b (i-1a) fundamentals of reservoir phase behavior

Copyright 2008, NExT, All rights reserved

Basics of Reservoir Engineering Module I

I.1.A - Fundamentals of Reservoir Phase Behavior


Understanding Phase Behavior

Naturally occurring hydrocarbon mixtures found in petroleum reservoirs are mixtures of organic compounds and few non-hydrocarbons that may exist in gaseous or liquid states.

Differences in the phase behavior of these mixtures over a wide ranges of pressures and temperature ultimately determine the production characteristics of hydrocarbon reservoirs.


Why study Phase Behavior?

As oil and gas are produced from the reservoir, they are subjected to a series of pressure, temperature, and compositional changes.

Such changes affect the volumetric and transport behavior of these reservoir fluids and, consequently, the produced oil and gas volumes.

All reservoir performance equations (e.g., Darcys law, materialbalances) require the knowledge of fluid properties. It is impossible to correctly evaluate well productivity and reservoirperformance if fluid properties are not known.


Phase Behavior - Pure Substance

LiquidSolid

GasVapor-p

ressure

line

Mel

ting-

poin

t lin

e C

T

TemperatureTc

pc

P

r

e

s

s

u

r

e



LiquidSolid

GasVapor-p

ressure

line

Mel

ting-

poin

t lin

e C

T

TemperatureTc

pc

P

r

e

s

s

u

r

e

Critical Point

Triple Point



400

500

600

700

800

900

1000

1100

1200

0 0.05 0.1 0.15 0.2 0.25

P

r

e

s

s

u

r

e

,

p

s

i

a

Specific volume, cu ft/lb

Two-phase region 60F

70F

80F85F

90F=Tc

95F

100F

110F

130F

160F

C


Phase Behavior - Mixtures

Dewpoint

300 oF

350 oF

400 oF

425 oF

450 oF454 oF

Critical pointBu

bble

poin

t

400

300

200

0.1 0.2 0.3 0.4

P

r

e

s

s

u

r

e

,

p

s

i

a

Volume, cu ft/lb



MIXTUREPURE SUBSTANCE



Pressure, p

Temp, T

CP

The less alike the molecules,

the farther apart BP and DP Curves!

BP Curve

DP Curve

L + V co-existence

T > TcGAS

T < TcLIQUID

There is no real transition!


Phase Diagrams of Mixtures of Ethane and n-Heptane

10

987

6

5

4

3

2

1

No. Wt % ethane1 100.002 90.223 70.224 50.255 29.916 9.787 6.148 3.279 1.25

10 n-Heptane

Composition

1000

400

600

800

200

0200 300 400 500100

P

r

e

s

s

u

r

e

,

p

s

i

a

Pure nC7

Pure C2

1400

1200

Temperature, F


Phase Diagram of a Reservoir Fluid

Temperature, F

-200 -150 -100 -50 0 50

14001300120011001000900800700600500400300200100

0

P

r

e

s

s

u

r

e

,

p

s

i

a

Criticalpoint

100%

Liq

uid

1

102

520

50


The Five Reservoir Fluids

Black Oil

Criticalpoint

P

r

e

s

s

u

r

e

,

p

s

i

a

Bubbl

epoint

line

Separator

Pressure pathin reservoir Dewpoint line

9080

907060

5040

10

30

20

% Liquid

Temperature, F

Black Oil


P

r

e

s

s

u

r

e

Temperature

Separator

% Liquid

Bubb

lepoin

t line

Dewpoint line

Dewpoint line

Volatile oil

Pressure pathin reservoir

3

2

1

5

10

30

20

40

5060

708090

Criticalpoint

Volatile Oil


3

3020

15

10

40

Separator

% Liquid


1

2Retrograde gas

Criticalpoint

Bubb

lepoin

t line

Dewp

oint li

ne

50

P

r

e

s

s

u

r

e

Temperature

Retrograde Gas

P

r

e

s

s

u

r

e

Temperature

% Liquid

2

1


Wet gas

Criticalpoint

Bubb

lepo

int

line

Separator

152530

Dew

poin

t lin

e

Wet GasP

r

e

s

s

u

r

e

Temperature

% Liquid

2

1


Dry gas

Separator

Dew

poin

t lin

e15

0Dry Gas

25


Phase Diagram of a Typical Black Oil

Black Oil

Criticalpoint

P

r

e

s

s

u

r

e

,

p

s

i

a

Bubbl

e-poin

t Line

Separator


Dewpoint line

9080

7060

5040

10

30

20

% Liquid

Temperature, F

An Oil Reservoir: Tr < Tc ( Bubblepoint Oil )


Phase Diagram of a Typical Volatile Oil

P

r

e

s

s

u

r

e

Temperature, F

Separator

% Liquid

Bubb

lepoin

t line

Dewpoint line

Dewpoint line

Volatile oil


3

2

1

5

10

30

20

40

5060

708090

Criticalpoint

An Oil Reservoir: Tr < Tc ( Bubblepoint Oil )


Phase Diagram of a Typical Retrograde Gas

A Gas Reservoir: Tr > Tc (dewpoint system)

3

3020

15

10

40

Separator

% Liquid

Pressure pathin reservoir1

2Retrograde gas

Critical point

Bubb

lepoin

t line

Dewp

oint li

ne

50

P

r

e

s

s

u

r

e

Temperature


Phase Diagram of Typical Wet Gas

A Gas Reservoir: Tr > TcP

r

e

s

s

u

r

e

Temperature

% Liquid

2

1


Wet gas

Criticalpoint

Bubb

lepo

int

line

Separator

152530

Dew

poin

t lin

e


Phase Diagram of Typical Dry Gas

A Gas Reservoir: Tr > TcP

r

e

s

s

u

r

e

Temperature

% Liquid2

1


Dry gas

Separator

Dew

poin

t lin

e1

50 25


Field Identification of Reservoir FluidsThe Concept of GOR

Gasres bbl Oil

S

e

p

a

r

a

t

o

r

Stocktank

scfSTB

GOR =

STB

scf

scf

res bbl


Components of Naturally Occurring Petroleum Fluids

Component Composition,mole percent

Hydrogen sulfide 4.91Carbon dioxide 11.01Nitrogen 0.51Methane 57.70Ethane 7.22Propane 4.45i-Butane 0.96n-Butane 1.95i-Pentane 0.78n-Pentane 0.71Hexanes 1.45Heptanes plus 8.35

100.00Properties of heptanes plusSpecific Gravity 0.807Molecular Weight 142 lb/lb mole


Initial Producing GOR Correlates With C7+

0

20000

40000

60000

80000

100000

0 10 20 30 40 50

Heptanes plus in reservoir fluid, mole %

I

n

i

t

i

a

l

p

r

o

d

u

c

i

n

g

g

a

s

/

l

i

q

u

i

d

r

a

t

i

o

,

s

c

f

/

S

T

B

Dewpoint gasBubblepoint oil


Initial Producing GLR Correlates With C7+

100

1000

10000

100000

0.1 1 10 100


I

n

i

t

i

a

l

p

r

o

d

u

c

i

n

g

g

a

s

/

o

i

l

r

a

t

i

o

,

s

c

f

/

S

T

B

Dew point gases



10

100

1000

10000

0 20 40 60 80 100


I

n

i

t

i

a

l

p

r

o

d

u

c

i

n

g

g

a

s

/

l

i

q

u

i

d

r

a

t

i

o

,

s

c

f

/

S

T

B

Bubblepoint oils



0

50000

0 30Heptanes plus in reservoir fluid, mole %

I

n

i

t

i

a

l

p

r

o

d

u

c

i

n

g

g

a

s

/

o

i

l

r

a

t

i

o

,

s

c

f

/

S

T

B

Retrogradegas

Volatileoil

Wetgas

Drygas

Blackoil

Dewpoint gasBubblepoint oil


Field Identification

Black Oil

Volatile Oil

Retrograde Gas

Wet Gas

Dry Gas

Initial Producing Gas/Liquid Ratio, scf/STB

3200 > 15,000* 100,000*

Initial Stock-Tank Liquid Gravity, API

< 45 > 40 > 40 Up to 70 No Liquid

Color of Stock-Tank Liquid

Dark Colored Lightly Colored

Water White

No Liquid

*For Engineering Purposes


Laboratory Analysis

BlackOil

VolatileOil

RetrogradeGas

WetGas

DryGas

PhaseChange inReservoir

Bubblepoint Bubblepoint Dewpoint NoPhase

Change

NoPhase

ChangeHeptanesPlus, MolePercent

> 20% 20 to 12.5 < 12.5 < 4* < 0.8*

OilFormationVolumeFactor atBubblepoint

< 2.0 > 2.0 - - -

*For Engineering Purposes


Primary Production TrendsG

O

R

G

O

R

G

O

R

G

O

R

G

O

R

Time Time Time

TimeTimeTimeTimeTime

TimeTime

Noliquid

Noliquid

DryGas

WetGas

RetrogradeGas

VolatileOil

BlackOil

A

P

I

A

P

I

A

P

I

A

P

I

A

P

I


Exercise 1Determine reservoir fluid type from field data

One of the wells in the Merit field, completed in December 1967 in the North Rodessa formation, originally produced 54API stock-tank liquid at a gas/oil ratio of about 23,000 scf/STB. During July 1969, the well produced 1987 STB of 58API liquid and 78,946 Mscf of gas. By May 1972, the well was producing liquid at a rate of about 30 STB/d of 59API liquid and gas at about 2,000 Mscf/d.

What type of reservoir fluid is this well producing?


Plot of Exercise 1 Data

00 12 24 36 48 60 72

505152535455

6059585756

10000090000800007000060000500004000030000

1000020000

Months since start of 1967

P

r

o

d

u

c

i

n

g

g

a

s

/

o

i

l

r

a

t

i

o

,

s

c

f

/

S

T

B

Stock-tankliquid gravity, A

PI



A field in north Louisiana discovered in 1953 and developed by 1956 had an initial producing gas/oil ratio of 2,000 scf/STB. The stock-tank liquid was medium orange and had a gravity of 51.2API. Classify this reservoir fluid. Laboratory analysis of a sample from this reservoir gave the following composition: Component Composition,

mole fractionCO2 0.0218N2 0.0167C1 0.6051C2 0.0752C3 0.0474C4s 0.0412C5 0.0297C6s 0.0138C7 0.1491

1.0000Properties of heptanes plusSpecific Gravity 0.799Molecular Weight 181 lb/lb mole



The reported production from the discovery well of the Nancy (Norphlet) field is given below. How would you classify this reservoir fluid? Why?

DateStock-Tank

Liquid GravityAPI

Oil,STB

Gas,Mscf

9/86 29 4,276 1,16510/86 28 16,108 5,27011/86 28 15,232 4,80012/86 28 15,585 4,9601/87 28 15,226 4,6502/87 28 14,147 4,3353/87 28 15,720 4,7074/87 28 15,885 4,9045/87 28 15,434 4,9796/87 28 12,862 4,3397/87 28 14,879 4,8148/87 28 15,192 4,270



100

200

300

400

500

0 2 4 6 8 10 12

Months since start of production

P

r

o

d

u

c

i

n

g

g

a

s

/

o

i

l

r

a

t

i

o

,

s

c

f

/

S

T

B


Plot of Exercise 3 Data Three-Month Running Average


P

r

o

d

u

c

i

n

g

g

a

s

/

o

i

l

r

a

t

i

o

,

s

c

f

/

S

T

B

100

200

300

400

500

0 2 4 6 8 10 12



The Crown Zellerbach No. 1 was the discovery well in the Hooker (Rodessa) field. The reported production during the first year of production is given below. How would you classify this reservoir fluid? Why?

Monthly Production

DateStock-Tank

Liquid GravityAPI

Oil, STB Water, STB Gas, Mscf

Apr 1984 - 112 - 3,362May 1984 55 1,810 12,090 54,809Jun 1984 55 2,519 180 64,104Jul 1984 55 3,230 240 94,419

Aug 1984 55 3,722 279 119,151Sep 1984 54 2,780 248 100,235Oct 1984 55 3,137 270 113,359Nov 1984 56 2,291 210 80,083Dec 1984 56 2,108 217 71,412Jan 1985 56 1,799 203 60,279Feb 1985 56 1,422 196 57,626Mar 1985 56 1,861 186 60,330


Plot of Exercise 4 DataThree-Month Running Average

28000

37000

0 13


P

r

o

d

u

c

i

n

g

g

a

s

/

o

i

l

r

a

t

i

o

,

s

c

f

/

S

T

B



Here we present the GOR plot based on three month running average data for Exercise 4.

Annual Production

DateStock-Tank

Liquid GravityAPI

Oil, STB Water, STB Gas, Mscf

1982 46 4,646 1,484 462,2651983 50 2,606 1,177 342,0751984 47 1,350 1,215 241,0481985 48 1,430 932 221,0201986 50 1,662 1,122 267,106

*1987 51 1,110 665 178,951*through August 1987



50000

200000

1981 1988Year

P

r

o

d

u

c

i

n

g

g

a

s

/

o

i

l

r

a

t

i

o

,

s

c

f

/

S

T

B

40

55

1981 1988

S

t

o

c

k

-

t

a

n

k

l

i

q

u

i

d

g

r

a

v

i

t

y

,

A

P

I

Year



0

25

50

75

100

125

150

175

200

0 24 48 72 96 120

Months since start of 1966

Y

e

i

l

d

,

S

T

B

/

M

M

s

c

f

The following liquid yield production data is available for a given reservoir. Can you identify the fluid?


Basics of Reservoir Engineering

Natural Gas Properties


Phase Behavior

Relationship between conditions (Pressure, Temperature, Volume) and phases (liquid, gas, solid)


Ideal Gas Equation Of State

The simplest PVT model: the ideal gas.

Assumptions of the ideal model:

Volume occupied by molecules is insignificant compared to volume of gas

No attractive or repulsive forces between molecules

MTRpv

TRMmpV

TRnpV

=

==


Real Gas Equation of State

z is called compressibility factor:

Also called gas deviation factor, supercompressibility, or z-factor.M

RTzvp

TRMmzVp

TRnzVp

=

==

ideal

real

VVz =

idealreal

ideal

VzpTRnzV

pTRnV

==

=


Typical Shape of z-Factor

Pressure, p

Actual V greater than ideal V

Actual V less than ideal VCo

m

p

r

e

s

s

i

b

i

l

i

t

y

f

a

c

t

o

r

,

z

1.0

z approaches 1.0

0 0

Temp

eratur

e = co

nstan

t


z-Factors For Methane

0 1000

Methane1.1

0.9

0.1

0.7

0.3

0.52000

3000

4000

5000

1000080006000

1.0

1.2

1.4

1.6

-84

-70

-54

-4

-22

-40

140104

44

32

212 170

240

-84 -70-54 -4-22-40

32

140104

44

212170

240

262342 320404

262320

404342

RTVpZ M=

RTVpZ M=

Pressure, psia


z-Factors and Corresponding States

By defining reduced conditions Tr = T/Tc; Pr= P/Pc, z-factor isothermsfor different substances tend to collapse to a universal z-factor curve:

Reduced pressure, pr

C

o

m

p

r

e

s

s

i

b

i

l

i

t

y

f

a

c

t

o

r

,

z

=

p

V

R

T

3.01.80 1.2 2.40.60

1.0

0.6

0.8

0.4

0.2

Tr = 0.9Tr = 1.0

Tr = 1.1

Tr = 1.2

Tr = 1.3

Tr = 1.5

C5 H

12C

6 H14

C3 H

8

CH4

C6H14

C5H12

C5H12

C5H12

C5H12

CH4

CH4

CH4

CH4

C3H8

C3H8

C3H8

C3H8

C5H12

CH4C3H8


z-Factors for Naturally Occurring Gas Mixtures

0.9

1.1

7 8 9 10 11 12 13 14 15

Pseudoreduced pressure, ppr

C

o

m

p

r

e

s

s

i

b

i

l

i

t

y

f

a

c

t

o

r

,

z

1.0

0.4

0.25

0.5

0.3

0.6

1.1

1.0

0.70.80.9

1.01.11.21.31.4

1.71.61.5

1.01.1

0 1 4 6 7 82 3 5Pseudoreduced pressure, ppr

1.05

1.1

1.151.2

1.251.3

1.351.41.451.51.61.71.81.9

2.0 2.22.42.6

2.83.0Pseudoreduced Temperature

1.1

1.21.31.41.5

1.61.7 1.8

1.92.0 2.2

2.42.63.0

1.051.11.2

1.41.71.81.92.02.22.4

3.0

2.6

1.6 1.3

1.05

2.8

C

o

m

p

r

e

s

s

i

b

i

l

i

t

y

f

a

c

t

o

r

,

z


Molecular Weight Calculation

The apparent molecular weight of a natural gas is calculated as the weighted average of the molecular weight of all its components:

= jja MyM


Physical Constants

Physical constants of single components are tabulated! Critical Constants

Compound Formula Molar Mass, molecular weight

Pressure, psia

Temperature, F

Methane CH4 16.043 666.4 -116.67 Ethane C2 H6 30.070 706.5 89.92 Propane C3H8 44.097 616.0 206.06 Isobutane C4H10 58.123 527.9 274.46 n-Butane C4H10 58.123 500.6 305.62 Isopentane C5H12 72.150 490.4 369.10 n-Pentane C5H12 72.150 488.6 385.8 Neopentane C5H12 72.150 464.0 321.13 n-Hexane C6H14 86.177 436.9 453.6 2-Methylpentane C6H14 86.177 436.6 435.83 3-Methylepntane C6H14 86.177 453.1 448.4 Neophexane C6H14 86.177 446.8 420.13 2,3-Dimethylbutane C6H14 86.177 453.5 440.29 Hydrogen sulfide H2S 34.08 1300. 212.45 Carbon Dioxide CO2 44.010 1071. 87.91 Nitrogen N2 28.0134 493.1 -232.51 Argon A 39.944 704.2 -188.53 Oxygen O2 31.999 731.4 -181.43


Exercise 7Calculate Apparent Molecular Weight of Gas Mixture

Dry air is a gas mixture consisting of nitrogen, oxygen, and small amounts of other gases. Compute the apparent molecular weight of air given its approximate composition.

Component Composition,mole fraction

Nitrogen 0.7809Oxygen 0.2095Argon 0.0093Carbon dioxide 0.0003

1.0000


Specific Gravity Of Gas

29g

air

g

air

gg

M

TRMpTRMp

===

Gas specific gravities are calculated as the ratio of gas density to the density of air, both measured at the same temperature and pressure, usually 60F and atmospheric pressure

air

gg

= , which becomes:


Exercise 8Calculate Specific Gravity of Gas Mixture

Component Composition, molepercent

hydrogen sulfide 0.00carbon dioxide 0.00nitrogen 0.00methane 96.13ethane 1.50propane 0.88iso-butane 0.15n-butane 0.16iso-pentane 0.08n-pentane 0.06hexanes 0.10heptanes plus 0.94

100.00

Properties of Heptanes PlusDensity, gm/cc @ 60F 0.798Molecular weight 164


Gas Density

Calculated as a function of Z:

Units - lb/cu ft

or

TRzMp

g =

ftpsi

ftsqinsqftculbg =

/144/

0

0.15

0 10000

g

,

p

s

i

/

f

t

p, psia


Gas Formation Volume Factor (Bg)

Definition - volume of gas at reservoir conditions required to produce one standard volume of gas at the surface

Units - rcf/scf (res cu ft/scf)res bbl/scfres bbl/Mscf

Symbol - Bg

res bbl gasMscfBg =Gas

res bblS

e

p

a

r

a

t

o

r

Stocktank

STB

scf

scf


Gas Formation Volume Factor (Bg)

Equation:

or

sc

Rg VVB =

scfftcures

pTz

TpBsc

scg =

Mscfbblres

pTz

Tp

ftcubbl

MB

sc

scg

=

615.51000

0

40

0 10000B

g

,

r

e

s

b

b

l

/

M

s

c

f

p, psia


Gas Viscosity

Definition - The resistance to flow exerted by a fluid, i.e., large values = low flow rate. Units - centipoise or centistoke

0

0.05

0 10000

g

,

c

p

p, psia


Gas Viscosity

Gas Viscosity Correlation Equation (Lee-Gonzalez)

whereA = f(Ma, T)B = f(Ma, T)C = f(Ma, T)

Thusg = f(g, Ma, T) or g = f(z, Ma, T)

( ) ( )Cgg BEXPA 410=


Coefficient of Isothermal Compressibility of Gas(Gas Compressibility)

0

7000

0 10000p

c gx

106

Tg p

VV

c

= 1Definition

Ideal Gas

Real Gas

pcg

1=

Tg p

zzp

c

= 11


Gas Properties - Summary

gaa

g MTRzMP 29, ==

pTz

TpBsc

scg =

( )TMf gag ,, =( )Tpzfc gg ,,,=

i.e., need z and Mai.e., need Tpc, ppci.e., need g

Thus the only gas property required to enter all gas property correlations is either gas composition or gas specific gravity.


Basics of Reservoir Engineering

Oil Properties


Specific Gravity of Oil

w

oo

=

Specific gravity of a crude oil is defined as the ratio of the density of the oil and the density of water at specified pressure and temperatureconditions:

Both densities measured at the same temperature and pressure, usually 60F and atmospheric pressure

Sometimes called o (60/60)


API Gravity of Oil

Besides specific gravity, it is customary in the petroleum industry to use another gravity scale known as API (American Petroleum Institute), which has been defined as:

5.1315.141 =o

API o

This definition gives hydrometers a linear scale for measurement. Based on API of crude oils, a gross classification of crude oils as light (high API), medium, heavy and extra heavy (low API) is used


Phase Diagram - Typical Black Oil

Black Oil

Criticalpoint

P

r

e

s

s

u

r

e

,

p

s

i

a

Bubbl

epoint

Line

Separator


Dewpoint line

9080

7060

5040

10

30

20

% Liquid

Temperature, F


Reservoir Pressure > Oil Bubblepoint Pressure

Oil

res bbl oilSTBBo =

Sepa

rato

r

Stocktank

p > pbres bbl

STB

scf

scf


Oil Formation Volume Factor (Bo)

Definition - volume of reservoir oil at reservoir conditions required to produce one standard volume of stock tank oilUnits - res bbl/STBSymbol - Bo

Oil

res bbl oilSTB

Bo =

Sepa

rato

r

Stocktank

p > pb

res bbl

STB

scf

scf


Oil Formation Volume Factor

Three things happen to reservoir oil as it is produced to surface1. Loses mass - gas comes out of solution on trip to

surface2. Contracts - temperature decrease from reservoir

temperature to 60F 3. Expands - pressure decreases from reservoir

pressure to atmospheric pressure


Typical Shape -Oil Formation Volume Factor

1

2

0 6000p

Bo

pb


Solution Gas/Oil Ratio (Rs)

Another important property of oils is the amount of gas in solution (Rs) available at every pressure level:

Definition - volume of gas which comes out of the oil as it moves from reservoir temperature and pressure to standard temperature and pressure

Units - cubic feet of total surface gas at standard conditions per barrel of stock-tank oil at standard conditions, scf/STB


Reservoir Pressure > Oil Bubblepoint Pressure

Oil

res bbl oilSTBBo =

Sepa

rato

r

Stocktank

p > pb

scfSTB

Rsb =

res bbl

STB

scf

scf


Typical Shape -Solution Gas/Oil Ratio

0

2000

0 6000p, psig

Rs,

scf/S

TB

pb


Reservoir Pressure < Oil Bubblepoint Pressure

res bbl gasMscfBg =

Gasres bbl

scf

Oil

res bbl oilSTBBo =

Sepa

rato

r

Stocktank

p < pb

scfSTB

Rsb =

STB

scf

scf

res bbl


Typical Shape - Oil Formation Volume Factor

1

2

0 6000p, psig

Bo,

res

bbl/S

TB

pb


Typical Shape - Solution Gas/Oil Ratio

0

2000

0 6000p, psig

Rs,

scf/S

TB

pb


Coefficient of Isothermal Compressibility of Oil p > pb

T

o

oo p

BB

c

= 1Definition, oro Vc = 1

TpV

Oil

Hg

Oil

Hg


Coefficient of Isothermal Compressibility of Oil p < pb

Hg

Hg

Oil

OilGas

T

s

o

g

T

o

oo

pR

BB

pB

Bc

+

= 1


Typical Shape - Oil Compressibility

0

500

0 6000p, psig

c o, p

si-1

x 10

6

pb


Oil Density

Units - lb/cu ft or ftpsi

ftsq/insq144ftcu/lb =

39

47

0 6000p, psig

o, lb

/cu

ft

pb


Oil Viscosity

Definition - the resistance to flow exerted by a fluid, i.e., large values = low flow rates. Units: centipoise.

0.3

1.1

0 6000p, psig

o, cp

pb


Production/Pressure History of Typical Black Oil

3000

6000

9000

100

75

50

25

4000

3000

2000

1000

019791978 19811980

Time

P

r

o

d

u

c

i

n

g

g

a

s

/

o

i

l

r

a

t

i

o

O

i

l

p

r

o

d

u

c

i

n

g

r

a

t

e

,

M

S

T

B

/

d

R

e

s

e

r

v

o

i

r

p

r

e

s

s

u

r

e

,

p

s

i

a


Field Data For Correlations

Field Data Needed: Plot producing gas/oil ratio v. cumulative oil production Plot measured average reservoir pressures v. cumulative oil production

Get: Rsb is initial producing gas/oil ratiopb is pressure at which pressure curve flattens

- just before producing GOR starts to increase


Production/Pressure History of Typical Black Oil

1000

2000

3000

4000

5000

6000

7000

8000

0 10 20 30 40 50 60 70

Cumulative oil production, MMSTB

Pres

sure

, psi

aPr

oduc

ing

gas/

oil r

atio

, scf

/STB


Field Data For Correlations

If producing gas/oil ratios are calculated using sales gas (the usual situation), an estimate of the quantity of stock tank ventgas must be added to get Rsb, i.e., Rsb = RSP + RSTCorrelation

),,,( SPSPgSPST TpAPIfR o=


Field Data for Correlations

Accurate value of pb will improve accuracy of results of all correlations - otherwise use correlation for pbRsb required in all correlations - derive from production dataAPI of stock tank oil required in all correlations - get from oil sales datagSP of separator gas required in most correlations - get from gas sales data


Exercise 9Determination of Black Oil Properties

The attached production graphs show stock tank oil sales and separator gas sales for Niceoil field. The stock tank oil produced at Niceoil field is 39.9 API and the sales gas has specific gravity of 0.787. Reservoir temperature is 246F. Separator conditions are 150 psig and 75 F.

Determine and list all variables needed for estimating properties of the black oil.


Pressure/Production History for Niceoil Field

AVAILABLE PRODUCTION DATA


A

v

e

r

a

g

e

r

e

s

e

r

v

o

i

r

p

r

e

s

s

u

r

e

,

p

s

i

a

1750

2250

2750

3250

3750

4250

0 4 8 12


P

r

o

d

u

c

i

n

g

g

a

s

/

o

i

l

r

a

t

i

o

(

3

m

o

r

u

n

n

i

n

g

s

c

f

/

S

T

B

a

v

e

r

a

g

e

)

300

400

500

600

700

800

900

1000

0 2 4 6 8 10


Exercise 9 Solution


A

v

e

r

a

g

e

r

e

s

e

r

v

o

i

r

p

r

e

s

s

u

r

e

,

p

s

i

a

1750

2250

2750

3250

3750

4250

0 4 8 12


P

r

o

d

u

c

i

n

g

g

a

s

/

o

i

l

r

a

t

i

o

(

3

m

o

r

u

n

n

i

n

g

s

c

f

/

S

T

B

a

v

e

r

a

g

e

)

300

400

500

600

700

800

900

1000

0 2 4 6 8 10

Rsp= 570 scf/STB

Pb=2400 psia


Exercise 9 Solution

Rsb = 707 scf/STBTR = 246FSTO = 39.9APIg = 0.787pb = 2,400 psia


Exercise 10Estimation of black oil fluid properties.

Estimate values of oil properties for Niceoil field. Required properties are oil formation volume factor, solution gas/oil ratio, oil density, oil viscosity, and oil compressibility. Create a table starting at 5,000 psiawith increments of 500 psi above the bubblepointpressure and increments of 200 psi below the bubblepoint pressure to a final pressure of 100 psia.


Exercise 11 Solution

0

100

200

300

400

500

600

700

800

900

1000

0 1000 2000 3000 4000 5000Pressure, psia

S

o

l

u

t

i

o

n

g

a

s

/

o

i

l

r

a

t

i

o

,

s

c

f

/

S

T

B

datacorrelation


Exercise 11 Solution(continued)

1.00

1.05

1.10

1.15

1.20

1.25

1.30

1.35

1.40

1.45

1.50

0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000Pressure, psia

O

i

l

f

o

r

m

a

t

i

o

n

v

o

l

u

m

e

f

a

c

t

o

r

,

r

e

s

b

b

l

/

S

T

B

datacorrelation



0.26

0.27

0.28

0.29

0.3

0.31

0.32

0.33

0.34

0.35

0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000

Pressure, psia

O

i

l

d

e

n

s

i

t

y

,

p

s

i

/

f

t

datacorrelation



0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0 1000 2000 3000 4000 5000

Pressure, psia

O

i

l

v

i

s

c

o

s

i

t

y

,

c

p datacorrelation


References and Further Reading

McCain, W., The Properties of Petroleum Fluids, Pennwell, 1990.

Whitson, C. and Brule, M., Phase Behavior, SPE Monograph Volume 20, Henry Doherty Series, 2000.

Danesh, A., PVT and Phase Behaviour of Petroleum Reservoir Fluids, Developments in Petroleum Science v. 47, Elsevier, 1998.

Basics of Reservoir Engineering Module IUnderstanding Phase BehaviorWhy study Phase Behavior?Phase Behavior - Pure SubstancePhase Behavior - Pure SubstancePhase Behavior - Pure SubstancePhase Behavior - Pure SubstancePhase Behavior - MixturesPhase Behavior - MixturesPhase Diagrams of Mixtures of Ethane and n-HeptanePhase Diagram of a Reservoir FluidThe Five Reservoir FluidsPhase Diagram of a Typical Black OilPhase Diagram of a Typical Volatile OilPhase Diagram of a Typical Retrograde GasPhase Diagram of Typical Wet GasPhase Diagram of Typical Dry GasField Identification of Reservoir FluidsThe Concept of GORComponents of Naturally Occurring Petroleum FluidsInitial Producing GOR Correlates With C7+Initial Producing GLR Correlates With C7+Initial Producing GLR Correlates With C7+Initial Producing GLR Correlates With C7+Field IdentificationLaboratory AnalysisPrimary Production TrendsExercise 1Determine reservoir fluid type from field dataPlot of Exercise 1 DataExercise 2Determine reservoir fluid type from field dataExercise 3Determine reservoir fluid type from field dataPlot of Exercise 3 DataPlot of Exercise 3 Data Three-Month Running AverageExercise 4Determine reservoir fluid type from field dataPlot of Exercise 4 DataThree-Month Running AverageExercise 5Determine reservoir fluid type from field dataPlot of Exercise 5 DataExercise 6Determine reservoir fluid type from field dataPhase BehaviorIdeal Gas Equation Of StateReal Gas Equation of StateTypical Shape of z-Factorz-Factors For Methanez-Factors and Corresponding Statesz-Factors for Naturally Occurring Gas MixturesMolecular Weight CalculationPhysical ConstantsExercise 7Calculate Apparent Molecular Weight of Gas MixtureSpecific Gravity Of GasExercise 8Calculate Specific Gravity of Gas MixtureGas DensityGas Formation Volume Factor (Bg)Gas Formation Volume Factor (Bg)Gas ViscosityGas ViscosityCoefficient of Isothermal Compressibility of Gas(Gas Compressibility)Gas Properties - SummarySpecific Gravity of OilAPI Gravity of OilPhase Diagram - Typical Black OilReservoir Pressure > Oil Bubblepoint PressureOil Formation Volume Factor (Bo)Oil Formation Volume FactorTypical Shape - Oil Formation Volume FactorSolution Gas/Oil Ratio (Rs)Reservoir Pressure > Oil Bubblepoint PressureTypical Shape - Solution Gas/Oil RatioReservoir Pressure < Oil Bubblepoint PressureTypical Shape - Oil Formation Volume FactorTypical Shape - Solution Gas/Oil RatioCoefficient of Isothermal Compressibility of Oil p > pbCoefficient of Isothermal Compressibility of Oil p < pbTypical Shape - Oil CompressibilityOil DensityOil ViscosityProduction/Pressure History of Typical Black OilField Data For CorrelationsProduction/Pressure History of Typical Black OilField Data For CorrelationsField Data for CorrelationsExercise 9Determination of Black Oil PropertiesPressure/Production History for Niceoil FieldExercise 9 SolutionExercise 9 SolutionExercise 10Estimation of black oil fluid properties.Exercise 11 SolutionExercise 11 Solution(continued)Exercise 11 Solution(continued)Exercise 11 Solution(continued)References and Further Reading

b (i-1a) fundamentals of reservoir phase behavior

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