Reservoir Material Balance COPYRIGHTcloud1.activelearner.com/contentcloud/portals/... · initial oil in place (or gas in place) can be calculated once production data ~ ~ A ~ ~ q

Reservoir Material Balance Core

Material Balance Overview

Why This Module Is Important

One of the most useful piecesof information about oil andgas reservoirs is the size• How much hydrocarbons are

present in the reservoir?

The determination ofhydrocarbons in place candetermine future developmentstrategies

The material balance methodis superior to volumetricanalysis because it includesdynamic data

Reservoir Material Balance Core ═════════════════════════════════════════════════════════════════════════

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Unlike the volumetric analysis method, the material balancemethod uses data which is readily available from the field

Unlike decline curve analysis, material balance analysis is notdependent on changes in the field and operating conditions

Amount ofmass originally

present

Amountof mass

in

Amount of mass

out

Amount ofmass currently

present+ – =

The material balance method can provide a useful anchor pointof initial hydrocarbons in place, even for operators using thereservoir simulation method


Situations where we should not use the material balance method:

When reservoir pressure

measurements are highly unreliable

When the field has just started production, and a very limited amount of production data is

available

When the reservoir permeability is very

low, and the transient flow conditions prevail

for a long time

When significant uncertainty exists with respect to the type of

mechanisms influencing the production



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Learning Objectives

By the end of this lesson, you will be able to:This section will cover the following learning objectives:

Describe the purpose of the material balance technique toestimate the initial hydrocarbons in place

Differentiate between volumetric analysis and material balancetechnique

State the basic principle of material balance analysis

Why Material Balance?

Material balance is a method by which you can calculate the

original hydrocarbons in place in a given

reservoir

The calculation of original

hydrocarbons in place is

important to understand the

size of the reservoir

Hydrocarbons in place is one of

the main contributing factors to

determine how much

hydrocarbons will be

recovered from the reservoir

Material balance is popular

because it uses data which are easy to collect and normally

available



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Principles

The basic principle in material balance is to relate change in the pressure of the

reservoir to produced hydrocarbons so that original hydrocarbons can be estimated.

The relationship between the pressure and the produced

hydrocarbon is not as straight forward and depends on how the hydrocarbons are

produced.

The reservoir hydrocarbons can be produced by different mechanisms. Some

mechanisms are more efficient than the

others. Let us discuss each of these mechanisms.



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Drive Mechanisms for Hydrocarbon Production

Drive Mechanisms Flow

Primary Drive Mechanisms

• Reservoir uses its own energy to produce hydrocarbons.

Secondary Drive Mechanisms

• An external force is used to produce hydrocarbons. Typically, the external force comes from water injection.

Tertiary Drive Mechanisms

• An external force is used to produce hydrocarbons. The external force comes from fluids other than water. An example would be CO2injection, steam injection, polymer injection, etc.



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Volumetric Analysis and Material Balance

Bothtechniques provide a methodology to

determine the initial hydrocarbons in

place

Assumesthat reservoir

boundaries canbe correctly definedso that the volume contained withinthose boundariescan be calculated

Uses a proxy tomeasure depletion

in the reservoir as a function of produced hydrocarbons, and

estimates how much hydrocarbons were

there in thefirst place

VolumetricAnalysis

MaterialBalance

Material Balance Analogy



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Learning Objectives

You are now able to:This section has covered the following learning objectives:

Describe the purpose of the material balance technique toestimate the initial hydrocarbons in place

Differentiate between volumetric analysis and material balancetechnique

State the basic principle of material balance analysis



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Drive Mechanisms


Learning Objectives

By the end of this lesson, you will be able to:

Describe the driving force for producing oil and gas from thereservoir

List and explain the important primary reservoir mechanisms

Realize the need for additional drive mechanisms to recoveradditional hydrocarbons

Recall the principles of secondary and tertiary oil recoveryprocesses and explain why they recover additional oil beyondprimary recovery mechanisms

This section will cover the following learning objectives:



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Drive Mechanisms

Solution gas drive• The gas dissolved in oil

comes out of oil andexpands pushing the oilout of the reservoir

Oil Zone

Water

Liberated Gas

Drive Mechanisms

Gas cap drive• The free gas in the

reservoir expands andpushes the hydrocarbonsout

Original GOC

Original WOC

PrimaryGas Cap

ExpandedGas Cap

Water

Liberated Gas



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Drive Mechanisms

Water (aquifer) drive• The underlying aquifer

pushes the hydrocarbonsto the surface

Original WOC

Oil Zone

Water-Invaded Zone

Water

Liberated Gas



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Primary Drive Mechanisms

This is the overall picture of all the different primary drive mechanisms which are present in the reservoir. Expansion drive, water drive, and compaction drive, so expansion is either gas which is dissolved in oil and expanding or a gas cap drive, or sometimes it is just a gas drive when you have a single-phase gas which is present in the reservoir. The water drive is partial, again, coming from the underneath aquifer or it is so strong that it provides the entire mechanism of producing oil. The compaction drive is, again, very rare, but for some oil reservoirs it can be an important mechanism by which oil can be produced.

Compaction Drive

• Reservoir is compacted because of overburden pressure.

Gravity Drainage Drive

• Gravity segregates oil and gas and oil is collected at the bottom of the reservoir.



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Beyond Primary Recovery

• Oil is trapped in pores• Oil is trapped in low permeability reservoirs• Oil is poorly connected to the existing wells

Significant amount of oil is remaining in the reservoir because:

For oil reservoirs, the primary recovery results in a very smallfraction of oil recovered compared to original oil in place; thisrecovery factor can be as low as 5% to as much as 30%

Additional recovery mechanisms are necessary to recovermore oil from the existing reservoirs

Secondary Recovery Mechanisms

Water is injected ininjectors and oil isproduced from producers

Water displaces andreplaces the hydrocarbonsas it pushes the oiltowards producer



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Many tertiary recovery mechanisms exist, and each of thesemechanisms produces oil by different process

Tertiary Recovery Mechanisms

Steam FloodingCO2 Flooding

Polymer Flooding Surfactant Flooding

Dissolves in oil and expels oil from the

pores

Steam increases the temperature of the oil

and reduces the viscosity

Increases the viscosity of injected fluid thus making it

easier to displace oil without overrunning it

By adding soap in injected fluid, we can

improve the miscibility between injected fluid and oil



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Flooding CO2 Flooding

CO2 is typically injected in an injector, and it extracts hydrocarbons from the oil which is present in the reservoir. By becoming richer, eventually creates miscibility with the oil phase, thus reducing the capillary affects and increasing the recovery of trapped oil. In addition, CO2 also dissolves in oil, expands the oil phase, and removes some of the oil which is present in pores. The steam flooding is a process where the steam is injected which is in vapor phase, and it provides the heat to the oil phase, thus reducing the viscosity. The steam eventually condenses into water phase and provides some additional help in pushing the oil towards producing well.



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Steam Flooding

The steam flooding is a process where the steam is injected which is in vapor phase, and it provides the heat to the oil phase, thus reducing the viscosity. The steam eventually condenses into water phase and also provides some additional help in pushing the oil towards producing well.



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Polymer Flooding

The polymer flooding is injection of polymers which are dissolved in water, thus increasing the viscosity of the displacing fluid. Because the viscosity of the displacing fluid is much higher, it moves a lot slower than oil, thus always staying behind the oil phase and resulting in a much more efficient displacement of oil towards producing well.



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Surfactant Flooding

Surfactant flooding is the process where surfactants are dissolved in water phase, and that dissolved surfactant creates a lower interfacial tension between the injector fluid and oil, thus reducing the capillary forces. Sometimes the surfactant flooding is also accompanied by polymers so that the viscosity of the injector fluid will also be higher, thus improving the displacement of oil by reducing the override. All these mechanisms are important. They're more expensive than either waterflooding or natural gas injection. However, they do recover more oil.



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Learning Objectives

Describe the driving force for producing oil and gas from thereservoir

List and explain the important primary reservoir mechanisms

Realize the need for additional drive mechanisms to recoveradditional hydrocarbons

Recall the principles of secondary and tertiary oil recoveryprocesses and explain why they recover additional oil beyondprimary recovery mechanisms




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Principles of Material Balance

Learning Objectives


Describe the principles behind material balance equation

Identify the data that is needed to apply the material balanceequation and the uncertainties associated with collecting suchdata

Identify the purpose of the modified black oil model in materialbalance equation

State the assumptions involved in applying the material balanceequation

Identify the limitations of material balance technique




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Basic Material Balance Equation

Injecting more fluid than produced

Material accumulated in reservoir

Higher pressure

Injecting lessfluid than produced

Material reduced in reservoir

Low pressure

Primary Recovery

Secondary and Tertiary Recovery

Secondary and Tertiary Recovery

Amount ofmass originally

present

Amountof mass

in

Amount of mass

out

Amount ofmass currently

present+ – =



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Data Needed for Material Balance

There are three types of data which are needed to apply the material balance technique.

Average pressure data as a function of time

How does the average reservoir pressure change as a function of time

Cumulative produced fluids

How much water, gas and oil are produced from the reservoir as a function of time

PVT properties How do the physical properties of water, gas and oil change as a function of time



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Material Balance Equation

Let's consider each of these three data types separately. The average reservoir pressure is the most difficult parameter to obtain for material balance calculations. Ideally, an average reservoir pressure can only be obtained if all the wells within the reservoir are shut in for long enough period to equilibrate pressure across the reservoir. This is very difficult to obtain. There are two challenges in obtaining such information. Operator may not be interested in shutting the production over a long period of time. This makes it difficult to get an average pressure. The only exception to this is if you have a gas reservoir which is connected to a gas plant, and yearly shut down of the gas plant may shut down all the wells, and hence we can obtain that average pressure. Or, hurricane forces the operator to shut down all the wells producing from the platform, and thus we'll be able to obtain an average reservoir pressure.

Other than that, we can only obtain average pressures from individual wells when they are shut in, and we can measure the buildup pressure. The second point is that to shut the wells requires an assumption that the pressure can be equilibrated in a reasonable period of time. An example of such exception is when you are trying to obtain an average pressure from unconventional reservoirs, or low permeability reservoirs, where the time to equilibrate is exceedingly long and is impractical. Part of the reason we cannot apply the material balance technique to unconventional reservoirs is the difficulty in obtaining an average reservoir pressure as a function of time. Typically, when we compare the gas reservoirs to oil reservoirs, because of high mobility of the gas phase, gas tends to equilibrate a lot faster than oil, hence the application of material balance is perhaps more appropriate for a given permeability and porosity for a gas reservoir rather than oil reservoir.

Average Pressure

Average pressure can only be obtained if all the wells within the reservoir are shut-in for long enough period to equilibrate pressure across the reservoir. Two challenges in obtaining such information:

Operator may not be interested in shutting the production over a long period of time

The time required to equilibrate can be very long and impractical



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Production Data

Production data requires continuous measurement of oil, gas and water rates from the field so that cumulative production as a function of time can be recorded and used.

The data are most reliable for oil since it is sold, and operator carefully monitors the information

The gas data are less reliable if the gas is not sold and instead flared

The water data are least reliable since it is a waste product Very few operators accurately measure it

The uncertainty in production data measurement should be considered in applying material balance data



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Rock and Fluid Properties

Standard fluid properties as a function of pressure and temperature

The properties required for material balance technique are:

Also need:

• Formation compressibility (cf)

• Water compressibility (cw)

If compaction and water expansion are important


Gas Gas Formation Volume Factor (Bg) Volatilized Oil-Gas Ratio (Rv)

Oil Oil Formation Volume Factor (Bo) Solution Gas-Oil Ratio (Rs)

Water Water Formation Volume Factor (Bw) Normally we neglect gas dissolved in water



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Fluid properties can be measured in the lab and the data are most reliable.

Fluid properties can be estimated from correlations if the lab data are not available.

The minimum amount of information required to generate fluid properties is:

• API gravity of oil

• Specific gravity of separator gas

• Salinity of water

For oil reservoirs, knowledge of either bubble point or initial gas-oil ratio is valuable to match the fluid properties correctly.


Large number of correlations are available to predict the properties as a function of pressure and temperature.

If the reservoir is either volatile oil or retrograde condensate, the estimation of properties without lab data can be less reliable.



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Generalized Black Oil Model

Generalized black oil model• Assumes that the reservoir contains certain initial fluid, which can

be either gas or oil

• As the pressure drops below bubble point, or dew point, twophases form in the reservoir which can be gas and oil

• If both of those phases are brought to the surface, they containthe other phase

Standardized black oil model• Assumes that the gas phase does not contain any evaporated oil,

whereas in generalized black oil model, we assume that the gasphase contains volatile oil

• In the lab, we can measure both the total amount of evolved gasand evolved oil, and the volume of the dominate phase

Generalized Black Oil Model

Reduced Pressure

Standard Conditions

Vgg

Vog

Vgo

Voo

Bg = Vg/VggRv = Vog/Vgg

Bo = Vo/VooRs = Vgo/Voo

Gas

Oil

Vg

Vo

IntermediatePressure

Initial Fluid(Single Phase)

InitialPressure



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Material Balance Application

Goal

Estimate initial hydrocarbons in place

Assumptions

The reservoir is homogeneous

No gradients exist in the reservoir: saturation, pressure, reservoir properties

The static properties can be arithmetically averaged

Limitation

Cannot be applied to individual wells within a reservoir. Part of the reason we cannot apply the material balance application to individual wells is because the hydrocarbons in place associated with individual wells can change with time as other wells in the neighborhood are drilled or abandoned. The volume of the hydrocarbons associated with a given well can be either large or small depending on how the other wells in the vicinity perform. You can always apply the material balance technique for the entire field, because the assumption is that all those hydrocarbons are associated with all the wells which are producing within that field.

Does not predict the future rate of the reservoir



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Material Balance Key Concept

Gfi

Nfi

W

InitialConditions, pi

NpWp

Gp

WIGI

IntermediateSteps

GR

NR

WR

CurrentConditions, p



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Learning Objectives

Describe the principles behind material balance equation

Identify the data that is needed to apply the material balanceequation and the uncertainties associated with collecting suchdata

Identify the purpose of the modified black oil model in materialbalance equation

State the assumptions involved in applying the material balanceequation

Identify the limitations of material balance technique

You are now able to:You are now able to:This section has covered the following learning objectives:



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Development of Equations

Learning Objectives


Develop the material balance equations from the first principle

Identify and explain the different mechanisms influencing theproduction of hydrocarbons and how they are incorporated inmaterial balance equation




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Equations

Single Phase Dry Gas Reservoir

Start with original material balance and eliminate terms from that equation.

Assume that there is no gas injection, because it's a single-phase gas there is no dissolved oil, there is no oil production, there is no water injection, there is no free oil present in the reservoir.

Simplifying

Btg = B

g since R

s and R

v are zero.



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Single Phase Gas Reservoir

You can write the material balance equation for single-phase gas as the equation below. The left-hand side of withdrawal remains the same, but on the right-hand side you have expansion of the gas, combination of the formation compressibility and the compressibility of water in a single part of the equation, and then water influx.

1



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Generalized Single Phase Gas Reservoir

This is a generalized single-phase gas reservoir equation, but this equation can also be simplified further if we neglect the compressibility of the formation as well as the compressibility of water. We neglect any water production and water influx. Then we get only one term on the left-hand side which is Gp times Bg and the right-hand side you have free gas (formation value factor under current conditions – formation value factor at initial conditions). We can simplify this equation by substituting the formation volume factor, and we come up with: gas produced = initial gas in place (1-P/Z) divided by Pi over Zi.



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Example of Volumetric Expansion

This is an example of a gas reservoir where P over Z is plotted as a function of gas produced and by extrapolating that line all the way until it intersects the X-axis we can calculate the free gas which is present in the reservoir.

So, this is an example of volumetric expansion of the gas phase where other contributing mechanisms are neglected.

-

8,500

17,000

0

500

1000

1500

2000

2500

0 1000 2000 3000

p/z

, kP

a

p/z

, psi

a

Gp



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Initial Oil in Place Initial Gas in Place

Remaining Oil Remaining Gas


Assume that: No gas is dissolved in water There are no chemical

reactions and changes

Recall that oil and gas phases in the reservoir can contain dissolved gas

and dissolved oil respectively

N Nfi GfiRvi G Gfi NfiRsi

NR GRRv GR NRRs


Oil balance

Gas balance

Water balance

Free oil + Oil in gas phase= Initial oil in place – What is produced

Free gas + Gas in the solution= Initial gas in place – What is produced + What is injected

Remaining water = Initialwater present – Water produced + Water injected

The constraint is the pore volume of the reservoir

To calculate the initial oil and gas in place, you need to know the remaining oil, gas and water in the reservoir



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In terms of pore volume, oilbalance can be written as:

Gas phase:

Water phase:

= Initial oil in place – Whatever is produced

= Initial gas in place + Amount injected – Amount gas produced

= Initial water in place – Amount produced + Amount of water injected

G

W


In terms of pore volume, oilbalance can be written as:

Gas phase:

Water phase:

We also know that: 1

In addition, G

W



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Relationship between the current and the initial pore volume as:

cf is the formation compressibility

1

Some terms in material balance equation are detailed below:


where

where

Expansion of gas phase

Expansion of oil phase

Difference in the formation volume factors of water

Compressibility of the formation



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Learning Objectives

This section has covered the following learning objectives:

Develop the material balance equations from the first principle

Identify and explain the different mechanisms influencing theproduction of hydrocarbons and how they are incorporated inmaterial balance equation



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Learning Objectives

By the end of this lesson, you will be able to:This section will cover the following learning objectives:

Understand the necessary equations to be used depending onthe type of reservoir from which hydrocarbons produce

Develop appropriate equations for dry gas, wet gas,condensate, volatile oil and black oil reservoirs



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The equation for wet gas will be exactly the same as single phase dry gas reservoir

Wet Gas Reservoir

1

The only additional term we need to

calculate is:Np GpRvi

Note that for wet gas reservoirs, there is no liquid drop in the reservoir. As a result, the amount of liquid produced at the surface is

always proportional to gas produced. The initial condensate yield never changes.

The wet gas does produce oil (or condensate). The condensate is converted to equivalent gas amount and is added to the

dry gas production.



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Retrograde Condensate Reservoir


Volatile Oil Reservoir




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Black Oil Reservoir




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Black Oil Reservoir (Above Bubble Point)

Consider some simplifications of the equation. If we assume that oil reservoir is producing at a pressure above bubble point with no gas cap, we can write the equation as:

1

Since the production is above bubble point, ; substituting:

1

If we assume, no water injection, no gas injection, no water production and no water influx, we can write the equation as:

1

Black Oil Reservoir (Below Bubble Point)

If we assume that oil is producing below bubble point, and we can ignore compressibility of rock and water, and assume no gas or water injection, and no gas cap, we can write:

Writing

The equation simplifies to:

If no water production or no water influx, we can write:



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Black Oil Reservoir (with Gas Cap)

If we assume gas cap is present and compressibility effects are negligible, we can write:

If we assume no water or gas injection, we can write:

If we assume no water production or water influx, we can write:



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Learning Objectives


Understand the necessary equations to be used depending on thetype of reservoir from which hydrocarbons produce

Develop appropriate equations for dry gas, wet gas, condensate,volatile oil and black oil reservoirs



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Applications of Material Balance: Simplifications

Learning Objectives


Describe modifications of material balance equations toestimate the initial oil and gas in place

Explain the Havlena and Odeh method and the appropriate wayto linearize the material balance equations

Express the importance of water influx and how to detect thepresence of aquifer based on production data

Recognize the uncertainties associated with predicting the waterinflux as a function of time




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Why Material Balance?

The equations presented before show the variety of options available to write material balance equations.

Typically, we will know the type of reservoir from which the hydrocarbons are produced (although in some instances it is difficult to distinguish between condensate or volatile oil reservoirs).

The amount of water influx creates the most uncertainty since the amount of water influx changes with time and it cannot be seen or measured.

In simple cases, if production data are available, we can solve for oil in place explicitly.



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Explicit Forms

Single Phase Dry or Wet Reservoir

A simple equation which allows you to calculate the gas in place explicitly by knowing a single data point at some reservoir pressure in the future.

Black Oil Reservoir

No water influx, no water production and no significant impact of compaction

==

If compaction is important and significant, and compressibilities are known

, 1

Substituting

=,

No water influx, no water production and no significant impact of compaction

If compaction is important and significant, and compressibilities are known

, 1

Substituting

,



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Havlena and Odeh Method

Havlena and Odeh [JPT, August 1963, p. 896] developed a method where initial oil in place (or gas in place) can be calculated once production data over a period of time is available. They developed linearized form of equation, which allowed graphical interpretation of the data and calculation of the initial gas or oil in place. Start with generalized form of the material balance equation:

The left-hand side of the equation is net withdrawal, defined as:

1 1

Single Phase Gas

If the left-hand side value, F, can always be calculated without uncertainty, several linear forms can be proposed. For example, for single phase gas reservoir equation without water influx, we could write it as F is equal to initial gas in place times Eg. A plot of F over versus Eg should yield a straight line with a slope equal to initial gas in place. This is assuming large number of data points are available.

If formation compressibility is important, then we can include the Ef,w term and we can write the equation for F as initial gas in place times Ef,w plus Eg, which means a plot of F versus Eg plus Ef,w should yield a straight line with slope equal to initial gas in place.

, )



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Single Phase Oil

For single phase oil, about bubble point and without water influx, we can write the equation as F equal to initial oil in place times E0 plus the impact of compressibility and by using the appropriate definition of Ef,w, we could write that equal to Nfoi times E0 plus Ef,w. A plot of F versus E0 plus Ef,w should yield a straight line with a slope equal to initial oil in place.

For oil reservoir with gas cap but no water influx, we can write the equation as F equal to initial oil in place into bracket, E0 plus M, which is the size of the gas cap compared to oil in place, times BOI over Bgi plus ... times Eg.

If you know the size of the gas cap, or M, then part of F versus E0 plus M times BOI over Bgi times Eg should yield a straight line and that should provide us with the initial oil in place.

If M is not known, then we can rearrange this equation to make it F over E0 versus Eg over E0. That will provide a straight line where intercept is equal to initial oil in place and the slope, with some manipulation, providing a value of the size of the gas cap. There are many ways that Havlena and Odeh method can be utilized so that we can develop an equation for a straight line.

1= ,



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About the Method

Havlena and Odeh method is useful because it provides a straight-line equation for most mechanisms. That is, if we know the principal mechanisms providing the support to produce oil or gas, a straight-line equation can be developed to estimate oil and gas in place

The only exception is when the reservoir is supported by water influx. Since the amount of water influx is not known and needs to be estimated, the only way Havlena and Odeh method can be formulated in terms of straight line is if the amount of water influx as a function of time can be explicitly calculated

Even in the absence of knowledge about how much water is received from aquifer, Havlena and Odeh (or some modification of it) plot can be instructive understanding an importance of aquifer



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Gas Reservoir with Aquifer

A plot of , vs any variable (time, average pressure, cumulative

production, etc.) should be a horizontal line (equal to Gfgi) in the absence of

aquifer. If we observe a deviation from the horizontal line, it is an indication

of mechanisms which can be important.



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Cole Plot

A plot of F over Eg plus Ef,w versus any variable time, average pressure, cumulative production, etc. should be a horizontal line equal to GFGI in the absence of aquifer. If we observe a deviation from the horizontal line, it is an indication of mechanisms which can be important. If it's a horizontal line, that means only the expansion's terms are important and gas in place can be calculated as an intercept on Y axis.

However, if the rock compressibility dominates and is important, you can see a shape, which is shown as graph two. If there is a weak aquifer which is influencing the reservoir, you get a shape like three, and if a strong aquifer is present, you can get a shape like four. If you know that other mechanisms are driving the gas influx or gas in place calculation, then those can be incorporated by understanding which mechanisms may be important and need to be considered.



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Oil Reservoir with Aquifer

A plot of ,

versus any variable (pressure, time or

cumulative production) should be a horizontal line with an intercept on y

axis equal to initial oil in place. If horizontal line moves higher, this is an

indication of presence of other mechanisms.



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How to Determine the Water Influx?

Calculation of water influx requires trial and error method because:

The size of the aquifer is rarely known

The reservoir properties of the aquifer are rarely known

The water influx can be represented either by transient state or pseudo-steady state

Key to remember is that even with many available equations, multiple solutions are possible for aquifer influx which will provide reasonable solutions



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Learning Objectives


Describe modifications of material balance equations to estimatethe initial oil and gas in place

Explain the Havlena and Odeh method and the appropriate wayto linearize the material balance equations

Express the importance of water influx and how to detect thepresence of aquifer based on production data

Recognize the uncertainties associated with predicting the waterinflux as a function of time

PetroAcademyTM Applied Reservoir Engineering Skill Modules

This is Reservoir Engineering Core

Reservoir Rock Properties Core

Reservoir Rock PropertiesFundamentals

Reservoir Fluid Core

Reservoir Fluid Fundamentals

Reservoir Flow Properties Core

Reservoir Flow PropertiesFundamentals

Reservoir Fluid Displacement Core

Reservoir Fluid Displacement Fundamentals

Properties Analysis Management


Reservoir Material Balance Fundamentals

Decline Curve Analysis and Empirical Approaches Core

Decline Curve Analysis and Empirical Approaches Fundamentals

Pressure Transient Analysis Core

Rate Transient Analysis Core

Enhanced Oil Recovery Core

Enhanced Oil Recovery Fundamentals

Reservoir Simulation Core

Reserves and Resources Core

Reservoir Surveillance Core

Reservoir Surveillance Fundamentals

Reservoir Management Core

Reservoir Management Fundamentals




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Reservoir Material Balance COPYRIGHTcloud1.activelearner.com/contentcloud/portals/... · initial oil in place (or gas in place) can be calculated once production data ~ ~ A ~ ~ q