PETE 331-Session 2-07_10_2011

PETE 331

Petroleum Production Engineering I

Session 2 – 07.10.2011

PETE - 331

Course Outline:

• Introduction to Petroleum Production SystemsBasic Oilfield Operations and Nomenclature Components of Production Systems Role of Production Engineer in Field Life Cycle

• Reservoir DeliverabilityFlow RegimesInflow Performance Relationship

• Vertical and Horizontal Flow in Pipes

• Choke Performance

• Well Deliverability

• Production System Optimization-Nodal Analysis

07.10.2011 Can S. Bakiler 2


Reservoir Deliverability

Objective:

• Understand the flow regimes in the reservoir and review the equationswhich describe the fluid flow for each flow regime.

• Understand the Inflow Performance Curve and its use in ProductionEngineering.

• Learn how to generate the Inflow Performance Curve for single phaseand two phase flow in the reservoir.

• Learn to generate Inflow Perfromance Curve for multi layered reservoirs.


PETE – 331 Reservoir Deliverability

References for Reservoir Deliverability

Main Text:

B. Guo, W.C.Lyons, A.Ghalambor, Petroleum Production Engineering, Elsevier, 2007, Chapter 3, pp 29 to 43

Additional References:

• M.J Economides, A.D.Hill, C.E.Economides, Petroleum Production Systems, Prentice Hall, 1994, Chapter 2 and 3, pp 17 to 55.

• SPE Petroleum Engineering Handbook, Production Operations Engineering, Volume 4, 2007




Reservoir Deliverability is :

Oil or gas production rate which the reservoir can deliver at a given bottom hole flowing pressure.

Important:

Reservoir Deliverability alone does not tell how much the well can produce. It only gives the flow capacity of the reservoir into the wellbore.The reservoir deliverability needs to be coupled with well deliverability to calculate the actual production rate from the well.

The well deliverability and the coupling of the well deliverability with reservoir deliverability will be covered in future lectures.


T

PETE – 331 Simplified Schematic Production System for a Single Flowing Oil Well

pr, ppbhf

pwhf

Gas

pr, p = Reservoir pressure, average reservoir pressurepe = Pressure at the reservoir boundarypbhf = Bottom hole flowing pressurepwhf = Wellhead flowing pressurepsp = Separator pressurepst = Stock Tank pressurePpl = Pipeline Pressureq = Oil Production Rate


Separatorpsp

Stock Tank

M

M

Oil

Water

pst

Pump

Sales

qpe


Why do we need to know about Flow Regimes and Reservoir Deliverability as a Production Engineer? (1/3)

Understanding of the flow regimes helps us to:

• Identify different flow periods (transient, steady-state, pseudo-steady-state).

• Distinguish between stabilized and unstabilized flowconditions.

• Use the correct equation derived for the specific flow regimethat takes place in the flow period we are investigating, in our engineering calculations.




Understanding of the Reservoir Deliverability (Inflow Performance Relation) helps us to:

• Decide how much the production rate can be increased if wedecrease the flowing bottom hole pressure by artificial lift methods.

• Estimate the maximum production rate without exceeding the bubblepoint pressure at bottom hole flowing conditions.

• Estimate the effect of two phase flow on the production rate.

• Understand the contribution of different layers to production and potential forcrossflow.


07.10.2011 Can S. Bakiler 10


Understanding of the Reservoir Deliverability (Inflow Performance Relation) helps us to:

• Evaluate the success of stimulation treatments (acidizing, fracturing) by testing the reservoir deliverability (productivity index) before and after the treatments.

• Control any reduction in deliverability (productivity index) due to anydamage around the wellbore (sand, asphaltene deposition, scalingetc) by repeating the deliverability tests during the production.

• Predict the change in well deliverability (productivity index) with time,due to reservoir pressure decrease.


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Flow Regimes


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Flow Regimes in the Reservoir:

• Transient Flow

• Steady State Flow

• Pseudo-Steady State Flow


07.10.2011 Can S. Bakiler 13

Transient Flow:

Flow regime where the radius of pressure wave propagation from wellbore has not reached any boundaries of the reservoir.

In the transient pressure analysis, the reservoir is treated as an infinite acting reservoir, because the reservoir boundary is not reached yet.

t3t2t1

)(tftp

=DD

(Transient flow regime is valid until the first boundary is reached, at time = t3)

At any point within the radius of wave propagation (also called radius of investigation), the pressure is changing (decreasing) as a function of time.


07.10.2011 Can S. Bakiler 14

krct eto

pss

2

200,1 fm=

Stabilization Time:

Flow time required for the radius of the pressure wave to reach the circular boundary.

In determining the stabilized bottom hole flowing pressure (pbhf) for a well corresponding to a flow rate, the flow rate must be maintained until the producing time exceeds the stabilization time (until the transient flow period is finished).

If the stabilization time is not reached, measured the bottom hole flowing pressure will be higher than the stabilized pressure. This will give optimistic results for the calculated productivity index of the well.

where tpss = time for the end of transient flow period, hrsf = porosity, fractionmo = oil viscosity, cpct = total compressibility, psia-1re = effective drainage radius, ftk = permeability, md


07.10.2011 Can S. Bakiler 15

Transient Flow:

For single phase oil flow in the reservoir, following analytical solution is used for describing the transient flow period.

The equation gives the bottom hole flowing pressure of the well ‘pbhf’, when the well is producing oil with a constant flow rate ‘q’.

÷÷ø

öççè

æ+-+´-= S

rckt

khqBpp

wto

ooibhf 87.023.3loglog6.162

2fmm

where

pwf = Flowing bottom hole pressure of the well, psia f = porosity, fractionpi = Initial reservoir pressure, psia ct = total compressibilityq = Oil production rate, stb/d rw = wellbore radius to sandface, ftmo = Viscosity of oil, cp S = skin factork = effective horizontak permeability to oil, md Log = 10 based logarithmh = reservoir thickness, ftt = flow time, hour


07.10.2011 Can S. Bakiler 16

Transient Flow:

Oil wells are normally operated with constant bottom hole pressure (or constant well head pressure), rather than constant rate. Therefore, it is more convenient to use an equation which gives the oil production rate for a constant bottom hole pressure.

The equation developed for constant bottom hole pressure is:

( )

÷÷ø

öççè

æ+-+

-=

Src

ktB

ppkhq

wtooo

bhfi

87.023.3loglog6.162 2fmm


07.10.2011 Can S. Bakiler 17

Transient Flow:

For gas wells, the transient equation is developed as:

where qg = Gas Production rate, Mscf/dT = Temperature, oRz = Gas compressibility factor m(p) = Real gas pseudo-pressure defined as:

( ) ( )( )

÷÷ø

öççè

æ+-+

-=

Src

ktT

pmpmkhq

wto

bhfig

87.023.3loglog1638 2fm

( ) dpzppm

p

pbò=m2


Steady-State Flow:

Flow regime after the transient flow period is finished, if the radius of pressure wave propagation from wellbore has reached a constant pressure boundary.

During steady state flow, pressure at any point in the reservoir remains constant.

Sketch of a reservoir with constant pressure boundary (figure from Guo et al, 2007)

zerotp

=DD

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At any point within the drainage radius of the well, the pressure is constant (does not change with time).


07.10.2011 Can S. Bakiler 19

Steady-State Flow:

Examples for Constant Pressure Boundaries:The constant pressure boundary may be because of an aquifer (water influx) or water/gas injection wells which maintain a constant pressure at the well’s drainage boundaries.

Injectors keeping the pressure constant at drainage boundary of the producer:

Aquifer (water influx) keeping the pressureconstant at drainage boundary of the producer:


07.10.2011 Can S. Bakiler 20

( )

÷÷ø

öççè

æ+

-=

SrrB

ppkhq

w

eoo

bhfe

ln2.141 m

Steady-State Flow:

For steady state flow condition because of a circular constant pressure boundary at a distance re from the wellbore, the following relation can be used for single phase oil flow :

‘ln’ is natural logarithm.

re

pe

pbhf

Constant pressure boundary, pe at re


Pseudo-Steady-State Flow:

Flow regime after the transient flow period is finished and the radius of pressure wave propagation from wellbore has reached all of the no flow boundaries.

During pseudo-steady-state flow, pressure at any point in the reservoir declines at a constant rate.

Sketch of a reservoir with no flow boundaries(figure from Guo et al, 2007)

Constant=DDtp

Decrease of pressure with time

07.10.2011 Can S. Bakiler 21

At any point within the drainage radius of the well, the pressure is decreasing with a constant rate.



Examples for No-Flow Boundaries:

A ‘No Flow’ boundary can be a sealing fault, pinch out of pay zone or boundaries of the drainage areas of production wells.

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Sealing faultPinchout

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(figure from Matthew and Russel, Pressure Build-up and Flow Tests in Wells, 1967)


Examples for No-Flow (Drainage) Boundaries:

No flow boundaries between wells : In a homogeneous system with constantthickness, each well drains an area proportional to its rate.

07.10.2011 Can S. Bakiler 24


For pseudo steady state flow condition because of a circular no-flow boundary at a distance re from the wellbore, the following relation can be used for single phase oil flow :

‘ln’ is natural logarithm.

re

pe

pbhf

( )

÷÷ø

öççè

æ+-

-=

SrrB

ppkhq

w

eoo

bhfe

21ln2.141 m


07.10.2011 Can S. Bakiler 25


Because the pe is not known at any given time, the following expression using the average reservoir presure is more useful:

( )÷÷ø

öççè

æ+-

-=

SrrB

ppkhq

w

eoo

bhf

43ln2.141 m

For Gas Wells:

If a gas well is located at the center of a circular drainage area with no-flow boundaries, the equation for the pseudo-steady state flow is:

( ) ( )( )÷÷ø

öççè

æ++-

-=

gw

e

bhfg

DqSrrT

pmpmkhq

43ln424,1

where = average reservoir pressure, psia p

where D = non-Darcy flow coefficient, d/Mscf


07.10.2011 Can S. Bakiler 26


If the no flow boundaries delineate a non-circular shape, the following equation, which contains a shape factor (CA), the pseudo –steady state solution in given as:

( )

÷÷ø

öççè

æ+

-=

SrCAB

ppkhq

wAoo

bhf

24ln

212.141

gm

where A = Drainage Area, ft2g = 1.78 (Euler’s Constant)CA = Drainage area shape factor (31.6 for a circular boundary)


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Shape Factors (CA) for different Reservoir Shapes and Well Locations:

(from Guo et al, 2007)


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Horizontal Wells:

The transient flow, steady state flow and pseudo-steady state flow can also exist in reservoirs penetrated by horizontal wells.

Most widely used relationship for the flow equation was presented by Joshi (1988) for steady state flow of oil in the horizontal plane and pseudo-steady state flow in the vertical plane:

( )( )

( )

V

Hani

He

aniw

aniani

bhfeH

kkI

LrLa

where

IrhI

LhI

LLaaB

pphkq

=

÷÷ø

öççè

æ÷ø

öçè

æ++=

÷÷

ø

ö

çç

è

æ÷÷ø

öççè

æ+

+÷÷

ø

ö

çç

è

æ -+

-=

4

22

2/41

21

2

1ln

2/2/ln2.141 m where

kH = average horizontal permeability, mdkV = vertical permeability, mdreH = radius of drainage area, ftL = length of horizontal borehole (L/2<0.9reH),ft


07.10.2011 Can S. Bakiler 29

Inflow Performance Relationship


07.10.2011 Can S. Bakiler 30

Inflow Performance Relationship (IPR) is used for evaluating reservoir deliverability in production engineering.

The IPR Curve is a graphical presentation of the relation between the flowing bottom hole pressure (pbhf) and liquid production rate (q).

The magnitude of the inverse slope of the IPR curve is called Productivity Index (PI or J).

p bhf

(p

sia)

qo (stb/day)

5000

4000

3000

2000

1000

0

0 200 400 600 800 1000

Straight line (constant J) for single phase (oil) flow

J is not constant for two phase (oil+gas) flow

)( bhfe ppqJ

-=


07.10.2011 Can S. Bakiler

pr

re re

pr

Producing Well

re

pbhf

Single Phase Liquid (Oil) Flow:

Average Reservoir Pressure and Bottom Hole Flowing Pressure are above the Bubble Point Pressure.

Therefore, second phase (gas) does not come out of solution. All of the flow is single phase liquid.

pr

pbhf

pbp

Single Phase Flowp > pbp


31

07.10.2011 Can S. Bakiler 32

IPR for Single (Liquid) Phase Reservoirs:

In undersaturated oil reservoirs, if the pressure does not fall below the bubble point in the reservoir and at the bottom hole, single phase (oil) flow takes place every where in the reservoir, including the near wellbore area.

In such systems, Productivity Index can be defined for radial transient flow around a vertical well as:

( )÷÷ø

öççè

æ+-+

=-

=

Src

ktB

khppqJ

wtooo

bhfi 87.023.3loglog6.162 2fmm

For radial steady state flow around a vertical well:

( )÷÷ø

öççè

æ+

=-

=S

rrB

khppqJ

w

eoo

bhfe ln2.141 m


07.10.2011 Can S. Bakiler 33


For pseudo steady state flow around a vertical well in a circular drainage area:

( )÷÷ø

öççè

æ+-

=-

=S

rrB

khppqJ

w

eoo

bhf

43ln2.141 m

For pseudo steady state flow around a vertical well in a non-circular drainage area:

( )÷÷ø

öççè

æ+

=-

=

SrCAB

khppqJ

wAoo

bhf2

4ln212.141

gm


07.10.2011 Can S. Bakiler 34


For steady state flow in horizontal plane and pseudo steady state flow invertical plane around a horizontal well :

( ) ( )( ) ÷

÷

ø

ö

çç

è

æ÷÷ø

öççè

æ+

+÷÷

ø

ö

çç

è

æ -+=

-=

1ln

2/2/ln2.141

22

aniw

aniani

H

bhfe

IrhI

LhI

LLB

hkppqJ

aam



pr

re re

pr

pbhf

Two Phase (Oil + Gas) Flow:

Average Reservoir Pressure and Bottom Hole Flowing Pressure are below the Bubble Point Pressure.

Therefore, second phase (gas) always exists in the reservoir. All of the flow in the reservoir is two phase (Oil + Gas).

pbp

Two Phase Flowp < pbp

Producing Well

re

pr

pbhf


35

07.10.2011 Can S. Bakiler 36

IPR for Two Phase (liquid +gas) Reservoirs: (1/3)

The average reservoir pressure ( p ) for two phase reservoirs are at or below the bubble point pressure. As soon as the production begins and pressure drops in the reservoir, gas comes out of solution. Two phases (gas and oil) exist everywhere in the reservoir and near wellbore area.

When two phase flow takes place, the oil rate is less than the oil rate for single phase (oil) flow because:

1. Free gas occupies some portion of the pore space and this reduces the oil flow (reduced oil relative permeability).

2. As the gas leaves the oil, the remaining oil becomes heavier (more viscous) and it is more difficult to flow.


07.10.2011 Can S. Bakiler 37


The reduction in oil rate makes the IPR curve deviate from the lineartrend after the bubble point pressure is reached.

p bhf

(p

sia)

5000

4000

3000

2000

1000

0

0 200 400 600 800 1000

qo (stb/day)

pbp

Undersaturated Reservoir (pr>pbp)

pr > pbp

pr < pbp

Decrease in qo due to two phase flow.



38

Decrease in qo due to two phase flow.

p bhf

(p

sia)

5000

4000

3000

2000

1000

0

0 200 400 600 800 1000

qo (stb/day)

pbp

Saturated Reservoir (pi <= pbp)


If the reservoir is a saturated reservoir (reservoir pressure is equal to or lessthan bubble point pressure), there is no linear section in IPR curve.


pr < pbp

38

07.10.2011 Can S. Bakiler 39

IPR for Two Phase (liquid +gas) Reservoirs:

Equations for modeling two phase reservoirs are empirical (based on observations).

Vogel’s equation is widely used for two phase flow:

úúû

ù

êêë

é÷÷ø

öççè

æ-÷÷

ø

öççè

æ-=

2

max 8.02.01pp

pp

qq bhfbhf

or,

úúû

ù

êêë

é-÷÷

ø

öççè

æ-= 18081125.0

maxqqppbhf

Where qmax is the maximum value of reservoir deliverability (AOF).

For Pseudo-steady state flow: 8.1

*

maxpJq =


07.10.2011 Can S. Bakiler 40

Absolute Open Flow (AOF) Potential:

AOF Potential of an oil or gas well is the expected production of the well when the flowing bottom hole pressure is zero (pbhf=0).

Practically, zero pressure can not be achieved as the bottom hole flowing pressure, therefore AOF is the theoretical maximum rate which a well is capable of producing.

p bhf

(p

sia)

5000

4000

3000

2000

1000

0

0 200 400 600 800 1000

AOF

qo (stb/day)


07.10.2011 Can S. Bakiler 41

IPR for Two Phase (liquid +gas) Reservoirs:

Fetkovich’s empirical equation for two phase flow:

n

bhf

pp

qqúúû

ù

êêë

é÷÷ø

öççè

æ-=

2

max 1

or,

Where C and n are empirical constants and:

n

bhfppCq ÷øöç

èæ -= 2

2

np

qC 2max=

Used for gas reservoirs

Fetkovich’s Equation is more accurate than Vogel’s equation for IPR modelingand prediction.



pr

re re

pr

pbhf

Partial Two Phase (Oil + Gas) Flow:

Average Reservoir Pressure is above the Bubble Point Pressure (Undersaturated Reservoir). Bottom Hole Flowing Pressure is below the Bubble Point Pressure.

Therefore, there are two regions in the reservoir. Before the pressure falls below the bubble point pressure, one phase exists in the reservoir. After the pressure falls below the bubble point, gas comes out of oil and there is two phase (oil+gas) flow.

pbp


TwoPhaseFlowp < pbp


Producing Well

re

pr

pbhf


4242

07.10.2011 Can S. Bakiler 43

IPR for Partial Two Phase Oil Reservoirs:

If the reservoir pressure is above the bubble point pressure but the flowing bottom hole pressure is below the bubble point pressure, some of the flow in the reservoir is single phase (oil), but some of the flow is two phase (oil+gas).

In such reservoirs, the linear (one phase) IPR line can be combined with Vogel’s IPR model for the two phase flow .

According to the linear IPR model, the flow rate at bubble point is:

)(* bpbp ppJq -=


07.10.2011 Can S. Bakiler 44


Based on Vogel’s IPR model, the additional flow rate caused by a pressure drop below the bubble point pressure is expressed as:

úú

û

ù

êê

ë

é

÷÷ø

öççè

æ-÷

÷ø

öççè

æ-=D

2

8.02.01bp

bhf

bp

bhfv p

ppp

qq

Therefore, the flow rate when the bottom hole flowing pressure (pbhf) is lessthan the bubble point pressure (pbp) is expressed as:

úú

û

ù

êê

ë

é

÷÷ø

öççè

æ-÷

÷ø

öççè

æ-+=

2

8.02.01bp

bhf

bp

bhfvbp p

ppp

qqq


07.10.2011 Can S. Bakiler 45


Because

The final equation for the flow rate, when the bottom hole flowing pressure (pbhf) is less than the bubble point pressure (pbp) becomes:

( )úú

û

ù

êê

ë

é

÷÷ø

öççè

æ-÷

÷ø

öççè

æ-+-=

2** 8.02.01

8.1 bp

bhf

bp

bhfbpbp p

ppppJ

ppJq

8.1

*

maxpJq =


07.10.2011 Can S. Bakiler 46

pbhf

q

pbp

pi

qb AOF

8.1

*b

vpJq =

( )bpbp ppJq -= *

Generalized Vogel IPR model for partial two phase reservoirs:


07.10.2011 Can S. Bakiler 47

Construction of IPR Curves Using Test Points:

The IPR curves can be theoretically constructed using reservoir, fluid and well parameters such as:

f, k, h, ct, B, m, re, rw, S.

Most of the time, these parameters are not available and need to be estimated.

Therefore, most reliable method to obtain IPR relations is using actual well test data where the well is produced at different rates and the stabilized bottom hole flowing pressures are recorded.


07.10.2011 Can S. Bakiler 48

Calculating the Productivity Index using Test Points:

The productivity index can be back-calculated from the test data.

For a Single Phase (undersaturated oil) reservoir:

( )1

1*

bhfppqJ

-=

where q1 = Tested production ratepbhf1 = Tested flowing bottom hole pressurep = Average reservoir pressure (from Shut-in Data)


07.10.2011 Can S. Bakiler 49

Calculating the Productivity Index using Test Points:

For a Partial Two Phase Reservoir:

When the tested bottom hole flowing pressure is above the bubble point pressure (single phase flow):

When the tested bottom hole flowing pressure is below the bubble point pressure (two phase flow):

( )1

1*

bhfppqJ

-=

( )÷÷÷

ø

ö

ççç

è

æ

úú

û

ù

êê

ë

é

÷÷ø

öççè

æ-÷

÷ø

öççè

æ-+-

=2

11

1*

8.02.018.1 bp

bhf

bp

bhfbpbp p

pppp

pp

qJ


07.10.2011 Can S. Bakiler 50

Composite IPR of Layered Reservoirs:

Most of the reservoirs are layered. Instead of having a single producing zone with constant rock and fluid properties, multiple layers with different properties contribute to the well flow rate.

The observed well flow rate is based on the contribution of each layer, depending on their rock and fluid properties and pressures.

If the flowing bottom hole pressure is below the reservoir pressure of each layer, each layer contributes to flow based on their individual properties.

If the flowing bottom hole pressure is above the reservoir pressure of any of the layers, cross flow may occur and some of the fluid produced from high permeability layers may be injected into the low pressure layer, causing loss in the well’s total production rate.


07.10.2011 Can S. Bakiler 51


Impermeable Barriers

k=10 md

k=100 md

k=1 md

A

B

C

A BC

Composite IPR(A+B+C)

Pr=1600 psi

Pr=1250 psi

Pr=2000 psi

pbhf

q

Example for Two Phase Flow


Example 1

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Impermeable Barriers

k=10 md

k=100 md

k=1 md

A

B

C

A BC

Composite IPR (A+B+C)

Pr=2000 psi

Pr=2000 psi

Pr=2000 psi

pbhf

q

Example for Single Phase Flow


Example 2

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Composite IPR Model can be generated for following assumptions:1. Pseudo-steady state flow in all the layers2. Formation fluids of all layers have same properties3. Pressure losses in the wellbore between the layers are negligible4. IPR of each layer is known (by individually testing each layer, or by

calculation using rock and fluid data of the layers)

For steady flow from a well, material balance dictates:Addition of Mass Flow rate from all layers = Mass flow rate at the wellhead

or

whwh

n

iii qq rrå

=

=1

where ri = density of the fluid from/into layer iqi = flow rate from/into layer irwh = density of fluid at wellheadqwh = flow rate at wellheadn = number of layers


07.10.2011 Can S. Bakiler 54


Fluid flow from reservoir to wellbore is indicated by positive qi.

Fluid flow from wellbore to reservoir is indicated by negative qi.

Ignoring density change from bottom hole to wellhead, the previous equation reduces to:

wh

n

ii qqå

=

=1

or,

( ) wh

n

ibhfii qppJå

=

=-1

where Ji is the Productivity Index of layer i.

(Total well production rate is the summation of production rates from individual layers)


07.10.2011 Can S. Bakiler 55


For Single Phase Liquid Flow:

(Undersaturated reservoirs - Reservoir Pressure and bottom hole flowing pressure are both above the bubble point).

( ) wh

n

ibhfii qppJå

=

=-1

*


07.10.2011 Can S. Bakiler 56


For Two Phase Flow:

(Saturated reservoirs - Reservoir Pressure and bottom hole flowing pressure are both below the bubble point. Two phase flow takes place in the reservoir).

wh

n

i i

bhf

i

bhfii qpp

pppJå

=

=úúû

ù

êêë

é÷÷ø

öççè

æ-÷÷

ø

öççè

æ-

1

2*

8.02.018.1


07.10.2011 Can S. Bakiler 57


For Partial Two Phase Flow:

(Under Saturated reservoirs - Reservoir Pressure is above the bubble point but bottom hole flowing pressure is below the bubble point. Both single and two phase flow takes place in the reservoir).

( ) wh

n

i bpi

bhf

bpi

bhfbpibpiii q

pp

ppp

ppJå=

=ïş

ïıü

ïî

ïíì

úú

û

ù

êê

ë

é

÷÷ø

öççè

æ-÷

÷ø

öççè

æ-+-

1

2

* 8.02.018.1


07.10.2011 Can S. Bakiler 58

Predicting Future IPR:

Reservoir deliverability declines with time for transient flow and pseudo steady state flow regimes.

Transient flow: The decline in reservoir deliverability is because of the increase in the radius of pressure wave propagation in time.

Pseudo steady state flow: The decline in reservoir deliverability is because of the reservoir pressure decrease due to the production from limited reservoir volume (no-flow boundaries).

If the reservoir pressure is reduced below the bubble point, gas comes out of solution and two phase flow begins. This decreases the relative permeability to oil and also increases the oil viscosity, impairing oil mobility.

Therefore, these factors need to be considered in predicting future IPR of the reservoirs.


07.10.2011 Can S. Bakiler 59

Predicting Future IPR:

Future IPR can be predicted by Vogel’s and Fetkovich’s method.

Vogel’s Method:

poo

ro

foo

ro

p

f

Bk

Bk

JJ

÷÷ø

öççè

æ

÷÷ø

öççè

æ

=

m

m*

*

or

poo

ro

foo

ro

pf

Bk

Bk

JJ

÷÷ø

öççè

æ

÷÷ø

öççè

æ

=

m

m**

úú

û

ù

êê

ë

é

÷÷ø

öççè

æ-÷

÷ø

öççè

æ-=

2*

8.02.018.1 f

bhf

f

bhfff

pp

pppJ

q where Jp* = Present Productivity IndexJf* = Future Productivity Indexpf = Reservoir Pressure in a

future time


Documents

PETE 331-Session 2-07_10_2011