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.

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).

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.

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

E2E1 E1

E4E3 E3

E4

+ EL

E3 E3

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.

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

E4

+ EL

E3 E3EI EI

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.

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.

Magnified Many Times

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

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.

b. Natural Water Drive

Oil

OWC

Gas

GOR

Pressure

Water Cut

Pi

Time

Typical Gas-Cap Drive Production History

4

III. Reservoir Drive Mechanisms

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.

Typical Natural Water DriveProduction 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

d. Solution Gas Drive

Oil

Water

Pi

Time

Pressure

WOR

GOR

A PressureWOR

GOR

B

Time

5

III. Reservoir Drive Mechanisms

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.

Typical Solution Gas DriveProduction History

Time

Pi Pb

Water Cut

Pressure

GOR

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.

Datum

GL

Sea Level

AC

B

7

IV. Pumping Bottom Hole Pressure

Problem #1Calculate the datum depth for each well.

Datum: -1700 feet Kelly Bushing: 11 feetGround Elevations:

Well A: 3700 feetWell B: 3603 feetWell 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 #2Calculate the gradient for oil, water, and the oil / water mixture given the following:

BOPD: 275 BWPD: 561Oil 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.

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.

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

Producing Casing Pressure

Producing Interval

Pump Depth (PD)

Fluid Above the Pump (FAP)

Actual Fluid Above the Pump (AFAP)

10

IV. Pumping Bottom Hole Pressure

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

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.

Well with the Pump or Tailpipe set Below the Producing Interval

Producing Casing Pressure

Bottom Hole Pressure Depth (BHPD)

Pump Depth (PD)

Actual Fluid Above the Pump (AFAP)

Gas

Oil & Water

Oil

11

IV. Pumping Bottom Hole Pressure

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.

D. Formulas for calculating the PBHP from fluid levels.1. Well with the Pump set Above the Producing Interval

Producing Casing Pressure

Bottom Hole Pressure Depth (BHPD)Intake or Pump Depth

Actual Fluid Above the Pump (AFAP)

Gas

Oil & Water

Oil

Producing Interval

12

IV. Pumping Bottom Hole Pressure

Bottom Hole Pressure Depth below the Pump Depth:PBHP CPP GG AFL OG AFAP MG BHPD PD (Equation 4.10)

PBHP: Producing Bottom Hole PressureGG: Gas GradientAFL: Actual Fluid Level (AFL = PD – AFAP)OG: Oil GradientAFAP: Actual Fluid Above the PumpMG: Mixed GradientBHPD: Bottom Hole Pressure DepthPD: 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)

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)

13

IV. Pumping Bottom Hole Pressure

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 IntervalPBHP CPP OG (TOP AFL MG BHPD TOP (Equation 4.18)

TOP: Top Of Producing Interval

Bottom Hole Pressure Depth above or equal to Producing IntervalPBHP 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 #3Calculate 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 psiPerfs: 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.

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.

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

P*1 P*2 P*3 P*4

15

V. Static Bottom Hole Pressure

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.

D. P* vs. SBHPa. 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.

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.

Cell 1 Cell 2A

Pressure

Distance from Well bore

16

V. Static Bottom Hole Pressure

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.

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.

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

Shut-In Casing Pressure (SCP)

Static Fluid Level (SFL)

Producing Fluid Level (PFL)

Pump Depth (PD)

Bottom Hole Pressure Depth (BHPD)

17

V. Static Bottom Hole Pressure

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 #4Calculate 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. 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. 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.

C. Determining True Vertical Depth (TVD)

A

y

z

x B

A

w

dC

zy

x B

19

VI. True Vertical Depth

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 depthAngle of deviationKick-off depthThe law of cosines: Cosine A adjacenthypotenuse or

Cosine d zy orz Cosine d y (Equation 6.1)

i. Example:a. Measured Depth: 5200’

Angle of Deviation: 5 degreesKick-off Depth: 2000’

b. Diagram

c. z Cosine 5 3200z 3188’

d. TVD 2000 3188 5188’ii. This calculation applies to any point along the hole, not just the bottom.

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

2000’

5z

3200’

20

VI. True Vertical Depth

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:

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 psiHole 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 #5Assume:

Measured Depth: 6000 ftAngle of Deviation: 40 (Cosine 40 0.766)Kick-off Point: 2000 ftAdjusted Fluid Level: 4500 ftPump Depth: 5500 ftFluid Gradient: 0.433 psi/ft

Calculate:TVD of the Well BorePump Intake Pressure

Well Bore A Well Bore B5000’ 8000’

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.

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.

PBHP PS SBHPFlow

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.

Pressure (PSI)

Rate (BPD) Qmax0

0

SBHP

PI Relationship

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 BPDSBHP: 3000 psiPBHP: 1400 psi

Calculate:1. PI2. Qmax

3. Plot the PI relationship4. 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:QQmax 1 0.2 PBHP SBHP 0.8 PBHP SBHP2 (Equation 8.5)

In this equation Q is the rate obtained at the PBHP used in the calculations. Once the term QQmax is determined, Qmax can be calculated by:

Qmax Q QQmax (Equation 8.6)Now a rate can be calculated for any given PBHP by:

Q Qmax QQmax (Equation 8.7)Realize the term QQmax 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.

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). (PPs on the graph.)2. Enter into the graph and find the corresponding value of QQmax (qqm 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 #7With the following data: Calculate and/or Plot:

Q: 800 BPD IPR Curve (Use PBHP values of 2500, 2000 and 1000 psi)SBHP: 3000 psi From curve find Q for PHBP of 800 psiPBHP: 1400 psi Use equations to find Q for PBHP of 800 psi

Pressure (PSI)

Rate (BPD) Qmax0

0

SBHP

IPR Relationship

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.

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.

PIIPR

Comb.

Pressure

Rate

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.

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 gasN = Number of Pound MolesR = Universal Gas ConstantT = 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.

E. Definition of terms:

OilGasWater

Solution & Free Gas

Stock Tank Oil & Water

28

IX. Reservoir Barrels and PVT Data

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.

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.

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.

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.

F. Determining Reservoir Barrelsa. Stock tank barrels can be converted to reservoir barrels by the following equation:

100

700

500

300RS

1000 3000 40002000Pb

Pressure

1.0

1.3

1.2

1.1Bo

1000 3000 40002000Pb

Pressure

.02

.08

.06

.04

Bg

1000 3000 40002000Pb

Pressure

29

IX. Reservoir Barrels and PVT Data

RB STBO Bo GOR Rs STBO Bg 1000 STBW (Equation 9.2) Where:

STBO: Stock Tank Barrels of OilGOR: Gas-Oil RatioSTBW: 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 FactorWCO: STBW affected by CO2

WU: STBW unaffected by CO2

FHC: Free Hydrocarbon Gas in MSCFFCO: Free CO2 Gas in MSCFBg: 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 Horizontala. 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.

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.

OIL

PRODUCTION

TIME

Primary Oil

Secondary Oil

Tertiary Oil

34

XI. EOR Processes

EOR OR TERTIARY 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:

Water Flooding with Formation of Surfactant in the Reservoir

Water Flooding withThickened Water

Injection ofMicellar Solutions

Water flooding with Reduced Interfacial Tension

Hot WaterFlooding

Steam Stimulation(Huff-n-Puff)

SteamFlooding

In Situ CombustionWith Water Injection

In SituCombustion

CO2 Stimulation(Huff-n-Puff)

CO2 Immiscible Flooding Alternate Injection of CO2 and Water

CO2 MiscibleFlooding

CO2 Miscible Flooding Alternate Injection of CO2 and Water

N2 Miscible Flooding Alternate Injection of N2 and Water

High PressureGas Drive

EnrichedGas Drive

Injection of an LPG SlugFollowed by Gas

Alternate Injection ofNatural Gas and Water

Water

Alkali

Polymers

Surfactants + Alcohol + Crude Oil

Low ConcentrationSurfactants

Chemicals

Heat

Air

Carbon Dioxide

Nitrogen

Gases

Natural Gas

35

XI. EOR Processes

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 depths8. 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: 400Ground Elevation: 3500 feet Oil API: 34.5KB: 11 feet BWPD: 1229Perforation Depth: 5160 feet SGW: 1.01Pump Depth: 4900 feet Total Gas: 853 MSCFPumping FL: 4500 feet CO2 Percent: 70Static FL: 50 feet Bo: 1.204Pumping CP: 500 psi OSF: 1.0Static CP: 600 psi WCO: 1229Bw: 1.04 FHC: 56,000Bg: 3.093 FCO: 452,078Bg: 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

IPRo 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) Static Bottom Hole Pressure (page #18):

43

XIV. Formulas

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):QQmax 1 0.2 PBHP SBHP 0.8 PBHP SBHP2 (Equation 8.5)Qmax Q QQmax (Equation 8.6)Q Qmax QQmax (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

Datum 1700’ 1700’ 1700’+ GL 3700’ 3603’ 3656’= Datum Depth 5400’ 5303’ 5356’

or

Well A Well B Well C Datum 1700’ 1700’ 1700’+ GL 3700’ 3603’ 3656’+ KB 11’ 11’ 11’= Datum Depth 5411’ 5314’ 5367’

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 0.433OG 0.860 0.433OG = 0.372 psi/ft

Water Gradient:WG SGW 0.433WG 1.125 0.433WG = 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 0.33SGM = 1.038

MG SGM 0.433MG 1.038 0.433MG = 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 0.433OG = 0.372 psi/ft

Mix Specific Gravity:SGM Oil SG OC Water SG 1 OC 0.860 0.33 1.125 1 0.33SGM = 1.038

Mix Gradient:MG SGM 0.433 1.038 0.433MG = 0.449 psi/ft

Pump Intake Pressure (oil above pump):PIP CPP OG AFAP PIP 25 0.372 1000PIP = 397 psi

Pump Intake Pressure (mix above pump):PIP CPP MG AFAP PIP 25 0.449 1000PIP = 474 psi

Pumping Bottom Hole Pressure (at perforations):PBHP CPP OG AFAP MG BHPD PD

PBHP 25 0.372 1000 0.449 5160 4900PBHP = 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 0.433OG = 0.369 psi/ft

Mix Specific Gravity:SGM Oil SG OC Water SG 1 OC 0.852 0.25 1.01 1 0.25SGM = 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 + 150SBHP = 1,772 psi

48

XV. Problem Solutions

Problem #5 (page #21):True Vertical Depth:

Diagram:

z Cosine 40 4000 0.766 4000 = 3064’TVD 2000 3064 TVD 5064 ft

Pump Intake Pressure:Diagram:

Measured Fluid Above the Pump:FAP 5500 – 4500FAP 1000 ft

True Fluid Above the Pump:FAP Cosine 40 1000 0.766 1000FAP 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

Problem #6 (page #24):

2000’

40z

4000’

2000’

40zSFL: 4500’

PD: 5500’

49

XV. Problem Solutions

Productivity Index (PI):PI Q (SBHP PBHP

PI 800 (3000 1400PI 0.50 bbl/psi

Maximum Rate (Qmax):Qmax PI SBHPQmax 0.50 3000Qmax 1500 BPD

The Plot:

Rate at 800 PBHP:Q PI (SBHP PBHP

Q 0.50 (3000 800Q 1,100 BPD

0

1000

2000

3000

200 400 600 800 1000 1200 1400 1600

Pressure

Rate

50

XV. Problem Solutions

Problem #7 (page #25):IPR Curve:

PBHP/SBHP 1400 3000 0.467

From Vogel’s Curve: (Q/Qm) = 0.73 OrQQmax 1 0.2 PBHP SBHP 0.8 PBHP SBHP2

QQmax 1 0.2 1400 3000 0.8 1400 30002

QQmax 0.732

Qmax Q QQmax 800 0.732Qmax 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:

Q for PBHP of 800 psi:

From Plot:Q = 978 BPD

From Equation:QQmax 1 0.2 PBHP SBHP 0.8 PBHP SBHP2

QQmax 1 0.2 800 3000 0.8 800 30002

QQmax 0.890

Q Qmax QQmax

Q 1,093 0.890Q 973 (1,100 BPD with PI)

0

1000

2000

3000

100 200 300 400 500 600 700 800

Pressure

Rate900 1000 1100

52

XV. Problem Solutions

Problem #8 (page #39): SBHP at Datum:

Datum Plane Datum GL KB 1700 3500 11Datum 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 0.433OG = 0.369 psi/ft

Mix Specific Gravity:SGM Oil SG OC Water SG 1 OC 0.852 0.246 1.01 1 0.246SGM = 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 + 600SBHP = 2,747 psi

PBHP at Datum:PBHP CPP OG AFAP MG BHPD PD

PBHP 500 0.369 (4900 - 4500 0.420 5211 4900PBHP = 778 psi

53

XV. Problem Solutions

Pressure Draw Down:P SBHP PBHPP 2,747 778

P 1969 psi

Productivity Index (PI):PI Q (SBHP PBHP

PI 1629 (2747 778PI 0.827 bbl/psi

Qmax PI SBHPQmax 0.827 2747

Qmax 2,272 BPD

The Plot:

Rate at 1400 PBHP:Q PI (SBHP PBHP

Q 0.827 (2747 1400Q 1,114 BPD

0

1000

2000

3000

250 500 7501000

1250 1500 1750 2000

Pressure

Rate

54

XV. Problem Solutions

IPR:PBHP/SBHP 778 2747 0.283QQmax 1 0.2 PBHP SBHP 0.8 PBHP SBHP2

QQmax 1 0.2 0.283 0.8 0.2832

QQmax 0.879

Qmax Q QQmax 1629 0.879Qmax 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:

Rate at 1400 PBHP:

0

1000

2000

3000

200 400 600 800 1000 1200 1400 1600

Pressure

Rate1800 2000

55

XV. Problem Solutions

QQmax 1 0.2 PBHP SBHP 0.8 PBHP SBHP2

QQmax 1 0.2 1400 2747 0.8 1400 27472

QQmax 0.690

Q Qmax QQmax

Q 1,853 0.690Q 1279 BPD

PI or IPROil 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 1211.6RB 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