PTO CHAPTER 04A Well Inflow and Outflow

Chapter 4.

Well Inflow And Outflow

Well Performance is about understanding how to optimize the “system”.

The system is comprised of components.

Each component can be individually modeled.

The components can be connected to create a

“system” model.

Well Performance is about understanding how to optimize the “system”.

The system is comprised of components.

Each component can be individually modeled.

The components can be connected to create a

“system” model.

Reservoir

Wellbore

Flowline

SeparatorChoke

Completion

The System

Although the system includes all components to

the export valve, in this class, focus will be on the components of the system from within the reservoir

to the separator.

Although the system includes all components to

the export valve, in this class, focus will be on the components of the system from within the reservoir

to the separator.

The System

Why… to the separator?

A constant pressure is maintained on the separator by

a back pressure regulator.

So, the system has a pressure boundary at the separator.

Production from the well will not affect the separator

pressure.

Why… to the separator?

A constant pressure is maintained on the separator by

a back pressure regulator.

So, the system has a pressure boundary at the separator.

Production from the well will not affect the separator

pressure.

The System

A well’s production often joins total production from other wells in a

configuration of valves and pipes called the manifold which is upstream of the separator.

Often one well’s production does not affect the pressure significantly

at the manifold.

Assuming constant manifold pressure, production affects from

well to well can be ignored.

Well model tools - WEM, WEPS, SNAP, Prosper, or others - are

used to analyze well flow.Or, a network solution package such as GOAL or GAP is used.

A well’s production often joins total production from other wells in a

configuration of valves and pipes called the manifold which is upstream of the separator.

Often one well’s production does not affect the pressure significantly

at the manifold.

Assuming constant manifold pressure, production affects from

well to well can be ignored.

Well model tools - WEM, WEPS, SNAP, Prosper, or others - are

used to analyze well flow.Or, a network solution package such as GOAL or GAP is used.

Manifold

The System

Everywhere else in the system, the pressure (and temp) will

vary with rate.

It is mathematically helpful to start calculations from the

boundaries and work back to one point from each boundary.

This one point, Pwf, is normally chosen at the mid perforation interval depth in the well bore.

Everywhere else in the system, the pressure (and temp) will

vary with rate.

It is mathematically helpful to start calculations from the

boundaries and work back to one point from each boundary.

This one point, Pwf, is normally chosen at the mid perforation interval depth in the well bore.

The System

So, dividing the system as shown defines:

Outflow - downstream of this point. Primarily tubing & mechanical influences.

Inflow - upstream of this point. Primarily formation

influences.

So, dividing the system as shown defines:

Outflow - downstream of this point. Primarily tubing & mechanical influences.

Inflow - upstream of this point. Primarily formation

influences.

Inflow

Outflow

The System

The System

For gas wells, the system is sometimes divided at the

wellhead.

The well delivers based on the backpressure it sees.

Gas well performance is defined as its deliverability.

For gas wells, the system is sometimes divided at the

wellhead.

The well delivers based on the backpressure it sees.

Gas well performance is defined as its deliverability.

A Very Important Principle

Flow in pipe (e.g. tubing, flowline) or in porous media (e.g. formation) is related to the pressure difference between two points.

The greater the differential, the greater the flow rate, everything else being equal.

Flow direction is always from higher to lower pressure.

When the pressure differential approaches zero, flow stops.

A Very Important Principle

Flow in pipe (e.g. tubing, flowline) or in porous media (e.g. formation) is related to the pressure difference between two points.

The greater the differential, the greater the flow rate, everything else being equal.

Flow direction is always from higher to lower pressure.

When the pressure differential approaches zero, flow stops.

The System

All of the energy driving flow through this system is supplied

by the reservoir.

The greater the difference between the reservoir pressure and the separator pressure, the greater the potential flow rate.

All of the energy driving flow through this system is supplied

by the reservoir.

The greater the difference between the reservoir pressure and the separator pressure, the greater the potential flow rate.

The System

Acting against this differential and decreasing the flow rate are a number of important factors:

• vertical height of flow (head)

• friction of flow in pipe(s)

• friction of flow in the formation

these are the factors Production Technologists were

created to manage

PTs also must take responsibility for assuring that the differential

between the reservoir and separator is optimized.

Acting against this differential and decreasing the flow rate are a number of important factors:

• vertical height of flow (head)

• friction of flow in pipe(s)

• friction of flow in the formation

these are the factors Production Technologists were

created to manage

PTs also must take responsibility for assuring that the differential

between the reservoir and separator is optimized.

The System

What is the difference between inflow and outflow?

Inflow usually refers to flow from reservoir. Outflow usually refers to flow inside tubing.

Why does the system described here stop at the separator instead of the export valve?

Pressures upstream of the separator are usually those that significantly affect production.

Questions:

Pres

Pbhfp

Pftp

Pflowline

Psep inlet

Pst tank

Pre

ssu

re (

ps

i)

Produced Fluids Moving Through The System

P

System Pressure Drop

- reservoir- skin ??- perfs- tubing- wellhead- choke- flowline- manifold- separator- stock tank

note greatest pressure drop is due to skin

and in the production

tubing

Total Oil / Gas System Analysis

Inflow to any node pres - p (upstream components) = pnode

Outflow from any node psep + p (downstream components) = pnode

Conditions:1. Flow into a node equals flow out of a node2. Only one pressure can exist at a node3. Only one temperature can exist at a node

THE BASIC PRINCIPLE

Total Oil / Gas System Analysis

Pressure drop in any node is f (Q)Q = vol / time => ft3 / sec => ft2 x ft/sec => A x v

and velocity provides “lift”

Therefore, A plot of node rate vs node pressure produces a

curve for both inflow and outflow at each node

The intersection of the curves satisfies the conditions of inflow and outflow

Any change in conditions changes the curve(s)– separator pressure change – reservoir depletion– water cut change

Res

ervo

ir

Tub

ing

Cho

ke

Flo

wlin

e

Sep

arat

or

Sal

es /

Sto

ck

Tan

k

Tresv

TsepTst

Tftt

Tmanifold

Similarly, Temperature In The Production System

Tups ck

Tds ck

Phase Behavior

What happens to the oil and gas as they move through the system?

What happens to the oil and gas as they move through the system?

looking from above, this is a sketch of hydrocarbons flowing up a tubing stream . . .

casing

production tubing

Along the way from the reservoir to the separator, the production stream undergoes changes.

Assume for an oil reservoir:

• oil leaving the reservoir drops in pressure and temperature

• light hydrocarbons (HC) are liberated from the mixture of oil as the pressure falls

• the oil phase shrinks as the light HC leave and viscosity increases

• the gas phase expands as the light HC accumulate

• the volume of each phase determines the flow regimes each with its own friction and head properties

Along the way from the reservoir to the separator, the production stream undergoes changes.

Assume for an oil reservoir:

• oil leaving the reservoir drops in pressure and temperature

• light hydrocarbons (HC) are liberated from the mixture of oil as the pressure falls

• the oil phase shrinks as the light HC leave and viscosity increases

• the gas phase expands as the light HC accumulate

• the volume of each phase determines the flow regimes each with its own friction and head properties

Phase Behavior

Phase Behavior

So, why do PTs care about phase behavior?

A PT must be able to accurately predict the properties of produced fluids because the properties strongly influence the flowing pressures in the production system, and thus, they influence the production rates.

Proper assumptions, data collection, and classification and use of PVT properties is important to the success of most projects.

In most cases, the PT will work closely with the Reservoir Engineer to gather and create shared PVT data sets.

So, why do PTs care about phase behavior?

A PT must be able to accurately predict the properties of produced fluids because the properties strongly influence the flowing pressures in the production system, and thus, they influence the production rates.

Proper assumptions, data collection, and classification and use of PVT properties is important to the success of most projects.

In most cases, the PT will work closely with the Reservoir Engineer to gather and create shared PVT data sets.

Reservoir fluids may be composed of hundreds of compounds.

Only the compositions from C1 (methane) up to some heavier compounds (~C30) can be accurately defined.

The composition of a compound may change only when parts of the stream leave the system.

To describe the phase change of a hydrocarbon mixture, a given composition, a phase envelope is used.

Reservoir fluids may be composed of hundreds of compounds.

Only the compositions from C1 (methane) up to some heavier compounds (~C30) can be accurately defined.

The composition of a compound may change only when parts of the stream leave the system.

To describe the phase change of a hydrocarbon mixture, a given composition, a phase envelope is used.

Phase Behavior

This info is from DC Brown’s “Oil &Gas PVT for Experienced Engineers”

Phase Behavior

single phase vapor

single phase liquid

Temperature

Pre

ssur

e

Phase Envelope / Phase Diagram

vapor condenses

single compounds behave like this (propane, water)

single compounds behave like this (propane, water)

liquid boils

single component system


Phase Behavior

single phase vapor

single phase liquid

Critical Point = liquid/vapor same

0% li

quid

20%

liqu

id

100%

liqui

d

60%

liqui

d80%

liqui

d

40%

liqui

d

Dew

poin

t

Bubblepoint

Two Phase

Temperature

Pre

ssur

e


multi-component system


Phase Behavior

single phase liquid

0% li

quid

20%

liqu

id

100%

liqui

d

60%

liqui

d80%

liqui

d

40%

liqui

d

Dew

poin

t

Bubblepoint

Saturated

Temperature

Pre

ssur

e

Undersaturatedcan dissolve more

liquid or vapor

single phase vapor


Phase Behavior

single phase vapor

single phase liquid

0% li

quid

100%

liqui

d

Dew

poin

t

Bubblepoint

Temperature

Pre

ssur

e


oil has a bubble point where the first bubble of gas will appear

oil has a bubble point where the first bubble of gas will appear


Phase Behavior

single phase vapor

single phase liquid

0% li

quid

100%

liqui

d

Dew

poin

t

Bubblepoint

Temperature

Pre

ssur

e


retrograde segment

normal segment

vapor condenses

vapor condenses

gas has two means to reach the dew point where the first drop of liquid will appear

gas has two means to reach the dew point where the first drop of liquid will appear


Phase Behavior

single phase vapor

single phase liquid

0% li

quid

100%

liqui

d

Dew

poin

t

Bubblepoint

Temperature

Pre

ssur

e


phase diagrams are useful for classifying oils and

gasses

oil/gas classification depends on the location of the initial point (T,P) on the

diagram

phase diagrams are useful for classifying oils and

gasses

oil/gas classification depends on the location of the initial point (T,P) on the

diagram

Oil Gas


Phase Behavior

single phase vapor

single phase liquid

0% li

quid

100%

liqui

d

Dew

poin

t

Bubblepoint

Temperature

Pre

ssur

e

from their initial condition, fluids either stay in the reservoir, or . . .

from their initial condition, fluids either stay in the reservoir, or . . .

Oil Gas

PabandonPabandon


Phase Behavior

single phase vapor

single phase liquid

0% li

quid

100%

liqui

d

Dew

poin

t

Bubblepoint

Temperature

Pre

ssur

e

from their initial condition, fluids either stay in the reservoir or . . . are produced

from their initial condition, fluids either stay in the reservoir or . . . are produced

Oil Gas

T,Psep


Oils may be subdivided into:

Low Shrinkage (Black Oil)• API < 35o

• GOR < 500 scf/stb• Black or deeply colored• More large HC molecules than smaller

High Shrinkage (Volatile Oil)• API 30o - 50o

• GOR 500 - 8000 scf/stb• Medium orange colored• Relatively fewer heavy molecules than low

shrinkage oil and more intermediates




High Shrinkage (Volatile Oil)• API 30o - 50o

• GOR 500 - 8000 scf/stb• Medium orange colored• Relatively fewer heavy molecules than low



Phase Behavior

020

4060

8010

0Liquid Volume Curve for Typical Black Oil

Liquid Volume Curve for Typical Black Oil

Pressure0

Liqu

id V

olum

e %


020

4060

8010

0Liquid Volume Curve for Typical Volatile Oil

Liquid Volume Curve for Typical Volatile Oil

Pressure0

Liqu

id V

olum

e %


In a volatile oil, solution gas can drop out liquids.

In a black oil, the solution gas is ‘dry’ gas.

Volatile oils contain fewer large molecules so that intermediate molecules tend to separate into the gaseous phase.

. . . there are some gray areas in between

In a volatile oil, solution gas can drop out liquids.

In a black oil, the solution gas is ‘dry’ gas.

Volatile oils contain fewer large molecules so that intermediate molecules tend to separate into the gaseous phase.

. . . there are some gray areas in between


Phase Behavior

single phase vapor

single phase liquid

0% li

quid

100%

liqui

d

Dew

poin

t

Bubblepoint

Temperature

Pre

ssur

eRetrograde

Condensate Gas

Retrograde Condensate Gas

Oil

T,Psep

Pabandon


Retrograde Condensate

As reservoir pressure declines, condensate liquids drop out of gas in reservoir.

This condensate usually cannot be produced as it occurs in quantities below the critical oil saturation; hence, producing CGR decreases. (Rich retrograde condensates can produce at high CGR.)

Condensate drop out can also cause blockage around the well bore.

As pressure declines, condensate volume would be expected to decrease, EXCEPT, that the phase diagram is also shifting due to the composition of the reservoir liquids changing (that is, getting richer).

Retrograde Condensate

As reservoir pressure declines, condensate liquids drop out of gas in reservoir.

This condensate usually cannot be produced as it occurs in quantities below the critical oil saturation; hence, producing CGR decreases. (Rich retrograde condensates can produce at high CGR.)

Condensate drop out can also cause blockage around the well bore.

As pressure declines, condensate volume would be expected to decrease, EXCEPT, that the phase diagram is also shifting due to the composition of the reservoir liquids changing (that is, getting richer).

Phase Behavior


Retrograde Condensate Gas • API 50o - 60o

• GOR 8000 - 70,000 scf/stb or 100 - 140 stb/mmscfd (rich up to 400)• Tank oil is usually water-white or of a light

color; rich condensate can be black.• Contains relatively fewer of the heavier

molecules than low shrinkage oil.

Retrograde Condensate Gas • API 50o - 60o

• GOR 8000 - 70,000 scf/stb or 100 - 140 stb/mmscfd (rich up to 400)• Tank oil is usually water-white or of a light

color; rich condensate can be black.• Contains relatively fewer of the heavier


Phase Behavior


Volatile Oil vs Retrograde Condensates

As pressure decreases:• volatile oils exhibit bubble points• retrograde condensates exhibit dew points

Critical temperature is:• less than reservoir temp for retrograde gases• more than reservoir temp for volatile oils

Retrograde condensates contain fewer heavy molecules than volatile oils.

Volatile Oil vs Retrograde Condensates

As pressure decreases:• volatile oils exhibit bubble points• retrograde condensates exhibit dew points

Critical temperature is:• less than reservoir temp for retrograde gases• more than reservoir temp for volatile oils

Retrograde condensates contain fewer heavy molecules than volatile oils.

Phase Behavior


020

4060

8010

0Retrograde Liquid

Curve for Typical Lean Gas-Condensate

Retrograde Liquid Curve for Typical Lean

Gas-Condensate

Pressure0

Liqu

id V

olum

e %

Phase Behavior


020

4060

8010

0Retrograde Liquid Curve for Typical

Rich Gas-Condensate

Retrograde Liquid Curve for Typical Rich Gas-Condensate

Pressure0

Liqu

id V

olum

e %

Phase Behavior


Phase Behavior

single phase vapor

single phase liquid

Dew

poin

t

Bubb

lepo

int

Temperature

Pre

ssur

e

Wet GasWet Gas

Oil

T,Psep

Pabandon


Dew

point

Phase Behavior

single phase vapor

single phase liquid

Dew

poin

t

Bub

blep

oint

Temperature

Pre

ssur

e

Oil

T,Psep

Pabandon

Dry GasDry Gas


Wet Gas• API > 60o

• GOR up to 100,000 scf/stb or 10 stb/mmscf• Produced liquids usually water-white• Contains predominantly smaller hc molecules

Dry Gas

No condensate due to lack of heavy molecules



Dry Gas


Phase Behavior


Phase Envelopes For Reservoir Fluids

Pres Pres Tres Tres

Reservoir “A” Reservoir “B”

Similar Initial Reservoir Pressures For

2 Different Reservoir Temperatures

the position of the phase envelope relative to the

reservoir temperature, not

the reservoir system

hydrocarbon composition, is the controlling factor which determines

reservoir type

“C” is the critical temperature

for each system

This Example

Tres 1 Tres 2

TEMPERATURE ---->

look at each of four cases

Phase Envelopes For Reservoir Fluids

Pres Pres Tres Tres

Reservoir “A” Reservoir “B”

Similar Initial Reservoir Pressures For

2 Different Reservoir Temperatures

at higher temperature, the gas condensate

reservoir would be a gas reservoir

and the volatile oil reservoir would be a gas condensate

reservoir

“C” is the critical temperature

for each system

GAS COND

VOLATILEOIL

This Example

Tres 1 Tres 2

TEMPERATURE ---->

look at each of four cases

Phase Behavior

separator

gas at dew point

oil at bubble point

two-phase HC mixture

Once phases separate, each has its own composition and thus its own phase envelope.

This happens in separator, but also in tubing and

possibly in the reservoir.

Once phases separate, each has its own composition and thus its own phase envelope.

This happens in separator, but also in tubing and

possibly in the reservoir.




High Shrinkage (Volatile Oil)• API 30o - 50o 45o (OPEC) • GOR 500 - 8000 5000 scf/stb (OPEC)• Medium orange colored• Relatively fewer heavy molecules than low





High Shrinkage (Volatile Oil)• API 30o - 50o 45o (OPEC) • GOR 500 - 8000 5000 scf/stb (OPEC)• Medium orange colored• Relatively fewer heavy molecules than low



Phase Behavior - Summary

Retrograde Condensate Gas • API 50o 45o (OPEC) - 60o

• GOR 8000 5000 scf/stb (OPEC) - 70,000 or 100 - 14 stb/mmscfd (rich up to 400)• Tank oil is usually water-white or of a light color; rich condensate can be black.• Contains relatively fewer of the heavier


Retrograde Condensate Gas • API 50o 45o (OPEC) - 60o

• GOR 8000 5000 scf/stb (OPEC) - 70,000 or 100 - 14 stb/mmscfd (rich up to 400)• Tank oil is usually water-white or of a light color; rich condensate can be black.• Contains relatively fewer of the heavier




Dry Gas




Dry Gas



Phase Behavior - Summary cont’d.

Is this an oil or gas reservoir and what type? Why?

What happens to oil as it goes from the reservoir to the stock tank?

What kind of fluid type has a liquid with 39 API gravity and a GOR of 2500 scf/bbl ?

Questions

Inflow Performance

Picture yourself at the bottom of a flowing well

• Why is the well flowing?

• What would prevent flow from the well?

• What would make this well produce more?

Picture yourself at the bottom of a flowing well

• Why is the well flowing?



Inflow Performance

The inflow system dictates how much energy is provided to the rest of the system in a natural flowing well.

[Artificial lift adds extra energy. That’s another story for a later chapter! ]

For the inflow system, the lower the pressure at the bottom of the well, the more liquid can be pulled into the well.

The pressure at the bottom of the well is the flowing bottom hole pressure, Pwf [= FBHP]

The inflow system dictates how much energy is provided to the rest of the system in a natural flowing well.

[Artificial lift adds extra energy. That’s another story for a later chapter! ]

For the inflow system, the lower the pressure at the bottom of the well, the more liquid can be pulled into the well.

The pressure at the bottom of the well is the flowing bottom hole pressure, Pwf [= FBHP]

Inflow Performance

The inflow portion of the system can be described by providing information for various categories below:

• Rock

• Fluid

• Pressure

• Drive Mechanism

The inflow portion of the system can be described by providing information for various categories below:

• Rock

• Fluid

• Pressure

• Drive Mechanism

Inflow Performance

Reservoir Rock

is described by:

Mineralogy - the kind of rock, fines, etc.

Porosity - the space that holds reservoir fluids

Permeability - the measure of how easily a known fluid will flow through the pore space

Reservoir Rock

is described by:

Mineralogy - the kind of rock, fines, etc.

Porosity - the space that holds reservoir fluids

Permeability - the measure of how easily a known fluid will flow through the pore space

Inflow Performance

Reservoir Fluid

is described as:

Oil, Gas, Water, Condensate

each has specific properties at a given P&T

ratios of each are important and change over time; ratios (as well as the properties) will affect inflow performance

Reservoir Fluid

is described as:

Oil, Gas, Water, Condensate

each has specific properties at a given P&T

ratios of each are important and change over time; ratios (as well as the properties) will affect inflow performance

Pr

Inflow Performance

Pressures

important measures are:

Pwf - pressure at the bottom of the well

Pres - average pressure in the reservoir which provides the energy to the system

Drawdown - difference between Pres and Pwf

Skin - catch-all measure of the impedance to the flow caused by effects near the well

Pressures

important measures are:

Pwf - pressure at the bottom of the well

Pres - average pressure in the reservoir which provides the energy to the system

Drawdown - difference between Pres and Pwf

Skin - catch-all measure of the impedance to the flow caused by effects near the well

Pwf

Inflow Performance

Pwf

Pwf and Pres need to relate to the same depth: the ‘bottom of the well’.

The depth is often defined as the “datum” at the top or mid point of the producing interval.

Above this depth will require extrapolation of the outflow part of the system.

Pwf and Pres need to relate to the same depth: the ‘bottom of the well’.

The depth is often defined as the “datum” at the top or mid point of the producing interval.

Above this depth will require extrapolation of the outflow part of the system.

cumulative rateacross interval

Zero Rate

Total Rate

Inflow Performance

Another way to express pressure is with a pressure gradient => Pressure / Depth

Depth is always a true vertical depth (TVD).

View reservoir pressures as a gradient:

hydrostatic = 0.433 psi/ft

sub-hydrostatic < 0.433 (e.g. 0.350 psi/ft)

geopressured > 0.433 (e.g. 0.650 psi/ft)

The term ‘hydrostatic’ in offshore locations is usually taken at .465 psi/ft since no fresh water is present.

Also look at flowing pressures this way . . . A flowing pressure gradient range is ~ 0 psi/ft (for low flow rates, gas) to ~ 1 psi/ft (for high water cut wells with high friction).

Another way to express pressure is with a pressure gradient => Pressure / Depth

Depth is always a true vertical depth (TVD).

View reservoir pressures as a gradient:

hydrostatic = 0.433 psi/ft

sub-hydrostatic < 0.433 (e.g. 0.350 psi/ft)

geopressured > 0.433 (e.g. 0.650 psi/ft)

The term ‘hydrostatic’ in offshore locations is usually taken at .465 psi/ft since no fresh water is present.

Also look at flowing pressures this way . . . A flowing pressure gradient range is ~ 0 psi/ft (for low flow rates, gas) to ~ 1 psi/ft (for high water cut wells with high friction).

psi / ft = 0.052 x ppg psi / ft = 0.052 x ppg

Inflow Performance

Reservoir

described by:

Size - areal extent (acres)

Vertical Thickness - net pay, gross pay (feet)

Tilt - dip, angle from horizontal (angle - degrees)

Number of ‘reservoirs’ producing - it is possible to have hundreds of reservoirs producing into a single well (Tahoe, Enchilada, Salsa).

Reservoir

described by:

Size - areal extent (acres)

Vertical Thickness - net pay, gross pay (feet)

Tilt - dip, angle from horizontal (angle - degrees)

Number of ‘reservoirs’ producing - it is possible to have hundreds of reservoirs producing into a single well (Tahoe, Enchilada, Salsa).

dip

Gross Thickness

Inflow Performance

Reservoir

In the long term, inflow is heavily influenced by the reservoir drive mechanism.

• Solution gas drive

• Gas cap drive

• Water drive

• Gravity drive

In addition to these, compaction of the rock can be a drive mechanism.

There are usually multiple drive mechanisms at work in a real reservoir.

Reservoir

In the long term, inflow is heavily influenced by the reservoir drive mechanism.

• Solution gas drive

• Gas cap drive

• Water drive

• Gravity drive

In addition to these, compaction of the rock can be a drive mechanism.

There are usually multiple drive mechanisms at work in a real reservoir.

Inflow Performance

Solution Gas Drive - gas breaks out of solution and expanding gas maintains pressure in reservoir somewhat

Over time:

GOR (gas to oil ratio) increasing (may become gas cap drive)

Rapid decline in reservoir pressure

Water increase not significant

Solution Gas Drive - gas breaks out of solution and expanding gas maintains pressure in reservoir somewhat

Over time:

GOR (gas to oil ratio) increasing (may become gas cap drive)

Rapid decline in reservoir pressure

Water increase not significant

Inflow Performance

Gas Cap Drive - gas in gas cap is expanding as pressure depletes, maintaining pressure somewhat (later stages of solution gas drive)

Over time:

GOR increases slowly as gas is pulled into the producing well

Reservoir pressure decreases somewhat

Water production increase not significant

Gas Cap Drive - gas in gas cap is expanding as pressure depletes, maintaining pressure somewhat (later stages of solution gas drive)

Over time:

GOR increases slowly as gas is pulled into the producing well

Reservoir pressure decreases somewhat

Water production increase not significant

Inflow Performance

Water Drive - Large aquifer volume expands providing pressure for relatively small oil volume. Can be supplemented (or imitated) with water injection.

Over time:

Reservoir pressure decreases slowly (if at all)

GOR remains fairly constant

Water increase very significant as water is pulled into well

Water Drive - Large aquifer volume expands providing pressure for relatively small oil volume. Can be supplemented (or imitated) with water injection.

Over time:

Reservoir pressure decreases slowly (if at all)

GOR remains fairly constant

Water increase very significant as water is pulled into well

Inflow Performance

Gravity Drainage Drive - Usually for heavy oils with very little or no gas. Oil literally is produced as the density of the oil drops and oil moves under force of gravity. Normally accompanied by artificial lift. Can also be supplemented with water injection.

Over time:

Reservoir pressure remains low.

GOR very low if at all.

Gravity Drainage Drive - Usually for heavy oils with very little or no gas. Oil literally is produced as the density of the oil drops and oil moves under force of gravity. Normally accompanied by artificial lift. Can also be supplemented with water injection.

Over time:

Reservoir pressure remains low.

GOR very low if at all.

Inflow Performance

Recoverable Reserves

The Production Engineer often has to work with Res Engrg to calculate recoverable reserves for a given well (e.g. - for workover economics).

Recoverable Reserves

The Production Engineer often has to work with Res Engrg to calculate recoverable reserves for a given well (e.g. - for workover economics).

Re

Re = drainage radius, ft

A = drainage area = (Re)2/43560, acres

A varies from ~ 30 to 160 acres, with the larger drainage in massive hydraulic fractures or very massive, continuous sands (deep water)

Inflow Performance

Volumetric Oil In Place & Recoverable Reserves

How are reserves calculated early in field life ?

Oil:

= 7758 A h (1-Swc) R.F. / Bo

where:

A is recovery area in acres

h is thickness of reservoir in ft

is porosity fraction

Swc is connate water saturation

R.F. is the recovery factor (efficiency)

Bo is the formation volume factor (res bbl / st tank bbl)

Inflow Performance

Volumetric Gas I.P. & Recoverable Reserves


Gas: = 43560 A h (1-Swc) {(Pi/Zi - Pa/Za) Tsc} / (T Psc) OR

= 43560 A h (1-Swc) {(Pi/Zi) Tsc / (T Psc)} x R.F.

where:





Pi is reservoir pressure, initially, psia

Pa is reservoir pressure at abandonment, psia

Psc is standard conditions pressure, 14.7 psia

T is reservoir temperature, oR (460o F+ Treso F)

Tsc is standard temperature, 520oR (460o F+ 60o F)zi and za are gas compressibility factors at initial reservoir conditions and at abandonment

Volumetric Gas I.P. & Recoverable Reserves


Gas: = 43560 A h (1-Swc) {(Pi/Zi - Pa/Za) Tsc} / (T Psc) OR

= 43560 A h (1-Swc) {(Pi/Zi) Tsc / (T Psc)} x R.F.

where:





Pi is reservoir pressure, initially, psia

Pa is reservoir pressure at abandonment, psia

Psc is standard conditions pressure, 14.7 psia

T is reservoir temperature, oR (460o F+ Treso F)

Tsc is standard temperature, 520oR (460o F+ 60o F)zi and za are gas compressibility factors at initial reservoir conditions and at abandonment

Inflow Performance

Remember, the lower the flowing pressure at the bottom of the well, the higher the flow rate.

There are many ways to describe (mathematically model) this behavior. In general, the relationship between the flowing bottom hole pressure and the amount of the primary phase coming into the wellbore is the wells inflow performance relationship (IPR).

For oil wells, the rate of liquid entering the well

For gas wells, the rate of gas entering the well

Remember, the lower the flowing pressure at the bottom of the well, the higher the flow rate.

There are many ways to describe (mathematically model) this behavior. In general, the relationship between the flowing bottom hole pressure and the amount of the primary phase coming into the wellbore is the wells inflow performance relationship (IPR).

For oil wells, the rate of liquid entering the well

For gas wells, the rate of gas entering the well

Rate

Pw

f

Inflow Performance

Pwf = fn(Q)

Inflow Performance

Two points on the curve are normally all that is necessary to define an IPR relationship.

The two points (boundary conditions) are:

Reservoir Pressure: Rate = 0

AOF (absolute open flow): Pwf = 0

Two points on the curve are normally all that is necessary to define an IPR relationship.

The two points (boundary conditions) are:

Reservoir Pressure: Rate = 0

AOF (absolute open flow): Pwf = 0

Rate

Pw

f

AOF

Pres

Normally, Pres and one other point are given.Normally, Pres and one other point are given.

Inflow Performance

PI = Straight line IPR

Productivity Index (PI also given as J):

P.I. = Q / (Pr - Pwf)

or, Pwf = Pr - Q / PI

or, Q = PI * (Pr - Pwf)

P.I. is given in units of bpd / psi

PI = Straight line IPR

Productivity Index (PI also given as J):

P.I. = Q / (Pr - Pwf)

or, Pwf = Pr - Q / PI

or, Q = PI * (Pr - Pwf)

P.I. is given in units of bpd / psi

Rate

Pw

f

AOF

Pr

PI

Inflow Performance

P.I. - Straight Line IPR

Works fine for water wells and undersaturated oil zones.

Useful for simple estimates of changes near a Pwf (small incremental changes) or at very small drawdowns.

Useful (if not particularly accurate) for making comparison between zones. (“Hey, what’s the PI?”)

Not a very good representation of the liquid part of multi-phase flow.

Doesn’t take gas flow into account so PI over predicts liquid production at lower pressures in oil/gas systems.

P.I. - Straight Line IPR

Works fine for water wells and undersaturated oil zones.

Useful for simple estimates of changes near a Pwf (small incremental changes) or at very small drawdowns.

Useful (if not particularly accurate) for making comparison between zones. (“Hey, what’s the PI?”)

Not a very good representation of the liquid part of multi-phase flow.

Doesn’t take gas flow into account so PI over predicts liquid production at lower pressures in oil/gas systems.

Inflow Performance

For 2-phase flow (liquid and gas), gas expands as it approaches the well bore.

This gas partially blocks the pore throats open to liquid flow.

Since the plot is in terms of liquid flow, the effect is a downward curvature of the IPR.

In other words, a decreasing PI at lower pressures.

For 2-phase flow (liquid and gas), gas expands as it approaches the well bore.

This gas partially blocks the pore throats open to liquid flow.

Since the plot is in terms of liquid flow, the effect is a downward curvature of the IPR.

In other words, a decreasing PI at lower pressures.

Rate

Pw

f

AOF

Pr

Inflow Performance

PI is only meaningful at a small increment from Pr for multi-phase systems.

PI is only meaningful at a small increment from Pr for multi-phase systems.

Rate

Pw

f

AOF

PrPI

However, PI is used to loosely describe IPR for higher draw down and given rates:

However, PI is used to loosely describe IPR for higher draw down and given rates:

Rate

Pw

f

AOF

Pr

PI

P.I. Only valid above the B.P.P.

Inflow Performance

A better representation is given by the Vogel IPR relationship (1968):

A better representation is given by the Vogel IPR relationship (1968):

Rate

Pw

f

Qmax

Pres

Q = Qmax * (1 - 0.2 (Pwf/Pres) - 0.8(Pwf/Pres)2 )

where Qmax = AOF

Vogel developed this relationship by best fit from numerous reservoir simulation runs.

The Vogel IPR has a long history of use in the industry with very good success.

Vogel developed this relationship by best fit from numerous reservoir simulation runs.

The Vogel IPR has a long history of use in the industry with very good success.

Q

Pw

f

Qmax

Pr

Q

Pb

QbQa

Inflow Performance

For those zones where the reservoir is above bubble point and the flowing pressure is below bubble point, some combination of the single phase (straight line) and multi-phase (curve) is necessary. Here is the Modified Vogel from Neely:

For those zones where the reservoir is above bubble point and the flowing pressure is below bubble point, some combination of the single phase (straight line) and multi-phase (curve) is necessary. Here is the Modified Vogel from Neely:

Q = Qb + (Qmax- Qb) * (1 - .2(Pwf / Pr) - .8(Pwf / Pr)2 )

Qa = Q / [(1- .2Pwf / Pb - .8(Pwf / Pb)2) + Qb]

where Qb = (1.8Qa / Pb) (Pr - Pb)

Above the bubble point

Q = PI * (Pr - Pwf)

PI = 1.8Qa/Pb = Qb / (Pr - Pb)

Rate

Inflow Performance

Many other curves to represent multi-phase inflow take the form of the gas equation:

Many other curves to represent multi-phase inflow take the form of the gas equation:

Q = C (Pr2 - Pwf

2)n

Log(Rate)

Log

(P

r2 -

Pw

f2 )

The Bureau of Mines IPR, a.k.a. the Back Pressure equation (Rawlins & Schellardt 1936).

The exponent ranges from 0.5 to 1.0

The exponent is derived from multiple rates by plotting (Pr2 - Pwf2) versus rate and finding n, the inverse of the slope; then, find “C” by substituting one test point into the formula.

The Bureau of Mines IPR, a.k.a. the Back Pressure equation (Rawlins & Schellardt 1936).

The exponent ranges from 0.5 to 1.0

The exponent is derived from multiple rates by plotting (Pr2 - Pwf2) versus rate and finding n, the inverse of the slope; then, find “C” by substituting one test point into the formula.

nTest

points

Inflow Performance

The relationships thus far do not account for turbulence caused by high flow rates.

The relationships thus far do not account for turbulence caused by high flow rates.

Re-arranging previous equations:

Oil: Pr - Pwf = 1/PI * Q = bQ

Gas: (Pr2 - Pwf

2)n = Q/C = bQ [where n=1]

Saturated Oil: same as gas

where b is some constant that varies with the equation.

Inflow Performance

Oil: Pr - Pwf = aQ2 + bQ

Gas: Pr2 - Pwf

2 = aQ2 + bQ

Saturated Oil: same as gas

where a & b are some constants that vary with the equation.

Forcheimer’s work in 1901 with high velocity flow showed that turbulent effects were significant at higher rates.

Other models can be adapted by adding a term for turbulent effects as Forcheimer suggested.

Forcheimer’s work in 1901 with high velocity flow showed that turbulent effects were significant at higher rates.

Other models can be adapted by adding a term for turbulent effects as Forcheimer suggested.

These equations have the bQ term which is related to permeability and the aQ2 term which is related to turbulent flow. The aQ2 term is referred to as the non-Darcy flow term.

The Prosper IPR model uses this form in both the Jones and Forcheimer models. Other literature attributes this theory to Forcheimer.

These equations have the bQ term which is related to permeability and the aQ2 term which is related to turbulent flow. The aQ2 term is referred to as the non-Darcy flow term.

The Prosper IPR model uses this form in both the Jones and Forcheimer models. Other literature attributes this theory to Forcheimer.

Inflow Performance

Note that the pressure varies radially from the well, starting at the Pwf and rising out

into the reservoir to the Pres.

Note that the pressure varies radially from the well, starting at the Pwf and rising out

into the reservoir to the Pres.

Radius

Pre

ssur

e

Pr

Pwf

Darcy found the following relationship for horizontal flow:

q = C A dP / L

Darcy found the following relationship for horizontal flow:

q = C A dP / L

Inflow Performance

In 1856, Darcy ran experiments to quantify the flow through porous media.

In 1856, Darcy ran experiments to quantify the flow through porous media.

dPL

A

Golan & Whitson, pg 111

By integrating Darcy’s Law from the well bore to an arbitrary radius, the following relationship is developed:

Q = k 2 h(Pe-Pw) / [ ln(re/rw)]

where rw is the well bore radius and re the cylinder radius.

By integrating Darcy’s Law from the well bore to an arbitrary radius, the following relationship is developed:

Q = k 2 h(Pe-Pw) / [ ln(re/rw)]

where rw is the well bore radius and re the cylinder radius.

Inflow Performance

A most useful expression is cylindrical or radial flow for flow into a well.

A most useful expression is cylindrical or radial flow for flow into a well.


the area for flow is the outside area of this cylinder

A = 2rh

the area for flow is the outside area of this cylinder

A = 2rhPe

Pwf

Inflow Performance

What has been described is the ideal flow through a homogeneous cylinder. Changes near the well restrict (or enhance) this flow. This can be seen at a constant flowrate as a

change in Pwf.

What has been described is the ideal flow through a homogeneous cylinder. Changes near the well restrict (or enhance) this flow. This can be seen at a constant flowrate as a

change in Pwf.


Damage

It can be explained how the productivity of the well is impaired by including another term, skin, in the Darcy flow equation in oilfield units:

Q= 0.00708 kh (Pr - Pwf) / [ B (ln(re/rw) - 0.75 + s)]

Skin, s, is a catch-all for total unexplained flow restriction in the normal radial flow equation that happen near the well bore.

It can be explained how the productivity of the well is impaired by including another term, skin, in the Darcy flow equation in oilfield units:

Q= 0.00708 kh (Pr - Pwf) / [ B (ln(re/rw) - 0.75 + s)]

Skin, s, is a catch-all for total unexplained flow restriction in the normal radial flow equation that happen near the well bore.

Inflow Performance

By eliminating the other terms in Darcy’s Law, the extra pressure drop at a given flow rate seen in the well as a result of skin can be derived by:

Ps = s Q (141.2 B / (kh))

By eliminating the other terms in Darcy’s Law, the extra pressure drop at a given flow rate seen in the well as a result of skin can be derived by:

Ps = s Q (141.2 B / (kh))


Radius

Pre

ssur

e

Lower

Pwf

dPs

Damage

Inflow Performance

Gas also is described by Forcheimer’s equation:

Pr2 - Pwf

2 = aQ2 + bQ

Also Bg = V/Vsc = PscTZ/(PTsc). Plugging this in

and converting units gives:

Gas also is described by Forcheimer’s equation:

Pr2 - Pwf

2 = aQ2 + bQ

Also Bg = V/Vsc = PscTZ/(PTsc). Plugging this in

and converting units gives:


Q = 703 x 10-6 kh (Pr2 - Pwf

2) /

[ TZ (ln(re/rw) - 0.5 (CA/31.62) - 0.75 + s +DQ)]

This is the Jones equation for Gas. This is the Jones equation for Gas.

D = 2.222 x 10-18 kh g / ( rw hp2)

where hp is the completed h in ft and

= 2.73 x 1010 ka-1.1045

where ka is the near

wellbore perm (same as for oil)


D = 2.222 x 10-18 kh g / ( rw hp2)

where hp is the completed h in ft and

= 2.73 x 1010 ka-1.1045

where ka is the near

wellbore perm (same as for oil)


Inflow Performance

Darcy skin or laminar flow skin “s”, and DQ, the non-Darcy skin, are in an equation to describe the pressure rate relationship for oil and for gas.

So far, so good.

Now, s and D need to model all of the things that can happen to cause non-ideal Darcy flow.

s = si for all that causes non-ideal laminar flow

Examples are:• near well bore damage (like drilling mud / cement filtrate)

• partial penetration of the zone (hp < h)

• perforation crushed zone (kp < k)

• blockage due to condensate in pore spaces on gas

condensate well

• perforation geometry (phasing, length, etc.)

• gravel pack (pressure drop in gravel-pack sand)

Darcy skin or laminar flow skin “s”, and DQ, the non-Darcy skin, are in an equation to describe the pressure rate relationship for oil and for gas.

So far, so good.

Now, s and D need to model all of the things that can happen to cause non-ideal Darcy flow.

s = si for all that causes non-ideal laminar flow

Examples are:• near well bore damage (like drilling mud / cement filtrate)

• partial penetration of the zone (hp < h)

• perforation crushed zone (kp < k)

• blockage due to condensate in pore spaces on gas

condensate well

• perforation geometry (phasing, length, etc.)

• gravel pack (pressure drop in gravel-pack sand)

Inflow Performance

And

D = Di for all things that cause turbulent flow

Examples are:

• turbulent flow in the reservoir beyond the damaged (near wellbore) zone

• turbulent flow in the damaged zone

• turbulent flow in the crushed zone around the perforations

• turbulent flow in the gravel pack

And

D = Di for all things that cause turbulent flow

Examples are:

• turbulent flow in the reservoir beyond the damaged (near wellbore) zone

• turbulent flow in the damaged zone

• turbulent flow in the crushed zone around the perforations

• turbulent flow in the gravel pack

Inflow Performance

Remember that

s = si for all things that cause skin

D = Di for all that causes turbulent flow

How do all these add up ?

Remember that

s = si for all things that cause skin

D = Di for all that causes turbulent flow

How do all these add up ?

ideal well modelideal well model

skin effectskin effect

turbulence effect

turbulence effect

PVT properties and two-phase

flow effect

PVT properties and two-phase

flow effect

Actual IPRActual IPR

estimation of inflow begins with pressure transient analysis (PTA) which yield estimates

of perm and skin

estimation of inflow begins with pressure transient analysis (PTA) which yield estimates

of perm and skin

Inflow Performance

data can yield various models and interpretations

data can yield various models and interpretations

Comparison of IPR models

0

1000

2000

3000

4000

5000

6000

7000

8000

0 50 100 150 200

Gas (mmscfd)

FB

HP

(ps

i)

ipr-jones, s=7.7, k=50

dpskin-jones,s=7.7,k=50

ipr-PE, s=20, k=50

dpskin-PE, s=20, k=50

ipr-PE, S=7.7, k=33

dpskin-PE, s=7.7, k=33

Inflow Performance

IPR’s

p skin models

Inflow Performance

Comparison Of Completion Performance Among Wells

Comparison Of Completion Performance Among Wells

Bob Hite 4/99

Questions:

What does the pressure at zero rate indicate on the Inflow plot?

What is meant by drawdown?

To get more rate through the Inflow part of the well what has to happen to the pressure at the perforations?

A 10000’ deep well’s flowing bottom hole pressure measured 2990 psi while producing at a rate of 5 bbls per day. The reservoir pressure is 3000 psi. What is the PI?

If the flowing bottom hole pressure in the well mentioned above is lowered to 2000 psi, what would the production rate be?

Bonus: How could the flowing bottom hole pressure be lowered to achieve this production rate?

Questions:

1. What does the pressure at zero rate indicate on the Inflow plot?

2. Sketch the curves below.

Increased PI Reservoir Pressure Decreased

Bubblepoint = 0 Stimulated

3. Calculate the following using a Vogel relationship, assuming the bubble point is 3000 psi. There is one well test measurement where the fbhp = 1800, the reservoir pressure = 2000, the liquid flow rate is 500 bpd, the water cut is 20%.

What is the AOF?

What is the flow rate at fbhp = 1000?

Let’s have a look at the plumbing,

a.k.a. the

Outflow System

Let’s have a look at the plumbing,

a.k.a. the

Outflow System

From The Inflow Model

From The Inflow Model

Well bore

Flowline

SeparatorChoke

Outflow

Picture yourself at the bottom of a flowing well. This time, look up.



Picture yourself at the bottom of a flowing well. This time, look up.



Outflow Performance

The outflow system takes energy from the inflow system and uses that energy (plus artificial lift, if any) to get the total fluid rate to the surface.

For the outflow system, the higher the pressure at the bottom of the well, the more liquid can be pushed from the well (in order to overcome friction).

The outflow system takes energy from the inflow system and uses that energy (plus artificial lift, if any) to get the total fluid rate to the surface.

For the outflow system, the higher the pressure at the bottom of the well, the more liquid can be pushed from the well (in order to overcome friction).

Outflow Performance

Rate

Pw

f

Outflow Performance

Name this curve. Please!

This curve is known by many names

Several names are:

• VLP (vertical lift performance, in Prosper)

• Tubing Performance Curve (Industry)

• Intake Performance Curve (in WePS)

• Outflow curve (in contrast to the inflow curve, WinGLUE).

Name this curve. Please!

This curve is known by many names

Several names are:

• VLP (vertical lift performance, in Prosper)

• Tubing Performance Curve (Industry)

• Intake Performance Curve (in WePS)

• Outflow curve (in contrast to the inflow curve, WinGLUE).

Rate

Pw

f

Another convenient view of the outflow is on a depth vs pressure graph. These are the pressures in the tubing.

Another convenient view of the outflow is on a depth vs pressure graph. These are the pressures in the tubing.

Outflow Performance D

epth

Pressure

This curve is known as:

• Production Pressure model (WinGLUE)

• Gradient curve (Prosper)

• [Pressure] Traverse (WePS)

This curve is known as:

• Production Pressure model (WinGLUE)

• Gradient curve (Prosper)

• [Pressure] Traverse (WePS)

Pwf

Pftp

‘Gradient’ refers to the change in pressure / the change in depth.

‘Gradient’ refers to the change in pressure / the change in depth.

Outflow Performance D

epth

Pressure

.2 psi/ft

.45 psi/ft

0.433 psi/ft ==> SG = 1.0 ==> 8.33 ppg0.433 psi/ft ==> SG = 1.0 ==> 8.33 ppg

The gradient typically gets smaller as gas expands near the top of the well. Sometimes friction here increases very rapidly and the gradient gets higher.

The gradient typically gets smaller as gas expands near the top of the well. Sometimes friction here increases very rapidly and the gradient gets higher.

Outflow Performance

Actually, the VLP is simply a display of the pressures from a series of gradient calculations.

Actually, the VLP is simply a display of the pressures from a series of gradient calculations.

Dep

th

Pressure

ID 2.441”

Water Cut 40%

GOR 1000

100 bpd200 bpd

400 bpd800 bpd

1200 bpd

Rate

Pw

f

Bottomhole depth

VLP curve

Outflow Performance

How are outflow pressures calculated ?

The pressures in this part of the system are determined by calculating the change in pressure over the length.

In a single phase liquid over short distances, this can be determined with an equation and done in one step.

Because the phase fractions are changing along with PVT in multi-phase flow, no analytical solution is practical.

The calculation become enormously tedious and iterative.

For this reason computer programs have been employed since the first attempts were made to model the outflow in wells.

How are outflow pressures calculated ?

The pressures in this part of the system are determined by calculating the change in pressure over the length.

In a single phase liquid over short distances, this can be determined with an equation and done in one step.

Because the phase fractions are changing along with PVT in multi-phase flow, no analytical solution is practical.

The calculation become enormously tedious and iterative.

For this reason computer programs have been employed since the first attempts were made to model the outflow in wells.

Outflow Performance

So, what is inside a computer program to make the outflow calculations?

So, what is inside a computer program to make the outflow calculations?

Dep

th

Pressure

ID 2.441”

Water Cut 40%

GOR 1000100 bpd

200 bpd

400 bpd800 bpd

1200 bpd

Outflow Performance

As flow passes through a pipe, the pressure inside changes.

These changes can be described by three components:

• Gravity

• Friction

• Acceleration

As flow passes through a pipe, the pressure inside changes.

These changes can be described by three components:

• Gravity

• Friction

• Acceleration

Outflow Performance

Bubble Slug Transi-tion

Mist

Vertical flow regimesVertical flow regimes

Acceleration Friction Gravity

Acceleration Friction Gravity

Outflow Performance

at the top (lower pressures = higher velocities), friction is

significant

at the top (lower pressures = higher velocities), friction is

significant

at the bottom, pressure is dominated by gravity

at the bottom, pressure is dominated by gravity

Outflow Performance

Minimum Stable RateIn multiphase systems, especially where the density of the phases is great, (gas and liquid), and especially at rates which are low for a given size of tubing, gas slip through the liquid will be great. Consequently, total liquid rate will fall causing a significant turn up in the outflow curve.

Minimum Stable RateIn multiphase systems, especially where the density of the phases is great, (gas and liquid), and especially at rates which are low for a given size of tubing, gas slip through the liquid will be great. Consequently, total liquid rate will fall causing a significant turn up in the outflow curve.

Rate

Pw

f

Minimum Stable Rate

Unstable Flow Region

The minimum in the curve is referred to as the minimum stable rate. Understand that this is (at best) a rough approximation (pressure and rate) of

a very complex phenomena.

The minimum in the curve is referred to as the minimum stable rate. Understand that this is (at best) a rough approximation (pressure and rate) of

a very complex phenomena.

Questions:

1. At the top of a high rate well, which pressure drop component dominates? What can you do to minimise this effect?

2. Which of the following can lower the flowing bottom hole pressure in a well? (think about the effect on each of the components of pressure drop)

Lower GLR

Lower flowing tubing pressure (FTP)

Smaller ID tubing

Lower water cut

Lower production rate

Larger choke size in the wellhead

Well Performance is about understanding how to Optimize the system.

The system is comprised of components; each component can be modeled by itself.

The components can be connected to create a system model.

Well Performance is about understanding how to Optimize the system.

The system is comprised of components; each component can be modeled by itself.

The components can be connected to create a system model.

Reservoir

Wellbore

Flowline

SeparatorChoke

Completion

The System

Determining the effect on the system requires modeling the upstream and downstream parts of the system, i.e. - the inflow and the outflow.

Determining the effect on the system requires modeling the upstream and downstream parts of the system, i.e. - the inflow and the outflow.

Inflow

Outflow

The System

The inflow part of the system can be expressed as a function:

Pwf = Pr - (Q / PI)

Pr is the boundary of the inflow model.

All the IPR models are represented by a function that relates Pwf to Q.

Any mathematical model may be written in more general form:

Pwf = f (Upstream Boundary, Q)

The inflow part of the system can be expressed as a function:

Pwf = Pr - (Q / PI)

Pr is the boundary of the inflow model.

All the IPR models are represented by a function that relates Pwf to Q.

Any mathematical model may be written in more general form:

Pwf = f (Upstream Boundary, Q)

The System

Rate

Pw

f

The outflow part of the system cannot be expressed by a simple analytical function.

However, all flow correlations can be expressed as a function:

Pwf = function of (Downstream Boundary, Q)

where the Downstream Boundary is either the separator, or, ignoring the flowline, Pftp.

The outflow part of the system cannot be expressed by a simple analytical function.

However, all flow correlations can be expressed as a function:

Pwf = function of (Downstream Boundary, Q)

where the Downstream Boundary is either the separator, or, ignoring the flowline, Pftp.

The System

Rate

Pw

f

The System

Two equations, two unknowns . . .

Knowing that only one pressure can exist in one point in space, then Pwf must be equivalent in

each equation.

It would be nice to solve this system of equations by:

f(Upstream Boundary,Q) = Pwf = f(Downstream Boundary,Q)

However, the outflow equation can’t really be expressed that way, so the problem is solved graphically by finding the common point intersection of the two curves:

Two equations, two unknowns . . .

Knowing that only one pressure can exist in one point in space, then Pwf must be equivalent in

each equation.

It would be nice to solve this system of equations by:

f(Upstream Boundary,Q) = Pwf = f(Downstream Boundary,Q)

However, the outflow equation can’t really be expressed that way, so the problem is solved graphically by finding the common point intersection of the two curves:

System Solution

Here is an enormously powerful tool for decision making.

Here is an enormously powerful tool for decision making.

The System

RateRate

Pw

f

Expected Pwf

Expected Pwf

Expected Rate

Expected Rate

110BLWaring - PT1502-inflow.ppt

. . . end of section

PTO CHAPTER 04A Well Inflow and Outflow

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Transcript of PTO CHAPTER 04A Well Inflow and Outflow