INTRODUCTION TO RESERVOIR
ENGINEERING
LECTURE 1
CLASSIFICATION OF RESERVOIRS
AND RESERVOIR FLUIDS
Petroleum reservoirs are broadly classified as oil or gas reservoirs.
These broad classifications are further subdivided depending on:
• The composition of the reservoir hydrocarbon mixture
• Initial reservoir pressure and temperature
• Pressure and temperature of the surface production
The conditions under which these phases exist are a matter of
considerablepractical importance. The experimental or the
mathematical determinations of these conditions are conveniently
expressed in different types of diagrams commonly called phase
diagrams. One such diagram is called the pressuretemperature diagram.
Pressure-Temperature Diagram
Figure 1-1 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.
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
Petroleum Geology
LECTURE 2
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.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 an hence is
exposed to higher temperatures and pressures.Eventually
chemical changes result in the generation of petroleum,a
complex,highly variable mixture lf hydrocarbons.
2 what is “trap” ?
The term “trap” was first applied to a hydrocarbon
accumulation by Orton: “…stocks of oil and gas might be
reapped in the summits of folds or arches found along
their wat to higher ground .”A detailed historical account of
the subsequent evolution of the concept and etymology of
the term trap is found in Dott and Reyonlds(1969).
3 where can we find petroleum ?
Hydrocarbons—crude oil and natural gas—are found in
certain layers of rock that are usually buride deep beneath
the surface of the earth.
Basic Concepts of Origin, Accumulation and
Recovery of Hydrocarbons
LECTURE 3
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Elements of Petroleum Reservoir
---fluid content of the reservoir
LECTURE 4
Porosity and Effective Porosity
LECTURE 5
POROSITY
• For rock to contain petroleum and later allow petroleum to
flow,it must have certain physical characteristics. Obvilusly,
there must be some spaces in the rock in which the
petroleum can be stored.
•
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.For example,if 100 cubic feet of rock contains
many tiny pores and spaces which together have a volume
of 10 cubic feet, the porosity of the rock is 10%.
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 f = porosity
POROSITY
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. Thus, many of
the void spaces are interconnected while some of the
pore spaces arecompletely isolated. This leads to two
distinct types of porosity, namely:
• Absolute porosity
• Effective porosity
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. The absolute porosity is generally expressed
mathematically by the following relationships:
or
where fa = absolute porosity.
Effective porosity
The effective porosity is the percentage of interconnected
pore space with respect to the bulk volume, or
where f = effective porosity.
One important application of the effective porosity is its
use in determining the original hydrocarbon volume in
place. Consider a reservoir with an areal extent of A
acres and an average thickness of h feet. The total bulk
volume of the reservoir can be determined from the
following expressions:
Bulk volume = 43,560 Ah, ft3
or
Bulk volume = 7,758 Ah, bbl
where A = areal extent, acres
h = average thickness
Permeability and Darcy’s Law
LECTURE 6
PERMEABILITY
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. 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.
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 a cross-section of area A,
then the governing fluidflow equation is defined as
where n = apparent fluid flowing velocity, cm/sec
k = proportionality constant, or permeability, Darcys
m = viscosity of the flowing fluid, cp
dp/dL = pressure drop per unit length, atm/cm
The apparent velocity determined by dividing the flow rate by the
cross-sectional area across which fluid is flowing. Substituting
the relationship, q/A, in place of n in Equation 3-21 and solving
for q results in
where q = flow rate through the porous medium, cm3/sec
A = cross-sectional area across which flow occurs, cm2
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
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
Linear flow model
where L = length of core, cm
A = cross-sectional area, cm2
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.
For a radial flow, Darcy’s equation in a differential form can be
written as:
Intergrating Darcy’s equation gives:
The term dL has been replaced by dr as the length term has now
become a radius term.
Saturation
LECTURE 7
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
where
So = oil saturation
Sg = gas saturation
Sw = water saturation
Sg + So + Sw = 1.0
Critical oil saturation, Soc
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.
Residual oil saturation, Sor
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. This saturation
value is called the residual oil saturation, Sor. The term
residual saturation is usually associated with the
nonwetting phase when it is being displaced by a
wetting phase.
Movable oil saturation, Som
Movable oil saturation Som is another saturation of
interest and is defined as the fraction of pore
volume occupied by movable oil as expressed by
the following equation:
Som = 1 - Swc - Soc
where
Swc = connate water saturation
Soc = critical oil saturation
Critical gas saturation, Sgc
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 gas begins
to move.
Critical water saturation, Swc
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 8
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 as shown in Figure 3.
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.
Figure 3
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. 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 pc.
Capillary pressure = (pressure of the nonwetting phase) - (pressure of
the wetting phase)
pc = pnw - pw
Figure4
Transition Zone
The figure indicates that the saturations are gradually
changing from 100% water in the water zone to irreducible
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. The transition zone is then defined as the
vertical thickness over which the water saturation ranges
from 100% saturation to irreducible water saturation Swc.
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.”
Figure 5
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. 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.
Wettabiloity and Distribution of Reservoir
Fluids
LECTURE 9
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
Figure1. Small drops of three liquids-mercury, oil, and
water—are placed on a clean glass plate.
The three droplets are then observed from one side as
illustrated in Figure 3-1. 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.
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. This angle, which
is always measured through the liquid to the solid, is
called the contact angle q.
The contact angle q has achieved significance as a
measure of wettability.
As shown in Figure 1, as the contact angle decreases, the wetting
characteristics of the liquid increase. Complete wettability would be
evidenced by a zero contact angle, and complete nonwetting would
be evidenced by a contact angle of 180°. 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.
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 nonwetting phase occupies the more
open channels.
Properties of Natural Gas
LECTURE 10
PVT Behaviour
LECTURE 11
Classification of Hydrocarbon
Reservoir
LECTURE 12
CLASSIFICATION OF RESERVOIRS
AND RESERVOIR FLUIDS
Petroleum reservoirs are broadly classified as oil or
gas reservoirs.
• The composition of the reservoir hydrocarbon
mixture
• Initial reservoir pressure and temperature
pressure-temperature diagram
Pressure-Temperature Diagram
Figure 1-1 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.
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
Pressure-Temperature Diagram
• 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).
At the critical point, the corresponding pressure and temperature are
called the critical pressure pc and critical temperature Tc of the
mixture.
Pressure-Temperature Diagram
• Bubble-point curve—The bubble-point curve (line BC) is
defined as the line separating the liquid-phase region from the
two-phase region.
• Dew-point curve—The dew-point curve (line AC) is defined as
the line separating the vapor-phase region from the two-phase
region.
Pressure-Temperature Diagram
•
Oil reservoirs—If the reservoir temperature T is less
than the critical temperature Tc 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.
Types of Crude Oil
Low-shrinkage oil
• Oil formation volume factor
less than 1.2 bbl/STB
• Gas-oil ratio less than 200
scf/STB
• Oil gravity less than 35° API
• Black or deeply colored
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
Retrograde gas-condensate reservoir
If the reservoir temperature T lies
between the critical temperature Tc
and cricondentherm Tct of the
reservoir fluid, the reservoir is
classified as a retrograde gascondensate 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.
Wet-gas reservoir
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
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
Dry-gas reservoir
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.
Drives in the Reservoir(water drive and
compaction drive)
LECTURE 14
The Water-Drive Mechanism
Many reservoirs are bounded on a portion or all of their peripheries by
water bearing rocks called aquifers. The aquifers may be so large
compared to the reservoir they adjoin as to appear infinite for all
practical purposes, and they may range down to those so small as
to be negligible in their effects on the reservoir performance.
Reservoir have
a water drive
Characteristics
Trend
Reservoir pressure
Declines very slowly (remains
very high)
Gas oil ratio
Little change during the life of
the reservoir (remains low)
Water production
Early excess water production
Well behavior
Flow until water production gets
excessive.
Oil recovery
35 to 75 %
Rock and Liquid Expansion
When an oil reservoir initially exists at a pressure higher than
its bubble-point pressure, the reservoir is called an
undersaturated oil reservoir.
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 expand due to
their individual compressibilities.
The reservoir rock compressibility is the result of two factors:
• Expansion of the individual rock grains
• Formation compaction
Rock and Liquid Expansion
Both of the above two factors are the results of a
decrease of fluid pressure within the pore spaces,
and both tend to reduce the pore volume through
the reduction of the porosity.
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,Gravity Drive
LECTURE 15
The Depletion Drive Mechanism
This driving form may also be referred to by the following various
terms:
• Solution gas drive
• Dissolved gas drive
• Internal gas drive
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
Figure 1 Solution gas drive reservoir
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. 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
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. 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.
Characteristics
Trend
Reservoir pressure
Variable rates of pressure
decline, depending principally
upon the amount of gas
conservation.
Gas oil ratio
Low gas-oil ratio
Water production
Little or no water production.
Well behavior
Oil recovery
Near to 80 %
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. Two combinations of driving forces can be present in
combinationdrive 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.
Figure 4 Combination drive reservoir
Derivation of Material Balance Equation
LECTURE 16
• 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 the space vavated by the fluids removed. When
the oil-and gas-bearing strata are hydraulically
connected with water-bearing strata, or aquifers,
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.
• In 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.
• The general material balance equation is simply
a volumetric balance, Which states that since the
volume of a reservoir (as defined by its initial
limits)is a 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 two decreases
must be balanced by changes of equal
magnitude in the water and rock volumes .
• 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.
Steady-state and Pseudo Steady-state Flow
LECTURE 17
The area of concern in this lecture includes:
• Types of fluids in the reservoir
• Flow regimes
• Reservoir geometry
• Number of flowing fluids in the reservoir
TYPES OF FLUIDS
In general, reservoir fluids are classified into three
groups:
• Incompressible fluids
• Slightly compressible fluids
• Compressible fluids
Incompressible fluids
An incompressible fluid is defined as the fluid 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.
Slightly compressible fluids
These “slightly” compressible fluids exhibit small changes in
volumeor density, with changes in pressure.
It should be pointed out that crude oil and water systems fit into
this category.
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
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.
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)
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
(4-3)
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.
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
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 isopotential lines for a radial flow system.
Figure 4-1 Ideal radial
flow into a
wellbore
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.
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. 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 4-3 Spherical flow due to limited entry
Figure 4-4 Hemispherical flow in a partially penetrating well
NUMBER OF FLOWING FLUIDS IN THE RESERVOIR
There are generally three cases of flowing systems:
• Single-phase flow (oil, water, or gas)
• Two-phase flow (oil-water, oil-gas, or gas-water)
• Three-phase flow (oil, water, and gas)
The description of fluid flow and subsequent analysis of pressure
data becomes more difficult as the number of mobile fluids
increases.
Horizontal Wells
LECTURE 18
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.
• 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.
Assuming that each end of the horizontal well is represented by a
vertical well that drains an area of a half circle with a radius of b,
Joshi (1991) proposed the following two methods for calculating
the drainage area of a horizontal well.
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 rev) at
each end and a rectangle, of dimensions L(2b), in the center.
The drainage area of the
horizontal well is given then by:
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
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.
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
reh = drainage radius of the horizontal well, ft
A = drainage area of the horizontal well, acres
Natural Flow Recovery
LECTURE 19
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 , that is , it may be
produced with a choke at the surface or it may
be produced with no choke at the surface. 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 .
•
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 , in 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.
•
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 20
• 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 teo groups,the first is represented by the
beam pumping system and the second is represented
by hydraulic and centrifugal pumping systems.
• The beam pumping system consists essentially of five
parts:
• The subsurface sucker rod—friven 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 pumpto
the surface.
• The surface pumping eauipment which changes the
rotating motion of the prime mover into oscillatinf linear
pumping motion .
• The power transmiddion unit or speed reducer.
• The prime mover which furnishes the necessary power
to the system.
Fomation Damage Control
LECTURE 22
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 workover operations and
reduce the permeability around the wellbore.
Skin Factor
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. 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 Dpskin. 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
• 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.
Revision
LECTURE 23;24
FINAL TEST
LECTURE 25