could arise where coning of bottom water
is important.

Figure 4-4 Hemispherical flow in a partially penetrating well
Horizontal Wells
LECTURE 12
228
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39
Since 1980, horizontal wells began
capturing an ever-increasing share of
hydrocarbon production. Horizontal wells
offer the following advantages over those
of vertical wells:
• Large volume of the reservoir can be
drained by each horizontal well.
• Higher productions from thin pay zones.
• Horizontal wells minimize water and gas
zoning problems.
229 230
• In high permeability reservoirs, where near-
wellbore gas velocities are high in vertical
wells, horizontal wells can be used to reduce
near-wellbore velocities and turbulence.

• In secondary and enhanced oil recovery
applications, long horizontal injection wells
provide higher injectivity rates.

• The length of the horizontal well can provide
contact with multiple fractures and greatly
improve productivity.
The actual production mechanism and
reservoir flow regimes around the
horizontal well are considered more
complicated than those for the vertical
well, especially if the horizontal section of
the well is of a considerable length.

Some combination of both linear and
radial flow actually exists, and the well
may behave in a manner similar to that of
a well that has been extensively fractured.
231
Method I
Joshi proposed that the drainage area is represented by two
half circles of radius b (equivalent to a radius of a vertical well
r
ev
) at each end and a rectangle, of dimensions L(2b), in the
center. The drainage area of the horizontal well is given then by:




232
Figure 5-1


(5-1)

where
A = drainage area, acres
L = length of the horizontal well, ft
b = half minor axis of an ellipse, ft
233
Method II
Joshi assumed that the horizontal well drainage area
is an ellipse and given by:

(5-2)

with

(5-3)

where a is the half major axis of an ellipse.
234
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40
235
Joshi noted that the two methods give
different values for the drainage area A
and suggested assigning the average
value for the drainage of the horizontal
well.

Most of the production rate equations
require the value of the drainage radius
of the horizontal well, which is given by:


(5-4)


Where
r
eh
= drainage radius of the horizontal well, ft
A = drainage area of the horizontal well,
acres




236
Natural Flow Recovery
LECTURE 13
237
A thorough understanding of the
flowing well is necessary prior to
placing it on artificial lift.

There are two surface conditions
under which a flowing well is
produced i.e., it may be produced
with a choke at the surface or it may
be produced with no choke at the
surface.

238
239
The majority of all flowing wells utilize
surface chokes.

Some of the reasons for this are safety;
to maintain production allowable; to
maintain an upper flow rate limit to
prevent sand entry; to produce the
reservoir at the most efficient rate; to
prevent water or gas coning; and others.
In particular, flowing wells utilize a
choke in their early stages of
production.

As time progresses, the choke size
may have to be increased and
eventually removed completely in
order to try to optimize production.


240
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41
241
The second condition that we are
concerned with is producing the flowing
well with no restrictions at the surface
except normal Christmas tree turn, bends,
etc.

Even these may be streamlined in order
to obtain the maximum flowing rate
possible.
In order to analyze the performance of a
conventionally completed flowing well, it
is necessary to recognize that there are
three distinct phases, which have to be
studied separately and then finally linked
together before an overall picture of a
flowing well’s behavior can be obtained.

These phase are the inflow performance,
the vertical lift performance, and the
choke (or bean ) performance.

242
243
The inflow performance, that is, the flow
of oil , water , and gas from the formation
into the bottom of the well, is typified, as
far as gross liquid production is
concerned, by the PI of well or, more
generally, by the IPR.

The vertical lift performance involves a
study of the pressure losses in vertical
pipes carrying two-phase mixtures(gas
and liquid).
Mechanical Recovery (rod system)
LECTURE 14
244
Oil well pumping methods can be divided into
two main groups:

Rod systems. Those in which the motion of the
subsurface pumping equipment originates at
the surface and is transmitted to the pump by
means of a rod string. Rod less systems.
Those in which the pumping motion of the
subsurface pump is produced by means other
than sucker rods.
Of these two groups, the first is represented by
the beam pumping system and the second is
represented by hydraulic and centrifugal
pumping systems.
245
The beam pumping system consists essentially of five parts:

• The subsurface sucker rod—driven pump.

• The sucker rod string which transmits the surface pumping
motion and power to the subsurface pump. Also included is
the necessary string of tubing and/or casing within which the
sucker rods operate and which conducts the pumped fluid
from the pump to the surface.

• The surface pumping equipment which changes the rotating
motion of the prime mover into oscillating linear pumping
motion.

• The power transmission unit or speed reducer.

• The prime mover which furnishes the necessary power to
the system.
246
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42
Formation Damage Control
LECTURE 15
247
Skin Factor

It is not unusual for materials such as
mud filtrate, cement slurry, or clay
particles to enter the formation during
drilling, completion or work over
operations and reduce the permeability
around the wellbore.
248
This effect is commonly referred to as a
wellbore damage and the region of altered
permeability is called the skin zone. This zone
can extend from a few inches to several feet
from the wellbore.

Many other wells are stimulated by acidizing
or fracturing which in effect increase the
permeability near the wellbore.
Skin Factor
249 250
Thus, the permeability near the wellbore
is always different from the permeability
away from the well where the formation
has not been affected by drilling or
stimulation.

A schematic illustration of the skin zone
is shown in Figure 4-5.
Those factors that cause damage to the formation
can produce additional localized pressure drop during
flow. This additional pressure drop is commonly
referred to as Apskin. On the other hand, well
stimulation techniques will normally enhance the
properties of the formation and increase the
permeability around the wellbore, so that a decrease
in pressure drop is observed.




Figure 4-5
251
• Positive Skin Factor, s > 0
When a damaged zone near the wellbore exists, k-skin is less
than k and hence s is a positive number. The magnitude of the
skin factor increases as k-skin decreases and as the depth of
the damage r skin increases.

• Negative Skin Factor, s < 0
When the permeability around the well k-skin is higher than
that of the formation k, a negative skin factor exists. This
negative factor indicates an improved wellbore condition.

• Zero Skin Factor, s = 0
Zero skin factor occurs when no alternation in the permeability
around the wellbore is observed, i.e., k-skin = k.
252
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43
253
END

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