I. Basic History of A Reservoir
A. Assume a well is drilled and completed in a new, large reservoir.
B. Originally the reservoir has plenty of “energy” to produce the well by flowing.
E1
E2
E1
a. E1 is the energy that drives the fluid to the well bore.
b. E2 is the energy that is left over to lift the fluid up the well bore or tubing. E2 is some
fraction of E1.
C. In time the “energy” in the reservoir decreases and the produced fluid becomes heavier (higher water
cut).
E3
E4
E3
a. E3 is less than the original energy (E1). Therefore E4 is less than E2. This is called natural
depletion and eventually the well is not capable of flowing.
D. To further produce the well artificial lift, such as sucker rod or submersible, is installed. This does
not increase E3 any, but it does aid E4.
E3
E4
+
EL
E3
a. E3 is still capable of driving the fluid to the well bore but the remaining E4 cannot lift the
fluid by itself. With the aid of EL (artificial lift energy) the well is now capable of
production.
1
I. Basic History of A Reservoir
E. If this process was to continue for an infinite period of time, E3 would eventually decline to a point
that it would no longer be sufficient to drive the fluid to the well bore. Therefore injection wells are
put into place. All fluid made to this point is called primary recovery.
EI
E3
E4
+
EL
E3
EI
a. Water injection is started, adding EI.
b. Now E3 + EI are sufficient to drive the fluid to the well bore. In some cases E3 + EI may be
greater than the original energy E1.
c. The artificial lift energy (EL) may or may not be needed, depending on fluid weight, amount
of EI added, and the flowing ability of the reservoir.
d. Injection volumes need to equal withdrawal volumes to keep the reservoir energy at a
constant value.
F. Because oil and water do not mix well some of the oil is left in place. The amount of oil left after a
water flood may be as high as 60% of the original oil in place. The additional oil recovered during
the water flood process is called secondary recovery.
To recover more oil other methods are turned to such as polymer, steam, or CO2 flooding. The oil
produced from these methods is called tertiary recovery.
G. Eventually no more oil can be economically recovered and the reservoir is abandoned.
2
II. Reservoir Properties
A. Porosity ()

The term  is the Greek letter phi and is used for porosity in engineering calculations.

Porosity is defined as the ratio of the void space in a rock to the bulk volume of that rock
multiplied by 100 to express in percent (%). Also known as the fluid filled volume of a rock
divided by the total volume of the rock multiplied by 100. Otherwise stated it is a measure of
the space available for the storage of oil, water, and gas.
Magnified Many Times

Porosity is determined either from actual core analysis or more commonly from open-hole
logs, such as the acoustic log.
B. Saturation

Saturation is the fraction of the void volume or porosity that is filled with a given fluid. For
example water saturation would be calculated as follows.
Sw = (volume of water) / (volume of void)
If for example the water saturation is 0.20 or 20%, this means that 20% of the void
space is filled with water and the other 80% is filled with something else, usually oil
or gas.

Saturation is determined either from actual pressure core analysis or more commonly from
open-hole logs.

What we commonly call oil cut is not the same as oil saturation due to permeability and
compressibility properties. Because oil is more compressible than water, volumes in the
reservoir change when moved to the well bore. Also depending on the characteristics of the
reservoir, water or oil will flow more easily through the reservoir.
C. Permeability

In the introduction to API Code 27 it is stated that permeability is a property of the porous
medium and is a measure of the capacity of the medium to transmit fluids. In other words,
the permeability of a formation is a measure of the ease with which fluids will flow through
the particular formation.

The permeability of a rock is governed primarily by the size and number of pores in the rock,
or the porosity, and how well these pores are interconnected.

In general permeability increases with porosity, but this is not always the case. Shale for
example can have very high porosity but very low permeability.
3
III. Reservoir Drive Mechanisms
A. There are basically four different drive mechanisms within reservoirs. A drive mechanism can be
defined as the original energy within the reservoir which “pushes” the oil, water, and/or gas to the
well bore and up the tubing. Before going into the description of each drive mechanism some points
need to be made.
The drive mechanism pertains to primary production, before any injection is started. Once
injection is started, energy is added and the drive mechanism is altered. In some cases the drive
mechanism or original energy completely depletes and solely the injected fluid drives the fluid.
In most cases the two energies combine to drive the fluid.
In many cases, reservoirs can be singled out as having predominantly one main type of drive
mechanism. Other reservoirs may have any combination of the four drive mechanisms.
The type of drive mechanism that is in place will affect the PVT properties of the reservoir fluids
and to some extent the PI and IPR relationships. It is not in the scope of this course nor
necessary for our jobs to go into these affects. Just the basic concepts will be covered.
a. Gas-cap Drive
Gas
Oil
OWC
i. As can be seen the oil zone is overlain by a gas zone or cap.
ii. Under primary recovery the gas expands and drives the oil to the well bore. The
cause of this gas expansion is twofold.
1. First the gas-cap is under pressure and is therefore compressed. When a well
is drilled, the pressure decreases and the gas expands.
2. Also any gas in solution, usually in the oil, will be freed with this decrease in
pressure and will add to the volume of the gas-cap.
Pi
GOR
Pressure
Typical Gas-Cap Drive
Production History
Water Cut
Time
4
III. Reservoir Drive Mechanisms
b. Natural Water Drive
Oil
Water
i. Here the oil zone is underlain by a water zone or aquifer.
ii. In this case a drop in the reservoir pressure, due to the production of fluids, causes the
aquifer water to expand and flow into the reservoir. Graph A shows a partial water
drive. With a complete water drive the pressure stays constant with increasing water
oil ratio (Graph B).
iii. Of course water is not as compressible as gas, therefore a larger volume is required
from the water zone than the gas zone to drive equivalent amounts of oil.
A
Pi
B
Pressure
Pressure
WOR
WOR
GOR
Time
GOR
Time
Typical Natural Water Drive
Production History
c. Compaction Drive
i. The withdrawal of liquid or gas from a reservoir results in a reduction in the fluid
pressure and consequently an increase in the effective or grain pressure.
ii. Grain pressure is defined as the difference between the overburden and fluid
pressures.
iii. This increased pressure between the grains will cause the reservoir to compact and in
turn will drive the liquid or gas to the well bore.
iv. This drive is uncommon and is never considered as a primary mechanism
5
III. Reservoir Drive Mechanisms
d. Solution Gas Drive
i. A solution gas drive reservoir is one in which the principle drive mechanism is the
expansion of the oil and its originally dissolved gas. The freed gas does not rise to
form a gas-cap but stays as bubbles within the oil.
ii. In the first two drive mechanisms the size of the reservoir actually changes due to the
influx of water or gas. Here the size of the reservoir remains constant due to the
expansion of the reservoir fluids. In other words, the volume of expansion actually
equals the volume of production.
Pi
Pb
GOR
Pressure
Water Cut
Time
Typical Solution Gas Drive
Production History
6
IV. Pumping Bottom Hole Pressure
A. Definition of terms and abbreviations.
a. Bottom Hole Pressure (BHP): A pressure measured at a certain depth in a reservoir. This
pressure is at the face of the well bore. The depth varies from operator to operator and from
field to field. Some of the depths used are datum; top, middle, or bottom perforations; and
pump depth. It does not matter what depth is used as long as you stay consistent in all the
calculations. When someone gives you a bottom-hole pressure, ask what depth the pressure
was measured at.
b. Producing Bottom Hole Pressure: Defined as the stabilized bottom-hole pressure during a
producing period.
c. Flowing Bottom Hole Pressure (Pwf ): The stabilized bottom-hole pressure during a
producing period when the well is flowing.
d. Pumping Bottom Hole Pressure (PBHP): The stabilized bottom-hole pressure during a
producing period when the well is being produced via artificial lift, such as sucker rod or
submersible pumps.
e. Pump Intake Pressure (PIP): The stabilized bottom-hole pressure during a producing period
that is calculated at the actual pump intake depth.
f. Ground Level (GL): The elevation above sea level.
g. Kelly Bushing Height (KB): The height of the drilling floor above the ground level. Much of
well bore depth measurements are taken from the Kelly Bushing. The Kelly Bushing
Elevation is calculated by adding the ground level to the kelly bushing height.
h. Datum: A depth within a reservoir, which is measured from sea level and therefore is not
dependent on ground level. This gives a consistent or “level” plane within the reservoir to
refer to. The value of a datum is a negative number since the measurement is below sea
level. This term is used more by reservoir engineers than production people.
i. Datum Depth: This is calculated by adding the ground level elevation or kelly bushing
elevation to the datum. It does not matter if GL or KB elevations are used, just as long as
you are consistent. It is preferred to use the elevation that is consistent with logging
measurements.
A
C
GL
B
Sea Level
Datum
7
IV. Pumping Bottom Hole Pressure
Problem #1
Calculate the datum depth for each well.
Datum: -1700 feet
Kelly Bushing: 11 feet
Ground Elevations:
Well A: 3700 feet
Well B: 3603 feet
Well C: 3656 feet
j. Bottom Hole Pressure Depth (BHPD): The depth that the bottom-hole pressure is measured
at.
k. Pump Intake Depth (PID): The actual depth the bottom of the pump is set in the well bore.
The pump intake depth is used for pump intake pressure and total dynamic head calculations.
l. Tubing Intake Depth (TID): The depth at which well fluids enter the tubing string. At times
the pump intake and tubing intake depths are the same. In some cases there is a shroud or dip
tube installed in a well to enhance gas separation. The bottom of the shroud or dip tube is
equal to the tubing intake depth. The tubing intake depth is used in pumping bottom-hole
pressures.
m. Barrels of Oil Per Day (BOPD): The barrels of oil that is produced in a 24-hour period.
n. Barrels of Water Per Day (BWPD): The barrels of water that is produced in a 24-hour
period.
o. Oil Cut (OC) or Percent Oil (% Oil): The oil cut is the ratio of oil to total liquids, oil plus
water. Calculated by:
OC  BOPD  (BOPD  BWPD) (Equation 4.1)
Percent oil is calculated by multiplying the OC by 100.
p. Specific Gravity (SG): A dimensionless value that compares all liquids to fresh water and all
gases to air. Certain physical values can be calculated for any liquid by multiplying the
specific gravity of that liquid by the value for fresh water. For gases the values are calculated
by multiplying the specific gravity of the gas by the value for air. Fresh water and air have a
specific gravity of one. Liquids and gases with a specific gravity greater than one are heavier
than water or air.
A. Oil API: Most people use API values for oil. These must be converted to specific
gravities to be used in calculations. This can be done with the following formula:
Oil SG  141.5  (131.5  API) (Equation 4.2)
B. Specific Gravity of a Mixture (SGM): The specific gravity of any mixture can be
calculated if the individual fluid’s specific gravities and percentages are known.
The most common mixture of fluids in the oil patch is that of oil and water. The
specific gravity of this mixture is calculated by:
SGM  Oil SG  OC   Water SG  1  OC (Equation 4.3)
8
IV. Pumping Bottom Hole Pressure
q. Fluid Gradient: A value that is related to the weight of the fluid. It is a measurement of the
force in pounds per square inch (psi) that one vertical foot of the fluid would apply.
Therefore its value is psi/ft.
A. Oil Gradient (OG): Obtained by multiplying the oil specific gravity by 0.433 (the
value of fresh water). OG  SGO  0.433 (psi/ft) (Equation 4.4)
B. Water Gradient (WG): Obtained by multiplying the water specific gravity by 0.433
(the value of fresh water). WG  SGW  0.433 (psi/ft) (Equation 4.5)
C. Gas Gradient (GG)}: Obtained by multiplying the gas specific gravity by * (the
value of air changes as pressure increases). GG  SGG  * (psi/ft) (Equation 4.6)
D. Mixed Gradient (MG): Obtained by multiplying the mixture’s specific gravity by
0.433. MG  SGM  0.433 (psi/ft) (Equation 4.7)
Problem #2
Calculate the gradient for oil, water, and the oil / water mixture given the following:
BOPD: 275
BWPD: 561
Oil API: 33 degrees
Water Specific Gravity: 1.125
r. Producing Casing Pressure (CPP): The measurement of the pressure on the casing during a
producing period. Its value is in psi.
B. Determining the Pumping Bottom Hole Pressure (PBHP)
a. The pressure bomb is the most accurate method used to determine the PBHP. These range
from simple strain gauges to some elaborate crystal gauges. The accuracies can be as close
as 0.10 psi. These are not commonly used due to the cost involved and the fact that rods
should be pulled before running such a device.
b. Down hole sensors are used commonly with submersible pumps and at times with sucker rod
pumps. The majority of down-hole sensors in use at this time utilize boron tubes. These
tend to not be accurate, especially at the low and high end or their range. Making decisions
based on data from these devices can lead to wrong conclusions. Before drastic steps are
taken, such as pulling a pump, the values should be confirmed with one of the other methods.
Most companies have made recent improvements to these devices. Strain gauges are being
used to measure the PBHP. These down-hole sensors are much more accurate and reliable.
c. If the well has a packer in the hole, fluid levels cannot be used to calculate the PBHP. If all
the fluids come up the tubing, flow correlations can be used to estimate the PBHP. There are
several different flow correlations and programs available for this. The problem is not all are
accurate for a given field and there is not one that is best in all fields. The correct correlation
must be chosen by comparing to actual data gathered with a pressure bomb for each field.
d. If a chemical string or capillary tube is installed, these can be used to determine the PBHP.
The tube must be filled with a known gas and surface pressure measured. Great care must be
used when filling the tube with the gas; there is a change of error if a person is inexperienced.
9
IV. Pumping Bottom Hole Pressure
e. The most common method to determine the PBHP in wells without packers is the fluid level.
There is a chance of error with this method, especially when large amounts of gas are
produced up the backside. An experienced technician can usually get within 50 psi of the
actual value. There are several devices to measure this fluid level and most of them calculate
the bottom-hole pressure. It is best if a person knows the theories and calculations behind
these programs. Consider the following diagram.
Producing Casing Pressure
Fluid Above the Pump (FAP)
Actual Fluid Above the Pump (AFAP)
Pump Depth (PD)
Producing Interval
A. The fluid above the pump is derived from the actual shot fluid level (FL) and the
pump depth. The fluid level is determined by using an acoustic shot and either a
joint count or the acoustic velocity of the gas in the annulus.
FAP  PD  FL (Equation 4.8)
B. It has been proven that in most wells the fluid above the pump contains a
percentage of gas that will cause the fluid level to appear higher than it actually is.
This is commonly referred to as foam and is present in even low gas producing
wells. If all the gas were to be removed from the fluid we would have the actual
fluid above the pump (AFAP). Most modern fluid level devices will automatically
compensate for this. Programs are available that will calculate the AFAP given the
fluid level and change in casing pressure with time. If this “foam” is not
compensated for, large errors can be made in the bottom-hole pressure calculations.
It is best to use the AFAP in all cases to minimize the chance for error.
10
IV. Pumping Bottom Hole Pressure
C. The pressure for any depth in the well can be calculated by adding the producing
casing pressure to the force exerted by the fluids above that depth. The product of
the fluid gradient and the height of the column calculate the force exerted by a
column of fluid. F  Gradient  Height (psi) (Equation 4.9)
Well with the Pump set Above the Producing Interval
Producing Casing Pressure
Gas
Actual Fluid Above the Pump (AFAP)
Oil
Pump Depth (PD)
Oil & Water
Bottom Hole Pressure Depth (BHPD)
1. The column of fluid from surface to the actual fluid above the pump is the
well’s produced gas.
2. The column of fluid from the actual fluid above the pump to the pump is
usually oil. If the well has a very low oil cut or has not been producing long
enough to stabilize this column could be a mixture of oil and water. Of course
if the well does not produce any oil, the column would be all water.
3. The column of fluid from the pump to the bottom hole pressure depth is a
mixture of the oil, water and gas produced from the well. The gas usually is
neglected and the mixture is assumed to be of water and oil; based on the
well’s oil cut.
4. This can be further complicated if fresh water or chemical is being injected in
the well. It is recommended that any injection be terminated while shooting
the fluid level.
11
IV. Pumping Bottom Hole Pressure
Well with the Pump or Tailpipe set Below the Producing Interval
Producing Casing Pressure
Gas
Actual Fluid Above the Pump (AFAP)
Oil
Oil & Water
Producing Interval
Intake or Pump Depth
Bottom Hole Pressure Depth (BHPD)
1. The column of fluid from surface to the actual fluid above the pump is the
well’s produced gas.
2. The column of fluid from the actual fluid above the pump to the top of the
producing level is usually oil. If the well has a very low oil cut or has not
been producing long enough to stabilize this column could be a mixture of oil
and water. Of course if the well does not produce any oil, the column would
be all water.
3. The column of fluid from the top of the producing level to the bottom hole
pressure depth is a mixture of the oil, water and gas produced from the well.
The gas usually is neglected and the mixture is assumed to be of water and oil;
based on the well’s oil cut.
4. This can be further complicated if fresh water or chemical is being injected in
the well. It is recommended that any injection be terminated while shooting
the fluid level.
12
IV. Pumping Bottom Hole Pressure
D. Formulas for calculating the PBHP from fluid levels.
1. Well with the Pump set Above the Producing Interval
Bottom Hole Pressure Depth below the Pump Depth:
PBHP  CPP  GG  AFL  OG  AFAP  MG  BHPD  PD (Equation 4.10)
PBHP: Producing Bottom Hole Pressure
GG: Gas Gradient
AFL: Actual Fluid Level (AFL = PD – AFAP)
OG: Oil Gradient
AFAP: Actual Fluid Above the Pump
MG: Mixed Gradient
BHPD: Bottom Hole Pressure Depth
PD: Pump Depth
The gas column is normally very light and therefore does not add a significant
amount to the pumping bottom-hole pressure. Most computer programs go
ahead and include this column in the calculations. At times this term may be
dropped and the equation is simplified to:
PBHP  CPP  OG  AFAP  MG  BHPD  PD (Equation 4.11)
Some of the most commonly used programs assume the entire fluid column is
a mixed fluid. This further simplifies the equation as shown in equation 4.12.
This is not a bad assumption if the fluid level above the pump is low or the oil
cut is very low. A large error can be induced if the oil cut is high and/or the
fluid level above the pump is high.
PBHP  CPP  MG  BHPD  AFL (Equation 4.12)
Bottom Hole Pressure Depth above the Pump Depth:
PBHP  CPP  GG  AFL  OG  BHPD  AFL (Equation 4.13)
Dropping the gas column term results in the following equation:
PBHP  CPP  OG  BHPD  AFL (Equation 4.14)
Assuming the entire fluid column is a mixed gradient the equation becomes:
PBHP  CPP  MG  BHPD  AFL (Equation 4.12)
13
IV. Pumping Bottom Hole Pressure
Bottom Hole Pressure Depth equal to the Pump Depth:
In this case we are actually calculating the pump intake pressure (PIP).
PIP  CPP  GG  AFL  OG  AFAP (Equation 4.15)
Dropping the gas column term results in the following equation:
PIP  CPP  OG  AFAP (Equation 4.16)
Assuming the entire fluid column is a mixed gradient the equation becomes:
PIP  CPP  MG  AFAP (Equation 4.17)
2. Well with the Pump or Tailpipe set Below the Producing Interval: The
equations for this case are similar to those above. The only difference is the
oil column now extends down to the top of the producing interval. All the
equations listed assume there is an oil column and neglects the gas column
affects. If there is no oil production, replace OG with WG in all these
equations.
Bottom Hole Pressure Depth below Producing Interval
PBHP  CPP  OG  (TOP  AFL  MG  BHPD  TOP (Equation 4.18)
TOP: Top Of Producing Interval
Bottom Hole Pressure Depth above or equal to Producing Interval
PBHP  CPP  OG  (BHPD  AFL (Equation 4.19)
To calculate the PIP, substitute the pump depth for BHPD and use the appropriate
equation.
E. In most cases the bottom-hole pressure or pump intake pressure is either calculated
by a program or supplied by the customer. These numbers are accurate most of the
time. Just be aware there are times these pressures are in error. You now have the
knowledge how to check a value if a calculated pressure does not agree with a
measured pressure or your pump design does not perform as planned.
Problem #3
Calculate the pump intake pressure with the given data. First assume there is an oil column
above the pump. Next assume the entire fluid column is a mixture of water and oil. Finally
calculate the pressure at the perforations assuming an oil column is above the pump.
BOPD: 275
Pump Depth: 4900 ft.
AFAP: 1000 ft.
BWPD: 561
Oil API: 33 degrees
CPP: 25 psi
Perfs: 5160 ft.
SGW: 1.125
14
V. Static Bottom Hole Pressure
A. Definition of terms and abbreviations.
a. Initial Pressure (Pi): This is the pressure contained within a reservoir before any production
begins.
b. External Pressure (Pe): The pressure at the external boundary of the reservoir.
c. Average Pressure (Pbar): The average pressure in a bounded reservoir as determined by a
build up analysis.
d. P star (P*): The theoretical static bottom-hole pressure that would be obtained at an infinite
shut in time.
e. Static Bottom Hole Pressure (Pws or SBHP): The pressure within the well bore at formation
depth that is obtained when the well is shut in. This pressure is time dependent, and although
the required time for a good reading varies from field to field, a 36-hour shut in is usually
sufficient.
B. When a reservoir is first completed: Pi = Pe = P*.
a. The SBHP is measured in the well bore, and will become equal to Pi only after a very long
shut in period. Most often the shut in period is not long enough to obtain the Pi or P*.
b. P* or Pi is normally obtained by properly evaluating accurate build-up data.
c. When production is started, depletion begins and the reservoir pressure starts to decrease.
Therefore P* will be less than Pi.
d. Once any injection is started, as in a water flood, the reservoir pressure can continue to
decrease, remain constant, or increase. Therefore P* can be less than, equal to, or greater
than Pi.
C. If a reservoir has a number of injection wells, it actually will perform like a number of smaller
reservoirs.
P*1
P*2
P*3
P*4
a. The boundaries are formed by the injection wells and not the edge of the reservoir. In
general the resulting P*’s are not equal to each other. This is the reason that injection cells
are evaluated individually when balancing and required withdrawals are in question. Once
the desired P* is obtained, the cells are balanced by withdrawing the same amount of fluid
that is being injected.
15
V. Static Bottom Hole Pressure
b. There are several different injection patterns in use throughout the oil industry. Some of the
most common are line drives, 5 spots, 9 spots, and inverted 9 spots. Below is an example of
an inverted 9 spot. Two cells are shown side by side. As you can see, producing well A
affects both cells. Even though work is done on a cell basis, a change in one cell may affect
another. This should be taken into account to properly manage a flood.
Cell 1
A
Cell 2
D. P* vs. SBHP
a. Reservoir and production engineers use P* to evaluate the performance of the reservoir.
b. Production technicians and engineers use SBHP when evaluating single well performance
and designing artificial lift systems.
E. Determining P*
a. After producing a well until the flow rate and PBHP as stabilized, a well is shut in. The
increase in bottom-hole pressure, called a pressure build-up, is measured with a pressure
bomb or like device. This data must be accurate and the early data must be captured at very
small time intervals.
b. The pressure data is then plotted against time. The data and resulting shape of the curve is
then evaluated using various methods. One of the common methods is referred to as a
Horner Plot.
c. From this data several reservoir values can be calculated or estimated. These values include
P*, Pbar, permeability and mechanical skin factor. All of these terms have been defined
except for mechanical skin factor. Consider the following diagram.
P
r
e
s
s
u
r
e
Distance from Well bore
16
V. Static Bottom Hole Pressure
i. As you can see the pressure drop is higher close to the well bore. This is due to the
fact that the flow area steadily decreases as the fluid approaches the well bore. Much
like reducing a pipe diameter will increase the pressure drop for a given flow rate.
ii. The highest pressure drop occurs “near well bore”. If there is reservoir damage, such
as a scale build up near the well bore, this pressure drop is even higher. This will
result in lower flow into the well bore.
iii. Mechanical skin factor is a dimensionless measurement of the increased pressure
drop near the well bore due to any damage. There is no value of skin that indicates if
well bore damage is present or not. But by comparing mechanical skin factors from
analysis to analysis, the current condition of the near well bore can be determined.
d. Pressure buildups are not done on a regular basis in a given reservoir. At times they may
only be done when a reservoir is first discovered. There is one critical value we as
production people can glen from any pressure buildup. That would be the amount of shut-in
time required to obtain a SBHP that is realistic for a given reservoir.
F. Determining the static bottom-hole pressure (SBHP).
a. The most accurate method to determine the SBHP is to shut the well in for the necessary time
and then run in with a pressure bomb to record the down-hole pressure. These are often
called dip-ins, as the pressure bomb does not stay in the hole for a very long period of time.
These are costly, especially when rods have to be pulled, and are not commonly used.
b. A more common method is to shut the well in for the necessary time and then shoot a static
fluid level.
Shut-In Casing
Pressure (SCP)
Static Fluid Level
(SFL)
Producing Fluid Level
(PFL)
Pump Depth (PD)
Bottom Hole Pressure
Depth (BHPD)
i. There should be no “foam” present when a static fluid level is shot, as there should be
no flow of gas up the backside. It is still a good idea to check for a pressure build-up
with time in case things are not stabilized.
17
V. Static Bottom Hole Pressure
ii. The producing fluid level must be obtained during a period of stabilized production.
When the well is shut in, the fluid level and casing pressure generally will increase
with time. In some cases the fluid level may actually decrease while the casing
pressure will increase or visa versa. In any case the bottom-hole pressure will always
increase.
iii. In general there are four different zones of fluid gradients to consider. From surface
to the static fluid level there is a gas gradient. The area between the pump and the
producing fluid level is commonly an oil gradient. Between the pump depth and the
bottom hole pressure depth we have a mixed (oil and water) gradient. The area
between the static fluid level and producing fluid level will be a mixed (oil and water)
gradient also.
iv. The static bottom hole pressure can be calculated from the following equation:
SBHP  MG  BHPD  PD  OG  PD PFL  MG  PFL  SFL)  SCP (Equation 5.1)
1. As with the pumping down-hole pressure the zone with gas can be neglected
with very little error induced.
2. Also the actual gradients in each zone will vary depending on the pump set
depth in relation to the bottom hole pressure depth and actual oil cut.
3. If the fluid level actually drops when the well is shut in, the column of fluid
can be considered either all oil or a mixture of oil and water depending on the
oil cut.
c. At times it is difficult to convince upper management to shut in a well to collect the data for a
static bottom-hole calculation. There are two other methods to calculate a static bottom-hole
pressure. Even though this will not be accurate, there are times they should be used (if there
is no SBHP available or the SBHP is very old, more than three years).
i. When a well is being worked on, it may be closed in for a period of time. A fluid
level can be shot and equation 5.1 used to calculate the SBHP. If the shut in period is
not sufficient this SBHP could be in error. If kill fluids are present in the well bore,
the gradient for these fluids must be used.
ii. The other method utilizes data collected during a scale or chemical squeeze. When
fluid is squeezed into a well bore, either the tubing (flowing well) or the backside
(pumping well) will generally be full of a known fluid, the flush. Usually the flush is
produced water. By measuring the 15-minute shut in pressure, the SBHP can be
estimated with the following equation.
SBHP  SGflush  0.433  BHPD  Pshut-in (Equation 5.2)
If a well goes on vacuum during this process, this equation will not be applicable.
G. Problem #4
Calculate the SBHP with equation 5.1 with the following data; neglect the gas column.
BOPD: 250
Pump Depth: 4900’
PFL: 4500’
BWPD: 761
Oil API: 34.5
SFL: 1250’
BHPD: 5160’
SGW: 1.01
SCP: 150
18
VI. True Vertical Depth
A. When a well bore is drilled it is never completely straight. There will always be some
deviation present. This discussion does not apply to these “vertical” well bores. What we
are concerned about are well bores that are deviated on purpose. This is generally done due
to limited surface space (such as a well drilled in town or multiple wells drilled from an
offshore pad) or when a horizontal section in the well bore is desired. The goal is to get the
well bore from point A on the surface to point B in the reservoir. Point B will be located
some horizontal distance (x) from point A.
A
y
z
x
B
a. The distance y is the actual or measured depth of the well bore. It would take y feet
of tubing to get from the top to the bottom of the well bore.
b. The distance z is the “true vertical depth” (TVD) of the well bore.
B. A deviated well bore rarely if ever looks as above. There is usually a “kick-off point” where
the deviation begins.
A
w
C
z
d
y
x
B
a. Point C is the “kick-off point”. Of course it is not as sharp as shown in the diagram.
The kick-off tends to be a gradual curve until the desired deviation is achieved.
b. Distance w is the “straight” portion of the well bore.
c. Distance w  y is the actual or measured depth of the well bore.
d. Distance w  z is the true vertical depth of the well bore.
e. Distance x is the horizontal displacement of B from A or C.
f. Angle d is the angle of deviation from true vertical depth.
19
VI. True Vertical Depth
C. Determining True Vertical Depth (TVD)
a. The best way to determine the true vertical depth is by obtaining a record of the
deviation survey or report. These surveys are generally run on deviated well bores.
This report will record measured depth, angle of deviation, true vertical depth, and
dogleg severity at various increments. To obtain a TVD, simply obtain a measured
depth and go to the survey and read off the TVD. If the desired measured depth is not
in the survey, then extrapolate between the two closest points. This is the easiest and
most accurate method to determine a true vertical depth.
b. If a deviation survey is not available, then the TVD may be calculated using the
triangle formed by lengths x, y, and z plus the law of cosines. Certain data must be
available to perform this calculation.
Measured depth
Angle of deviation
Kick-off depth
The law of cosines: Cosine A  adjacenthypotenuse
Cosine d  zy
or
or
z  Cosine d  y (Equation 6.1)
i.
Example:
a. Measured Depth: 5200’
Angle of Deviation: 5 degrees
Kick-off Depth: 2000’
b. Diagram
2000’
z
5
3200’
c. z  Cosine 5  3200
z  3188’
d. TVD  2000  3188  5188’
ii.
This calculation applies to any point along the hole, not just the bottom.
20
VI. True Vertical Depth
D. How does TVD affect a pump designer in their day-to-day work? Of course we are aware
that a highly deviated well bore will adversely affect submersible equipment. The cable will
need to be protected from crushing with the various cable protectors that are on the market.
If the deviation is severe enough, flat cable may be required for added crush resistance. Also
the pumps, seals and motors can be damaged if the dogleg severity is too high. There is a
program available (ESP Bend) that can determine if the dogleg severity is too high to install
submersible equipment. Until the program is released for general use, contact OKC
engineering. The data required is the deviation survey and a description of the equipment
that is to be installed.
There is also a hidden problem associated with deviated holes. Consider the following:
Well Bore A
5000’
8000’
Well Bore B
Which well bore exerts the highest pressure at the bottom if both are filled with fresh water.
Hole A: 5000 ft.  0.433 psi/ft  2165 psi
Hole B: 8000 ft.  0.433 psi/ft  3463 psi
Well bore B does, right? Wrong, pressure gradients are figured on true vertical depths not
measured depths. In this case both wells would exert 2165 psi at the bottom.
E. Problem #5
Assume:
Measured Depth: 6000 ft
Angle of Deviation: 40 (Cosine 40  0.766)
Kick-off Point: 2000 ft
Adjusted Fluid Level: 4500 ft
Pump Depth: 5500 ft
Fluid Gradient: 0.433 psi/ft
Calculate:
TVD of the Well Bore
Pump Intake Pressure
21
VII. Differential Pressure or Pressure Draw Down
A. Pressure Draw Down (P): Defined as the difference between the static bottom-hole pressure and
the pumping bottom-hole pressure.
P  SBHP  PBHP (Equation 7.1)
B. The amount of pressure draw down dictates the amount of flow into the well bore or production.
The higher the draw down, the higher the production.
PBHP
PS
Flow
SBHP
a. On the above diagram a new term has been introduced, Ps or delta P skin. This Ps is
attributed to a skin of reduced permeability (formation damage, paraffin, scale, etc.) around
the well bore. This Ps reduces the amount of flow into the well bore. For an analogy
consider a pipeline that has a certain upstream pressure, downstream pressure, choke, and a
fixed diameter. To increase flow rate one of three things can be done. These are:
i. Increase the upstream pressure.
ii. Decrease the downstream pressure.
iii. Open the choke, which will decrease the amount of pressure drop or P.
b. The same situation exists in our reservoir. The upstream pressure is equivalent to SBHP,
downstream pressure to PBHP, and the choke to Ps. To increase production we can:
i. Increase the SBHP: increase injection rate.
ii. Decrease the PBHP: install larger artificial lift equipment.
iii. Decrease Ps: stimulate the well bore.
c. Ps is related to the mechanical skin factor that was covered in the SBHP section (E.c.iii).
Ps can be calculated using data from a pressure build-up.
22
VIII. Well Potential
A. Well Potential: A measurement or relationship that represents a well’s ability to give up fluids, or to
produce. As a well is produced, there is a direct relationship between the producing rate (Q) and the
pressure draw down (P). The producing rate increases as the pressure draw down increases. The
producing rate applies to liquids only (oil & water) at stock tank conditions. The amount of gas
produced is estimated from gas / oil ratios (GOR) or gas / liquid ratios (GLR).
B. There are basically two different types of well potential relationships. The types of fluids that are
produced from a well bore will determine which relationship is used.
a. Productivity Index (PI): This relationship applies to incompressible well fluids, such as
water. Used normally if the oil cut and gas rate is low.
b. Inflow Performance Relationship (IPR): This relationship applies to compressible well
fluids, such as oil and gas. Used normally if the oil cut or gas rate is not low.
c. Combination Curve: As the name implies, this is a combination of the PI and IPR
relationships. The PI relationship is used at pressures above the reservoir bubble point while
the IPR relationship is used at pressures below the reservoir bubble point.
The best way to determine which relationship to use for a given reservoir is to compare calculated
values to actual pressures and rates. The well potential in a reservoir can change as fluid
composition changes.
C. Determining the Productivity Index (PI)
a. This relationship is calculated by:
PI  Q  (SBHP  PBHP (Equation 8.1)
Once the PI is known, a rate can be calculated for any given PBHP by:
Q  PI  (SBHP  PBHP (Equation 8.2)
Also a PBHP can be calculated for any given rate by:
PBHP  SBHP  (Q  PI (Equation 8.3)
b. A graphical presentation of pumping bottom-hole pressure versus rate would produce a
straight line.
SBHP
PI Relationship
Pressure (PSI)
0
0
Rate (BPD)
Qmax
23
VIII. Well Potential
c. To plot the PI relationship only two points are needed; one will be 0 rate at the SBHP. The
other point will be defined by a rate and corresponding PBHP.
1. Therefore to calculate or plot the PI for a well we need the SBHP, a PBHP, and a
corresponding rate (Q).
2. It is very important that the rate and PBHP be measured on the same day.
3. The SBHP and PBHP must be calculated at the same depth in the well bore.
4. At times the SBHP is not available but the PI relationship can still be figured by
simply obtaining two PBHP with their corresponding rates. Plot the two points and
draw a straight line through them. The SBHP can be estimated from the plot and
the PI calculated.
5. Once the PI is plotted, the rate at any PBHP can be derived.
d. On the above plot a new term has been introduced, Qmax. Qmax is defined as the maximum
rate at which a well will produce. To achieve this, the maximum draw down must be
attained, or PBHP will be zero.
Qmax  PI  SBHP (Equation 8.4)
e. Problem #6
With the following data:
Q: 800 BPD
SBHP: 3000 psi
PBHP: 1400 psi
Calculate:
1. PI
2. Qmax
3. Plot the PI relationship
4. Q if PBHP is 800 psi
D. Determining the Inflow Performance Relationship (IPR): The calculations for IPR are a little more
intense because the fluids are no longer incompressible. The volume will increase due to increased
draw down and due to pressure drop.
a. The most common IPR in use is Vogel’s IPR, this relationship is defined by:
QQmax  1  0.2  PBHP  SBHP  0.8  PBHP  SBHP2 (Equation 8.5)
In this equation Q is the rate obtained at the PBHP used in the calculations. Once the term
QQmax is determined, Qmax can be calculated by:
Qmax  Q  QQmax (Equation 8.6)
Now a rate can be calculated for any given PBHP by:
Q  Qmax  QQmax (Equation 8.7)
Realize the term QQmax has to be calculated by Equation 8.5 for each new PBHP.
24
VIII. Well Potential
b. A graphical presentation of pumping bottom-hole pressure versus rate would produce a
curved line.
SBHP
IPR Relationship
Pressure (PSI)
0
0
Rate (BPD)
Qmax
1. It will require more points to define this relationship since this line is a curve. The
points can be calculated; they do not all have to be measured. To do so the SBHP,
PBHP and corresponding rate are needed.
2. As before, the PBHP and rate data should be gathered on the same day and the
SBHP and PBHP depths must be the same.
c. Since the calculations are more complicated, Vogel’s Dimensionless IPR Curve (next page)
and the following steps are often used to construct an IPR curve for a well.
1. Calculate the ratio of PBHP to SBHP (PBHP  SBHP). (PPs on the graph.)
2. Enter into the graph and find the corresponding value of QQmax (qqm on the
graph).
3. Use Equation 8.6 to calculate Qmax.
4. Calculate the ratio, in step one, a few more times using different PBHP values. The
curve will be more accurate as more points are used.
5. Enter into the graph and find the corresponding value of Q/Qmax for each PBHP.
6. Calculate the corresponding values of Q for each PBHP using Equation 8.7 and
Qmax obtained in step 3.
7. Now plot all the points and draw in the IPR curve.
You can get the same results by using Equation 8.5 to calculate the Q/Qmax values.
Graphs are quicker but equations are usually more accurate.
d. Problem #7
With the following data:
Q: 800 BPD
Calculate and/or Plot:
IPR Curve (Use PBHP values of 2500, 2000 and 1000 psi)
SBHP: 3000 psi
From curve find Q for PHBP of 800 psi
PBHP: 1400 psi
Use equations to find Q for PBHP of 800 psi
25
VIII. Well Potential
26
VIII. Well Potential
E. Determining the Combination Curve
a. To draw this curve one more piece of information is required, the reservoir bubble point
pressure. All the points above the bubble point pressure will behave according to the PI
relationship and all the points will behave according to the IPR relationship.
b. Below is a plot comparing the three different curves for a given well.
Pressure
Comb.
PI
IPR
Rate
c. As you can see the IPR curve tends to be a little optimistic at the lower rates and very
pessimistic at the higher rates. Critical design errors will be induced if the incorrect
relationship is utilized.
27
IX. Reservoir Barrels and PVT Data
A. In most reservoirs the reservoir barrels (pump barrels) that are produced do not match the stock tank
barrels (measured barrels). Serious design errors can be made if this is not taken into account when
sizing artificial lift. This is especially true in wells that have very high oil cuts, gas liquid ratios
and/or under a CO2 flood.
B. The actual reservoir barrels can be calculated or estimated by using PVT data. PVT (Pressure –
Volume – Temperature) Data is basically information about any type of fluid that predicts how the
volume of that fluid will change as the pressure and/or temperature of the fluid is altered. PVT data
is used by reservoir personal to predict the performance of a reservoir and by production personal to
predict the performance of a well and to design artificial lift systems.
C. The following diagram shows the relation between stock tank barrels and reservoir barrels.
Solution &
Free Gas
Stock Tank
Oil & Water
Oil
Gas
Water
The volumes are not only affected by the change in pressure and temperature. The release of
free gas in solution can greatly change measured volumes.
D. When it comes to hydrocarbon fluids, free natural gas is the easiest one for which to come up with
the PVT relationship. The relationship can be put into equation form as:
PV  ZnRT (Equation 9.1)
Where:
P = Pressure (psig)
V = Volume (ft3)
Z = Z-Factor: a term to correct for the deviation from ideal gas
N = Number of Pound Moles
R = Universal Gas Constant
T = Absolute Temperature (degrees Rankin)
Unfortunately most reservoirs’ PVT parameters are more complex due to the presence of oil, water,
and gas. The PVT parameters for such a reservoir are determined by laboratory analysis or by using
one of the several correlations that are available. Of course laboratory analyses are more accurate
and should be used whenever available.
28
IX. Reservoir Barrels and PVT Data
E. Definition of terms:
Both the standard cubic foot (scf) and the stock tank barrel (stb) referred to in the below
definitions are defined as volumes at standard conditions, 60 F and one atmosphere (14.7
psig at sea level).
a. Bubble Point (Pb): The pressure, at reservoir temperature, that the first bubble of gas is
liberated from the liquid phase. Also known as the saturation pressure.
b. Solution Gas-Oil Ratio (Rs): The number of standard cubic feet of gas that will dissolve into
one stock tank barrel of oil when both are taken down to the reservoir at the prevailing
reservoir pressure and temperature. Units: scf gas / stb oil.
700
RS
500
300
100
Pb
1000
2000
3000
4000
Pressure
c. Oil Formation Volume Factor (Bo): The volume in barrels occupied in the reservoir by one
stock tank barrel of oil plus its dissolved gas. Units: rb / stb oil.
1.3
Bo
1.2
1.1
Pb
1.0
1000
2000
3000
4000
Pressure
d. Gas Formation Volume Factor (Bg): The volume in barrels that one standard cubic foot of
gas will occupy as free gas in the reservoir. Units: rb / mscf gas.
.08
Bg
.06
.04
Pb
.02
1000
2000
3000
4000
Pressure
e. Water Formation Volume Factor (Bw): The volume in barrels occupied in the reservoir by
one stock tank barrel of water plus its dissolved gas. Units: rb / stb oil. Since water is
basically incompressible and hydrocarbon gas will not dissolve in it, this term is normally
ignored.
29
IX. Reservoir Barrels and PVT Data
F. Determining Reservoir Barrels
a. Stock tank barrels can be converted to reservoir barrels by the following equation:
RB  STBO  Bo  GOR  Rs  STBO  Bg  1000  STBW (Equation 9.2)
Where:
STBO: Stock Tank Barrels of Oil
GOR: Gas-Oil Ratio
STBW: Stock Tank Barrels of Water
b. With the addition of CO2 the conversion becomes more complex due to the following:
i. CO2 has its own Bg that is different from that of hydrocarbon gas.
ii. While hydrocarbon gas does not dissolve into water, CO2 will dissolve into water.
Now the Bw term becomes significant.
iii. Oil will swell when CO2 is dissolved into it, changing the Bo.
iv. Generally CO2 gas will generally dissolve into the water before it will dissolve into
the oil. Also the oil must “accept” all available hydrocarbon gas before any CO2 can
be put into oil solution.
To calculate reservoir barrels when CO2 is present is a long 18 step procedure, the final
equation looks like:
RB  STBO  Bo  OSF  WCO  Bw  WU  FHC  1000  Bg  FCO  1000  Bg
Where:
OSF: Oil Swell Factor
WCO: STBW affected by CO2
WU: STBW unaffected by CO2
FHC: Free Hydrocarbon Gas in MSCF
FCO: Free CO2 Gas in MSCF
Bg: CO2 Gas Formation Factor
c. When CO2 is present it is very critical to convert from stock tank barrels to reservoir barrels
prior to designing any artificial lift systems. Errors as high as two to one can result if this is
not done. Fortunately there are programs that will do this calculation and most modern
design software will convert to reservoir barrels prior to sizing submersible pumps.
30
X. Well Bore Completions
A. Knowledge of the well bore completion and treatments will greatly enhance the pump designer’s
chance of success. This section will discuss varies aspects of well bore completions.
B. Open Hole versus Perforations:
a. Many of the old well bores have open-hole completions. The casing string is terminated just
above the targeted producing zone. The producing zone is then drilled as an “open hole”.
i. Advantages:
1. Less cost involved.
2. More formation face “open” for production.
3. No cement circulated across the formation face, less chance of damage.
ii. Disadvantages:
1. Generally more formation solids enter the well bore.
2. Open holes can “cave” in.
3. Very difficult to achieve zonal isolation.
4. In gassy wells, can not set below the “perfs”.
b. Most modern day completions involve setting the casing across the production zone. The
casing is then perforated in the production zone. The perforations are created normally with
shaped charges. The configuration of these charges will vary from 1 shot per foot at 0
spacing to 20 shots per foot at 360. The depth of penetration can be altered by the size and
shape of the charges. The perforation guns can be wire-line or tubing conveyed and may be
reusable or disposable. The perforations may be shot with the well over-balanced, basically
killed, or under-balanced, the well will flow as soon as the perforations are shot. What is
done depends on the type of reservoir and the philosophy of the operator.
i. Advantages:
1. Well bore better protected from solids and cave-ins.
2. Zonal isolation is possible.
3. If enough “rat-hole” is present, can set below perforations for gassy wells.
ii. Disadvantages:
1. More cost involved.
2. Cements pumped to set the casing can generate formation damage.
C. Vertical versus Horizontal
a. The majority of the well bores are vertical. At times they can be deviated, the deviation
driven by surface limitations, but are basically vertical in the producing zone.
b. Horizontal well bores have been used recently for several different reasons.
i. Very thin pay zones.
ii. Attempts to increase productivity.
iii. Reduce the number of wells to drill.
31
X. Well Bore Completions
At times you may find a well that has a horizontal “window” with perforations in the vertical
section either below or above the horizontal section.
c. The producing zone can be either open hole or cased and perforated in either case. The
severity of deviations from horizontal plays a very important in the design of submersible
pumps.
D. Well Bore Stimulation:
a. As we mentioned earlier, the largest flow restriction in the reservoir occurs near the well
bore. Formation damage is also a near well bore phenomenon. The formation damage can
occur from kill fluids, cements, and solids that are pumped down-hole. Scales can form near
the well bore due to the large pressure drop at the formation face. These are the reasons
wells are stimulated from time to time, the desire is to remove damage or decrease the
pressure drop near the well bore. There are basically two methods used for well bore
stimulation, acidizing and fracturing.
b. Acidizing is used when formations have a matrix (dolomite) or formation damage that is acid
soluble. The most commonly used acid is 15% HCl, but several other types and strengths are
in use. The zones to be treated are usually isolated with bridge plugs and packers or a special
tool called a PPI (pin-point injection) tool. The acid is spotted to the formation and then
“forced” into the formation with pressure. The amount of pressure used depends on the type
of job desired. For a matrix acid job, the pressures are lower and the job tends to take more
time. At higher pressures the formation will fracture and the job will go faster. If a PPI tool
is not used, different forms of blocking agents are dropped during the acid job. This is done
to prevent all the acid from going into one zone. Some of the common blocking agents are
rock salt, benzoic acid flakes, or balls. Sometimes the acid is gelled so it will penetrate
deeper into the rock. Foaming agents may be used to improve clean-up operations.
c. Fracturing is used normally when the formation matrix is not acid soluble (sandstone). The
objective here is to create long fractures radiating from the well bore. High pressures and
special fluids are used to create these fractures. Propents are also pumped to keep the
fractures from closing once the pressure is removed. Large grains of sand are commonly
used for this. If installing artificial lift after a “frac” job, be aware abrasives will most likely
be produced for a period of time.
E. Chemical Treatments:
a. The chemical is introduced to the well bore via three different means:
i. Batch Treatment: The chemical is periodically pumped down the backside with a
chemical treatment truck. A flush is normally used to push the chemical down hole.
This only works with chemicals that have a “life”. If the well flows hard up the
backside, this treatment will not be very effective.
ii. Slipstream Treatment: At times a chemical will require continuous injection. A
chemical tank and pump is set at location and the chemical is pumped down the
backside continuously. A portion of the produced fluids is pulled in from the tubing
side and re-injected with the chemical to provide a flush. This is a cost effective
method for continuous injection, but only works if the well does not flow up the
backside.
32
X. Well Bore Completions
iii. Capillary String Treatment: This is the most costly but effective means of continuous
injection. If the well flows very hard up the backside, it is the only means to inject
chemical down hole. A capillary string, usually 3/8” stainless tube, is installed when
the tubing is run into the hole. The tube is coiled into the hole, banded to the tubing,
and terminated at the desired injection point. A chemical tank and pump are
connected to this tube. The chemical is injected at the required rate. Very accurate
placement of the chemical can be attained with this method. At times two tubes may
be run either for two incompatible chemicals or two different injection points.
b. There are all kinds of chemicals in use for different production problems:
i. Corrosion Inhibitors: Some well fluids are very corrosive; such as H2S, CO2, Water
chlorides and fluorides, and bacteria. This corrosion can be combated with
metallurgy, coatings and wrappings, and/or chemicals. The type of treatment varies
greatly depending on fluid properties, pressures, and temperatures. Be aware that
many of these chemicals contain compounds that are detrimental to cable insulation
and equipment o-rings. If chemical is being injected in a well that a submersible is to
be installed in, we need to get a copy of the MSDS sheet and check if we are
installing the proper equipment. These chemicals are introduced via any of the
above-mentioned methods.
ii. Scale Inhibitors: Some fluids have “scaling tendencies”. Two things will accelerate
the formation a scale in these fluids, increased temperature and pressure drop. Scale
inhibitors can greatly decrease the formation of these scales. The chemical can be
injected continuously or “squeezed” into the formation. These squeezes will have a
finite life, depending on the rate of water production. Chemical residuals should be
checked on a monthly basis, and the re-squeezed once depleted.
iii. Paraffin Treatments: Paraffin and asphaltene is a common problem in the oil field.
Using hot oil or water is one of the most popular methods to treat for paraffin. At
times chemicals, such as dispersants are added to the water or oil. Realize the fluid is
injected down the backside and if too hot can cause cable problems near surface. The
lower pigtail splice is what normally fails. Paraffin is also treated with crystal
modifiers (inhibit the formation) or solvents (clean up after formation). These
chemicals can be injected via any of the above-mentioned methods.
iv. Solid Treatments: Some well fluids bring in or precipitate solids, such as iron sulfide.
One cost effective way to treat for these is the use of surfactants or soap. Much like
helps to clean the dishes, the surfactants will help clean or move these solids through
the pump. There are some acid-surfactants that are being tried for very heavy iron
sulfide problems. If too much is injected down hole, foam will result that can “gas
lock” the submersible pump. These chemicals are usually continuously injected.
33
XI. EOR Processes
A. When a reservoir is first drilled and produced, the production is referred to as primary production,
utilizing the natural energy of the reservoir. The range of oil recovery for primary production is 5%
to 20% of the original oil in place (OOIP). The average recovery is 18% of the OOIP.
At a point in time it will no longer be effective or economical to continue oil production. The
reservoir is then either abandoned or secondary production methods are utilized. The most common
method of secondary production is the water flood. Water is injected to “sweep” some of the oil to
the producers and to add energy to the reservoir. Since water and oil do not mix, some of the oil is
left behind. The additional oil recovery ranges from 25% to 45% of the OOIP; the average recovery
is 32% of the OOIP.
Roughly 50% of the OOIP will be left in the reservoir if the reservoir is abandoned once the field
“waters out”. The next phase of oil recovery is referred to as tertiary or EOR production. Below is a
plot showing the general shape of the production curves utilizing all three phases of oil production.
O
I
L
P
R
O
D
U
C
T
I
O
N
Secondary
Oil
Tertiary Oil
Primary Oil
TIME
B. There are several different EOR processes available. The following diagram shows the majority of
tertiary or EOR processes that are available. As of June 1984 there was 465 billion barrels of OOIP
domestically. There had been 130 billion barrels produced, 27 billion barrels of reserves for primary
and secondary production, and 53 billion barrels available for existing tertiary technologies. That
still leaves 255 billion barrels for future technologies.
34
XI. EOR Processes
EOR OR TERTIARY PROCESSES
Water
Water Flooding with Formation of
Surfactant in the Reservoir
Alkali
Water Flooding with
Thickened Water
Polymers
Injection of
Micellar Solutions
Surfactants + Alcohol
+ Crude Oil
Water flooding with Reduced
Interfacial Tension
Low Concentration
Surfactants
Chemicals
Hot Water
Flooding
Heat
Steam Stimulation
(Huff-n-Puff)
Steam
Flooding
In Situ Combustion
With Water Injection
Air
In Situ
Combustion
CO2 Stimulation
(Huff-n-Puff)
CO2 Immiscible Flooding Alternate
Injection of CO2 and Water
CO2 Miscible
Flooding
Carbon
Dioxide
CO2 Miscible Flooding Alternate
Injection of CO2 and Water
N2 Miscible Flooding Alternate
Injection of N2 and Water
Gases
Nitrogen
High Pressure
Gas Drive
Enriched
Gas Drive
Injection of an LPG Slug
Followed by Gas
Natural
Gas
Alternate Injection of
Natural Gas and Water
35
XI. EOR Processes
C. CO2 flooding is common in the Permian Basin. There are two different types of CO2 floods,
immiscible and miscible. The reservoir pressure and the system miscibility or “mix ability” pressure
determine which type of flood is utilized. Immiscible floods have lower reservoir pressures and are
therefore less costly to operate. Miscible floods have higher reservoir pressures but are more
effective in recovering additional oil.
a. Immiscible (non-mixable) Displacement:
i. Major causes of improved oil recovery:
1. Reduced oil viscosity: increases the mobility of the oil.
2. Swelling of oil: oil saturation increases.
3. Addition of reservoir energy.
ii. Minor causes of improved oil recovery:
1. Reduced oil-water interfacial tension.
2. Well bore stimulation: increased permeability due to carbonic acid.
b. Miscible (mixable) Displacement: Multiple contacts of CO2 and crude oil develop modified
phases that become miscible with each other.
i. Major causes of improved oil recovery.
1. Reduced oil viscosity: increases the mobility of the oil.
2. Swelling of oil: oil saturation increases.
3. Addition of reservoir energy.
4. Vaporization and extraction of the lighter hydrocarbon ends (C2 – C30).
ii. Minor causes of improved oil recovery:
1. Reduced oil-water interfacial tension.
2. Well bore stimulation: increased permeability due to carbonic acid.
c. There are a couple of undesirable side-affects from the injection of CO2.
i. Since the lighter ends of the oil are extracted by the CO2, the formation of heavy
paraffin and asphaltene are common. This is also accelerated from the cooling affects
of CO2.
ii. When CO2 and water are mixed together, carbonic acid is formed. Corrosion then
becomes a possible problem.
36
XII. Total Pumping System
To properly design any type of artificial lift, a designer must understand all the components in a system. If
one component is changed it will affect the performance of all the associated components. Planning for
artificial lift should start before a well is drilled because some form of lift will probably be required to
deplete the reservoir. Usually a well will produce for a longer period of time with artificial lift than it will
flow. Apparently this simple fact is ignored in many instances.
How may times have you heard the following statements made when a well is drilled and completed?
“Drill a small diameter hole and use 4 ½” or 5 ½” casing instead of drilling a larger diameter hole
and using 5 ½” or 7” casing and we will save on the well’s expenses.”
“Forget about drilling a rat hole below the pay zone and we will save on the drilling expenses.”
“Casing size limits the size of artificial lift equipment that can be used but we will worry about that
later since the well will probably flow for five years.”
Statements like these illustrate the short sightedness that is often practiced. The Total Pumping System
concept that gives proper consideration to all the factors in the producing life of a well is not considered.
The majority of people who design and approve the drilling programs do not understand artificial lift or the
factors that affect it.
Some of the factors that must be considered when designing any type of artificial lift are:
1. The type of reservoir.
2. Reservoir characteristics.
3. Reservoir fluid properties.
4. Static bottom-hole pressure and temperature.
5. Pumping bottom-hole pressure.
6. The well’s inflow capacity.
7. Producing interval depths
8. Type of completion.
9. Casing size and weight.
10. Total depth, drill out depth, or plug back depth.
11. Presence, location and size of liners.
12. Presence and severity of well bore deviation.
13. Presence of junk in the hole or casing damage.
14. Solids that may be produced.
15. Corrosion, scale, or paraffin problems.
Many individuals who recommend work-overs or stimulations do not use the Total Pumping System
concept. Running a 4” liner to repair a casing leak is a prime example. This usually limits a pump designer
to 2 3/8” tubing and limits the size of pump that can be utilized. Individuals who recommend plugging or
diverting agents for acid or frac jobs can add to a pump designer’s problems. These solids often will plug
the pump, causing a premature failure. If diverting agents are pumped down a well, it should be standard
operating practice to clean them out by circulating or bailing before the pump is installed. It is costly and
time consuming to attempt cleaning a well with the down-hole pump.
37
XII. Total Pumping System
Individuals who design surface facilities can also cause pump designers problems by ignoring the Total
Pumping System concept. Most wells have the casing connected to the flow line. The flow line is
connected to a separator, free water knockout, treater, or tank. The sum of the vessel pressure, pressure
drop through the flow line and difference in elevations will be reflected at the wellhead. This additional
backpressure may be enough to restrict flow into the well bore. Any backpressure reduces the amount of
gas separation that can be accomplished in the annulus. If the amount of gas that is separated is reduced
more gas goes through the pump, decreasing the pump efficiency. Excessive backpressure will increase the
amount of head the down-hole pump will have to provide. All of these factors increase the expense of
producing a barrel of oil. You should always ask yourself if the potential increase in operating expenses is
justified by the lower initial investment.
Unfortunately, thousands of wells have been drilled and completed without using the Total Pumping System
concept. A hole was drilled, casing ran, and the well completed as soon as possible with the lowest initial
investment. Stimulations are performed without considering how they may affect the cost to produce a
barrel of oil. Economic analyses usually do not take in any affects to artificial lift. May times the surface
equipment is designed considering the initial cost of a project but not the affects to well production. What
we must realize is that the most wells will be produced with artificial lift for the majority of their lives.
There is an old saying, “Anyone who lives in a glass house should not cast stones”. This applies to pump
designers. The wisdom of individuals who design drilling procedures, stimulations, and surface facilities
has been questioned. It has been implied they do not use a Total Pumping System concept and look
primarily at initial investment and do not think of operating expenses. It is regrettable that the same
accusations can be applied to pump designers.
Many pump designers consider only one factor, increasing lift volumes. Many individuals assume that if
the lift volume were increased, the oil volume would increase. The well’s actual inflow performance is not
taken into account. Often we will run what was pulled out of the hole without analyzing for proper sizing.
We at times assume it is better to repair what we have instead of purchasing new equipment. When
designing an artificial lift system all the factors should be analyzed for a successful installation.
38
XII. Total Pumping System
Problem #8
Given the following:
Datum: 1700 feet
BOPD: 400
Ground Elevation: 3500 feet
Oil API: 34.5
KB: 11 feet
BWPD: 1229
Perforation Depth: 5160 feet
SGW: 1.01
Pump Depth: 4900 feet
Total Gas: 853 MSCF
Pumping FL: 4500 feet
CO2 Percent: 70
Static FL: 50 feet
Bo: 1.204
Pumping CP: 500 psi
OSF: 1.0
Static CP: 600 psi
WCO: 1229
Bw: 1.04
FHC: 56,000
Bg: 3.093
FCO: 452,078
Bg: 2.68
Solve for:

SBHP at Datum

PBHP at Datum

Pressure Draw Down

PI
o Qmax
o Plot PI Relationship
o Q if PBHP = 1400 psi

IPR
o Qmax
o Plot the IPR Relationship
o Q if PBHP = 1400 psi

Choose Which Relationship is the Best (PI or IPR)

Reservoir Barrels from Well Test
39
XIII. Glossary of Terms
Average Pressure (Pbar): The average pressure in a bounded reservoir as determined by a build up analysis.
Barrels of Oil Per Day (BOPD): The barrels of oil that is produced in a 24-hour period.
Barrels of Water Per Day (BWPD): The barrels of water that is produced in a 24-hour period.
Bottom Hole Pressure (BHP): A pressure measured at a certain depth in a reservoir. This pressure is at the
face of the well bore.
Bottom Hole Pressure Depth (BHPD): The depth that the bottom-hole pressure is measured at.
Bubble Point (Pb): The pressure, at reservoir temperature, that the first bubble of gas is liberated from the
liquid phase. Also known as the saturation pressure.
Combination Curve: As the name implies, this is a combination of the PI and IPR relationships. The PI
relationship is used at pressures above the reservoir bubble point while the IPR relationship is used at
pressures below the reservoir bubble point.
Datum: A depth within a reservoir, which is measured from sea level and therefore is not dependent on
ground level. This gives a consistent or “level” plane within the reservoir to refer to. The value of a datum
is a negative number since the measurement is below sea level. This term is used more by reservoir
engineers than production people.
Datum Depth: This is calculated by adding the ground level elevation or kelly bushing elevation to the
datum. It does not matter if GL or KB elevations are used, just as long as you are consistent. It is preferred
to use the elevation that is consistent with logging measurements.
Drive mechanism: Defined as the original energy within the reservoir that “pushes” the oil, water, and/or gas
to the well bore and up the tubing.
External Pressure (Pe): The pressure at the external boundary of the reservoir.
Flowing Bottom Hole Pressure (Pwf ): The stabilized bottom-hole pressure during a producing period when
the well is flowing.
Fluid Gradient: A value that is related to the weight of the fluid. It is a measurement of the force in pounds
per square inch (psi) that one vertical foot of the fluid would apply. Therefore its value is psi/ft.
Gas Formation Volume Factor (Bg): The volume in barrels that one standard cubic foot of gas will occupy
as free gas in the reservoir. Units: rb / mscf gas.
Ground Level (GL): The elevation above sea level.
Inflow Performance Relationship (IPR): This relationship applies to compressible well fluids, such as oil
and gas. Used normally if the oil cut or gas rate is not low.
Initial Pressure (Pi): This is the pressure contained within a reservoir before any production begins.
Kelly Bushing Height (KB): The height of the drilling floor above the ground level. Much of well bore
depth measurements are taken from the Kelly Bushing. The Kelly Bushing Elevation is calculated by
adding the ground level to the kelly bushing height.
Natural depletion: The reduction in reservoir energy as a well is produced.
Oil Cut (OC) or Percent Oil (% Oil): The oil cut is the ratio of oil to total liquids, oil plus water.
Oil Formation Volume Factor (Bo): The volume in barrels occupied in the reservoir by one stock tank barrel
of oil plus its dissolved gas. Units: rb / stb oil.
P star (P*): The theoretical static bottom-hole pressure that would be obtained at an infinite shut in time.
40
XIII. Glossary of Terms
Permeability: A property of the porous medium and is a measure of the capacity of the medium to transmit
fluids. In other words, the permeability of a formation is a measure of the ease with which fluids will flow
through the particular formation.
Porosity: Defined as the ratio of the void space in a rock to the bulk volume of that rock multiplied by 100
to express in percent (%). Also known as the fluid filled volume of a rock divided by the total volume of
the rock multiplied by 100. Otherwise stated it is a measure of the space available for the storage of oil,
water, and gas.
Pressure Draw Down (P): Defined as the difference between the static bottom-hole pressure and the
pumping bottom-hole pressure.
Primary recovery: All the reservoir’s early production, prior to the addition of injection wells and energy to
the reservoir.
Producing Bottom Hole Pressure: Defined as the stabilized bottom-hole pressure during a producing
period.
Producing Casing Pressure (CPP): The measurement of the pressure on the casing during a producing
period. Its value is in psi.
Productivity Index (PI): This relationship applies to incompressible well fluids, such as water. Used
normally if the oil cut and gas rate is low.
Pumping Bottom Hole Pressure (PBHP): The stabilized bottom-hole pressure during a producing period
when the well is being produced via artificial lift, such as sucker rod or submersible pumps.
Pump Intake Depth (PID): The actual depth the bottom of the pump is set in the well bore. The pump
intake depth is used for pump intake pressure and total dynamic head calculations.
Pump Intake Pressure (PIP): The stabilized bottom-hole pressure during a producing period that is
calculated at the actual pump intake depth.
PVT (Pressure – Volume – Temperature) Data: Basically information about any type of fluid that predicts
how the volume of that fluid will change as the pressure and/or temperature of the fluid is altered.
Qmax: Defined as the maximum rate at which a well will produce.
Saturation: The fraction of the void volume or porosity that is filled with a given fluid.
Secondary recovery: The additional oil recovered during the water flood process.
Solution Gas-Oil Ratio (Rs): The number of standard cubic feet of gas that will dissolve into one stock tank
barrel of oil when both are taken down to the reservoir at the prevailing reservoir pressure and temperature.
Units: scf gas / stb oil.
Specific Gravity (SG): A dimensionless value that compares all liquids to fresh water and all gases to air.
Static Bottom Hole Pressure (Pws or SBHP): The pressure within the well bore at formation depth that is
obtained when the well is shut in. This pressure is time dependent, and although the required time for a
good reading varies from field to field, a 36-hour shut in is usually sufficient.
Tertiary recovery: To recover more oil other methods are turned to such as polymer, steam, or CO2
flooding. The oil produced from these methods is called tertiary recovery.
41
XIII. Glossary of Terms
Tubing Intake Depth (TID): The depth at which well fluids enter the tubing string. At times the pump
intake and tubing intake depths are the same. In some cases there is a shroud or dip tube installed in a well
to enhance gas separation. The bottom of the shroud or dip tube is equal to the tubing intake depth. The
tubing intake depth is used in pumping bottom-hole pressures.
Water Formation Volume Factor (Bw): The volume in barrels occupied in the reservoir by one stock tank
barrel of water plus its dissolved gas. Units: rb / stb oil.
Well Potential: A measurement or relationship that represents a well’s ability to give up fluids, or to
produce.
42
XIV. Formulas

Oil Cut (page #8):
OC  BOPD  (BOPD  BWPD) (Equation 4.1)

Oil Specific Gravity (page #8):
Oil SG  141.5  (131.5  API) (Equation 4.2)

Mixture Specific Gravity (page #8):
SGM  Oil SG  OC   Water SG  1  OC (Equation 4.3)

Gradients (page #9):
o Oil:
OG  SGO  0.433 (psi/ft) (Equation 4.4)
o Water:
WG  SGW  0.433 (psi/ft) (Equation 4.5)
o Mixed:
MG  SGM  0.433 (psi/ft) (Equation 4.7)

Fluid Above the Pump (page #10):
FAP  PD  FL (Equation 4.8)

Pumping Bottom Hole Pressure with No Tailpipe (pages #13 & 14):
o Below Pump Depth:
PBHP  CPP  OG  AFAP  MG  BHPD  PD (Equation 4.11)
o Above Pump Depth:
PBHP  CPP  OG  BHPD  AFL (Equation 4.14)
o At Pump Depth:
PIP  CPP  OG  AFAP (Equation 4.16)

Pumping Bottom Hole Pressure with Tailpipe (page #14):
o Below Producing Interval:
PBHP  CPP  OG  (TOP  AFL  MG  BHPD  TOP (Equation 4.18)
o Above or At Producing Interval:
PBHP  CPP  OG  (BHPD  AFL (Equation 4.19)
43
XIV. Formulas

Static Bottom Hole Pressure (page #18):
SBHP  MG  BHPD  PD  OG  PD PFL  MG  PFL  SFL)  GG  SFL  SCP (Equation 5.1)

Pressure Draw Down (page #22):
P  SBHP  PBHP (Equation 7.1)

Productivity Index or PI (pages #23 & 24):
PI  Q  (SBHP  PBHP (Equation 8.1)
Q  PI  (SBHP  PBHP (Equation 8.2)
PBHP  SBHP  (Q  PI (Equation 8.3)
Qmax  PI  SBHP (Equation 8.4)

Inflow Performance Relationship or IPR (page #24):
QQmax  1  0.2  PBHP  SBHP  0.8  PBHP  SBHP2 (Equation 8.5)
Qmax  Q  QQmax (Equation 8.6)
Q  Qmax  QQmax (Equation 8.7)

Reservoir Barrels with no CO2 (page #30):
RB  STBO  Bo  GOR  Rs  STBO  Bg  1000  STBW (Equation 9.2)

Reservoir Barrels with CO2 (page #30):
RB  STBO  Bo  OSF  WCO  Bw  WU  FHC  1000  Bg  FCO  1000  Bg
44
XV. Problem Solutions
Problem #1 (page #8):
Well A
Well B
Well C
1700’
1700’
1700’
+ GL
3700’
3603’
3656’
= Datum Depth
5400’
5303’
5356’
Datum
or
Well A
Well B
Well C
1700’
1700’
1700’
+ GL
3700’
3603’
3656’
+ KB
11’
11’
11’
5411’
5314’
5367’
Datum
= Datum Depth
45
XV. Problem Solutions
Problem #2 (page #9):
Oil Gradient:
Oil SG  141.5  (131.5  API)
Oil SG = 141.5  (131.5  33)
Oil SG = 0.860
OG  SGO  0.433
OG  0.860  0.433
OG = 0.372 psi/ft
Water Gradient:
WG  SGW  0.433
WG  1.125  0.433
WG = 0.487 psi/ft
Mixed Gradient:
OC  BOPD  (BOPD  BWPD)
OC  275  (275  561)
OC = 0.33
SGM  Oil SG  OC   Water SG  1  OC
SGM  0.860  0.33   1.125  1  0.33
SGM = 1.038
MG  SGM  0.433
MG  1.038  0.433
MG = 0.449 psi/ft
46
XV. Problem Solutions
Problem #3 (page #14):
Oil Cut:
OC  BOPD  (BOPD  BWPD)  275  (275  561)
OC = 0.33
Oil Specific Gravity:
Oil SG  141.5  (131.5  API) = 141.5  (131.5  33)
Oil SG = 0.860
Oil Gradient:
OG  SGO  0.433  0.860  0.433
OG = 0.372 psi/ft
Mix Specific Gravity:
SGM  Oil SG  OC   Water SG  1  OC  0.860  0.33   1.125  1  0.33
SGM = 1.038
Mix Gradient:
MG  SGM  0.433  1.038  0.433
MG = 0.449 psi/ft
Pump Intake Pressure (oil above pump):
PIP  CPP  OG  AFAP
PIP  25  0.372  1000
PIP = 397 psi
Pump Intake Pressure (mix above pump):
PIP  CPP  MG  AFAP
PIP  25  0.449  1000
PIP = 474 psi
Pumping Bottom Hole Pressure (at perforations):
PBHP  CPP  OG  AFAP  MG  BHPD  PD
PBHP  25  0.372  1000  0.449  5160  4900
PBHP = 514 psi
47
XV. Problem Solutions
Problem #4 (page #18):
Oil Cut:
OC  BOPD  (BOPD  BWPD)  250  (250  761)
OC = 0.25
Oil Specific Gravity:
Oil SG  141.5  (131.5  API) = 141.5  (131.5  34.5)
Oil SG = 0.852
Oil Gradient:
OG  SGO  0.433  0.852  0.433
OG = 0.369 psi/ft
Mix Specific Gravity:
SGM  Oil SG  OC   Water SG  1  OC  0.852  0.25   1.01  1  0.25
SGM = 0.971
Mix Gradient:
MG  SGM  0.433  0.971  0.433
MG = 0.420 psi/ft
Static Bottom Hole Pressure:
SBHP  MG  BHPD  PD  OG  PD PFL  MG  PFL  SFL)  GG  SFL  SCP
SBHP  0.420  5160  4900  0.369  4900 4500  0.420  4500  1250)  0  150
SBHP = 109.2 + 147.6 + 1365 + 150
SBHP = 1,772 psi
48
XV. Problem Solutions
Problem #5 (page #21):
True Vertical Depth:
Diagram:
2000’
z
4000’
40
z  Cosine 40  4000  0.766  4000 = 3064’
TVD  2000  3064
TVD  5064 ft
Pump Intake Pressure:
Diagram:
2000’
SFL: 4500’
z
40
PD: 5500’
Measured Fluid Above the Pump:
FAP  5500 – 4500
FAP  1000 ft
True Fluid Above the Pump:
FAP  Cosine 40  1000  0.766  1000
FAP  766 ft
Pump Intake Pressure:
PIP  CPP  OG  AFAP = 0  0.433  766  0.433  766
PIP  332 psi
If we did not make the correction then:
PIP = 1000  0.433 = 433 psi or a 30% error
49
XV. Problem Solutions
Problem #6 (page #24):
Productivity Index (PI):
PI  Q  (SBHP  PBHP
PI  800  (3000  1400
PI  0.50 bbl/psi
Maximum Rate (Qmax):
Qmax  PI  SBHP
Qmax  0.50  3000
Qmax  1500 BPD
The Plot:
3000
2000
Pressure
1000
0
200
400
600
800
1000
Rate
1200
1400
1600
Rate at 800 PBHP:
Q  PI  (SBHP  PBHP
Q  0.50  (3000  800
Q  1,100 BPD
50
XV. Problem Solutions
Problem #7 (page #25):
IPR Curve:
PBHP/SBHP  1400  3000  0.467
From Vogel’s Curve: (Q/Qm) = 0.73
Or
QQmax  1  0.2  PBHP  SBHP  0.8  PBHP  SBHP2
QQmax  1  0.2  1400  3000  0.8  1400  30002
QQmax  0.732
Qmax  Q  QQmax  800  0.732
Qmax  1093 BPD (1500 using PI)
Points for Plotting so Far:
BPD
PBHP
1,093
0
800
1,400
0
3,000
More Points:
PBHP PBHP/SBHP Q/Qmax Rate (Q)
2500
0.833
0.278
304
2000
0.667
0.511
556
1000
0.333
0.844
923
51
XV. Problem Solutions
The Plot:
3000
2000
Pressure
1000
0
200
100
300
400
500
600
700
800
900
1000
1100
Rate
Q for PBHP of 800 psi:
From Plot:
Q = 978 BPD
From Equation:
QQmax  1  0.2  PBHP  SBHP  0.8  PBHP  SBHP2
QQmax  1  0.2  800  3000  0.8  800  30002
QQmax  0.890
Q  Qmax  QQmax
Q  1,093  0.890
Q  973
(1,100 BPD with PI)
52
XV. Problem Solutions
Problem #8 (page #39):

SBHP at Datum:
Datum Plane  Datum  GL  KB  1700  3500  11
Datum Plane = 5211 ft
Oil Cut:
OC  BOPD  (BOPD  BWPD)  400  (400  1229)
OC = 0.246
Oil Specific Gravity:
Oil SG  141.5  (131.5  API) = 141.5  (131.5  34.5)
Oil SG = 0.852
Oil Gradient:
OG  SGO  0.433  0.852  0.433
OG = 0.369 psi/ft
Mix Specific Gravity:
SGM  Oil SG  OC   Water SG  1  OC  0.852  0.246   1.01  1  0.246
SGM = 0.971
Mix Gradient:
MG  SGM  0.433  0.971  0.433
MG = 0.420 psi/ft
Static Bottom Hole Pressure:
SBHP  MG  BHPD  PD  OG  PD PFL  MG  PFL  SFL)  GG  SFL  SCP
SBHP  0.420  5211  4900  0.369  4900 4500  0.420  4500  50)  0  600
SBHP = 130.6 + 147.6 + 1869 + 600
SBHP = 2,747 psi

PBHP at Datum:
PBHP  CPP  OG  AFAP  MG  BHPD  PD
PBHP  500  0.369  (4900 - 4500  0.420  5211  4900
PBHP = 778 psi
53
XV. Problem Solutions

Pressure Draw Down:
P  SBHP  PBHP
P  2,747  778
P  1969 psi

Productivity Index (PI):
PI  Q  (SBHP  PBHP
PI  1629  (2747  778
PI  0.827 bbl/psi
Qmax  PI  SBHP
Qmax  0.827  2747
Qmax  2,272 BPD
The Plot:
3000
2000
Pressure
1000
0
250
500
750
1000
1250
Rate
1500
1750
2000
Rate at 1400 PBHP:
Q  PI  (SBHP  PBHP
Q  0.827  (2747  1400
Q  1,114 BPD
54
XV. Problem Solutions

IPR:
PBHP/SBHP  778  2747  0.283
QQmax  1  0.2  PBHP  SBHP  0.8  PBHP  SBHP2
QQmax  1  0.2  0.283  0.8  0.2832
QQmax  0.879
Qmax  Q  QQmax  1629  0.879
Qmax  1,853 BPD
Points for Plotting:
PBHP PBHP/SBHP Q/Qmax Rate (Q)
0
-
-
1853
778
-
-
1629
2747
-
-
0
1000
0.364
0.821
1522
1500
0.546
0.652
1209
2000
0.728
0.430
797
2500
0.910
0.156
289
The Plot:
3000
2000
Pressure
1000
0
200
400
600
800
1000
1200
1400
1600
1800
2000
Rate
55
XV. Problem Solutions
Rate at 1400 PBHP:
QQmax  1  0.2  PBHP  SBHP  0.8  PBHP  SBHP2
QQmax  1  0.2  1400  2747  0.8  1400  27472
QQmax  0.690
Q  Qmax  QQmax
Q  1,853  0.690
Q  1279 BPD

PI or IPR
Oil percent is fairly high: 24.6%
High CO2: 70%
IPR

Actual Pump Barrels:
RB  STBO  Bo  OSF  WCO  Bw  WU  FHC  1000  Bg  FCO  1000  Bg
RB  400  1.204  1.0  1229  1.04  0  56,000  1000  3.093  452,078  1000  2.68
RB  481.6  1278.16  0  173.2  1211.6
RB  3145
56
The Well Bore
Section
Title
Page
I
Basic History of A Reservoir _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
1
II
Reservoir Properties _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
3
III
Reservoir Drive Mechanisms _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
4
IV
Pumping Bottom Hole Pressure _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
7
V
Static Bottom Hole Pressure _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
15
VI
True Vertical Depth _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
19
VII
Differential Pressure or Pressure Draw Down _ _ _ _ _ _ _ _ _ _ _
22
VIII
Well Potential _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
23
IX
Reservoir Barrels and PVT Data _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
28
X
Well Bore Completions _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
31
XI
EOR Processes _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
34
XII
Total Pumping System _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
37
XIII
Glossary of Terms _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
40
XIV
Formulas _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
43
XV
Problem Solutions _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
45
i