2. 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 pressure-
temperature diagram.
3. 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
6. 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.
7. 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).
8. 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.
9. Basic Concepts of Origin, Accumulation and
Recovery of Hydrocarbons
LECTURE 3
15. 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%.
16. 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 φ = porosity
17. 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
POROSITY
18. 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 φa = absolute porosity.
19. Effective porosity
The effective porosity is the percentage of interconnected pore
space with respect to the bulk volume, or
where φ = effective porosity.
20. 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
22. 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
23. where ν = apparent fluid flowing velocity, cm/sec
k = proportionality constant, or permeability, Darcys
µ = 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 ν 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
24. 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
26. 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.
27. For a radial flow, Darcy’s equation in a differential form can be written
as:
28. Intergrating Darcy’s equation gives:
The term dL has been replaced by dr as the length term has now become a
radius term.
30. 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
31. 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.
32. 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.
33. 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
34. 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.
36. 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
37. 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
39. 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.
40. 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.”
42. 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.
44. 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.
45. 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.
46. 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 θ.
The contact angle θ has achieved significance as a measure of
wettability.
47. 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.
51. 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
52.
53. 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
54. • 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
55. • 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
56. • 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.
Pressure-Temperature Diagram
57. 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
Types of Crude Oil
58. 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
59. 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
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
60. 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
61. 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
62. 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
63. Drives in the Reservoir(water drive and
compaction drive)
LECTURE 14
64. 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
65. 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 %
66. 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
67. 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.
69. 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
71. 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
73. 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.
74. 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 %
75. 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.
78. • 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.
79. • 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.
80. • 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 .
81. • 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.
83. 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
84. 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.
85. 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.
86. 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)
87. 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)
88. 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.
89.
90. 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 iso-potential
lines for a radial flow system.
92. 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
93. 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
95. 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.
97. 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.
98. 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.
99. 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
100. (5-1)
where
A = drainage area, acres
L = length of the horizontal well, ft
b = half minor axis of an ellipse, ft
101. 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:
102. (5-4)
Where
reh = drainage radius of the horizontal well, ft
A = drainage area of the horizontal well, acres
104. 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.
•
105. • 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 .
•
106. • 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).
108. • 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.
109. • 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.
111. 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.
112. 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.
Skin Factor
113. 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 ∆pskin. 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
114. • 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.