2_ review_ of_reservoir_fluid_properties_.pdf

Review of Reservoir Fluid

Properties

Prof. Attia M. Attia

Lecture # 2 ,3

[PTRL02H02] Petroleum Reservoir Engineering

Review of Reservoir Fluid Properties

Five Reservoir Fluids

Phase Behavior

• Used to visualize the fluids production path from the reservoir to the surface

• To classify reservoir fluids

• Visualize miscible processes

Pressure vs. Temperature Diagrams

Why do we need to classify

Reservoir Fluids?

• Methods of the fluid sampling

• Types and size of surface equipment

• Calculation procedure for determining

OOIP or OGIP

• Techniques of predicting oil and gas

reserves

• The plan of depletion

• Selection of EOR methods

How can you confirmed the type of

reservoir fluid?

• Three properties are readily available in Lab.

• Initial gas oil ratio

• Gravity of the stock tank liquid

• Color of the stock tank liquid

There are five types of reservoir

fluid

1. Black oils

2. Volatile oils

3. Retrograde gas

( gas condensates – R G condensates)

1. Wet gas

2. Dry gas

• For all reservoir we study, what will happen

if the reservoir pressure decrease?

• Or

• What will happen in the production path?

• Or

• What is the effect of Pressure and

temperatures on the fluid behavior ?

Remember …..

Chemical Composition

Black oils

• Contains large , heavy nonvolatile molecules …… phases????

• Not reverse after separate C1

• So we have gas phase and liquid phase

Phase Diagram of a

Black oils or Low shrinkage crude

1-2 undersaturated

From figure

• 1 2 3 indicates the reduction in pressure

at constant temperature that occurs in

reservoir during production

• 1 2 oil is said to be undersaturated

• 2 the oil is at bubble point (said –

saturated) misnomer

• With reduction in pressure, release gas to

form a free gas phase in the reservoir

• 2-3 additional gas is evolved

Black oils are characterized !!! Or Classification of Reservoirs based on

Production and PVT data

• Initial producing G / O ratio of 2000 or less scf / STB

• Stock tank oil gravity below 45 API will slightly decrease with time

• Stock tank oil color is very dark indicating the presence of heavy hydrocarbon often black some times greenish or brown

• Oil formation volume factor 2 or less bbl / stb

Phase Diagram of a

Volatile Oil Reservoir OR High shrinkage crude

Volatile Oil Reservoir cont.

• We can not dealing with this type during

production as phases because is reversed

• Liquid gas liquid and so on…..

• So, We can dealing with this type using

composition only

Volatile oils

• Contain relatively fewer heavy molecules and more intermediates ( Ethan through hexanes) than black oils.

• For fluid to be volatile oil its critical temperature must be greater than reservoir temperature.

• G / O ratio 2000 – 3300 scf / STB increase with the production

• A

Volatile oils are characterized !!!

Or Classification of Reservoirs based on

Production and PVT data

• Initial producing G / O ratio of 2000- 3300

scf / STB

• Stock tank oil gravity greater than 40 API

increase during production

• Stock tank oil color usually brown ,

orange

• Oil formation volume factor 2 or less bbl /

stb

Retrograde condensates gas

Tr greater than Tc

less than Tcond

• Initially, the retrograde gas is totally gas in the

reservoir

• As reservoir pressure decreases the retrograde

gas exhibits a dew point

• As pressure is reduced , the liquid condense

from the gas to form liquid in reservoir

• The liquid will normally not flow and can not

produced as some low in pressure the liquid

begins to revaporize.( this occur in Lab.)

Phase Diagram of a

Retrograde Gas Reservoir

Classification of Reservoirs based on

Production and PVT data for retrograde

• Lower limit of G / O ratio of 3300- upper

not defined but observed at 150000 scf /

STB

• Stock tank oil gravity between 40 – 60

API increase during production

• Stock tank oil lightly b colored , brown ,

orange Or water- white

Wet gas

wet gas reservoirs are

characterized !!!

• The gravity of the Stock tank liquid does

not change during the life of the reservoir

( same range of gravity as the liquid from

retrograde gas)

• True wet gas have very high producing

G / O ratio, producing gas oil ratio will

remain constant during the life of wet gas

GO R more than 50000 scf/STB

Dry gas

• Dry gas is primarily methane with some intermediates

• No liquid is formed at the surface

• The word of dry indicates that the gas does not contain enough of heavier molecules to for hydrocarbon liquid at surface. Usually some of liquid water is condensed at the surface.

• Dry gas - gas reservoir

Typical Reservoir Fluid CompositionsComponent Black Oil Volatile Oil Gas Condensate Wet Gas Dry Gas

C1 48.83 64.36 87.07 95.85 86.67

C2 2.75 7.52 4.39 2.67 7.77

C3 1.93 4.74 2.29 0.34 2.95

C4 1.60 4.12 1.74 0.52 1.73

C5 1.15 3.97 0.83 0.08 0.88

C6 1.59 3.38 0.60 0.12

C7+

42.15 11.91 3.80 0.42

MwC7+

225 181 112 157

GOR 625 2000 18,200 105,000 -

Tank oAPI 34.3 50.1 60.8 54.7 -

Liquid

Color

Greenish

Black

Medium

Orange

Light

Straw

Water

White

-

Why different

?????

CLASSIFICATION OF RESERVOIRS

AND RESERVOIR FLUIDS

Cap Rock

Reservoir

Rock

Oil Gas Water

Reservoir Fluids

1. Oil Reservoirs due to reservoir conditions (P & T)

Undersaturated (Pr>Pb)Saturated (Pr≤Pb)

With bottom

water

Without

bottom water

Depletion Gas

CapBottom

water

Drive

Combination

Gas Reservoirs

Dry gas

reservoir, no

condensate

Wet gasRetrograde gas

condensate

reservoir

Revision 1. Define oil specific gravity and define oil gravity in API

2. Define oil bubble point pressure, pb.

3. Define oil formation volume factor, Bo,

4. Define solution gas/oil ratio, Rs,

5. Define the coefficient of isothermal compressibility of oil,

co.

6. Define oil density, o,

7. Define oil viscosity, o,

8. Field Data for Correlations….

Specific Gravity of Oil

• Both densities measured at the same

temperature and pressure,

usually 60F and atmospheric pressure

• Sometimes called o (60/60)

w

oo

API Gravity of Oil

5.1315.141

APIo

Phase Diagram - Typical Black Oil

Black Oil

Criticalpoint

Pre

ssure

, psia

Separator

Pressure pathin reservoir

Dewpoint line

% Liquid

Temperature, °F

Bubble-Point Pressure

The bubble-point pressure pb of a hydrocarbon system is defined as

the highest pressure at which a bubble of gas is first liberated from the

oil.

The empirical correlations for estimating the bubble-point pressure

Standing

Vasquez and Beggs

Glaso

Marhoun

Petrosky and Farshad

Reservoir Pressure > Oil Bubblepoint

Pressure

Oil

res bbl oil

STBBo =

Se

pa

rato

r

Stocktank

p > pb

res bbl

STB

scf

scf

Formation volume factor

• The change in volume of a reservoir fluid

undergoing production is normally

expressed in terms of the formation

volume factor

In general terms , the formation volume factor (B)

is the volume of the reservoir fluid (Vres) required

to produce a slandard volume of a surface product

relative to that surface volume (Vsur)

Oil Formation Volume Factor

• Definition - volume of reservoir oil at

reservoir conditions required to produce

one standard volume of stock tank oil

• Units - res bbl/STB

• Symbol - Bo

Oil Formation Volume Factor

• Three things happen to reservoir oil as it

is produced to surface

1. Loses mass - gas comes out of solution

on trip to surface

2. 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

Reservoir Pressure > Oil Bubblepoint Pressure

Oil

res bbl oil

STBBo =

Se

pa

rato

r

Stocktank

p > pb

scf

STBRsb =

res bbl

STB

scf

scf

Solution Gas/Oil Ratio

• Definition - volume of gas which comes

out of the oil as it moves from reservoir

temperature and pressure to standard

temperature and pressure.

• Amount of gas that will dissolve in a

certain amount of oil (Rs,or GOR)

• Units - scf/STB

Typical Shape -

Solution Gas/Oil Ratio

0

2000

0 6000p, psig

Rs, scf/S

TB

pb

Reservoir Pressure < Oil Bubblepoint Pressure

res bbl gas

MscfBg =

Gasres bbl

scf

Oil

res bbl oil

STBBo =

Se

pa

rato

r

Stocktank

p < pb

scf

STBRsb =

STB

scf

scf

res bbl

Typical Shape - Oil Formation

Volume Factor

1

2

0 6000p, psig

Bo, re

s b

bl/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

Definition, orT

op

V

V

1c

T

o

oo

p

B

B

1c

Oil

Hg

Oil

Hg

Coefficient of Isothermal

Compressibility of Oil - p < pb

T

s

o

g

T

o

oo

p

R

B

B

p

B

B

1c

Hg

Hg

Oil

Oil

Gas

)](1[

1.

//

/

1

..........

1

1

bxoobox

obbx

oxob

xb

STBSTBob

STBob

o

xb

oxob

o

o

PPC

PP

PP

VVoxVV

VVC

STBthebyDividing

PP

VV

Vob

dp

dv

VC

Typical Shape - Oil

Compressibility

0

500

0 6000p, psig

co, p

si-1

x 1

06

pb

Oil Density

• Units - lb/cu ft or ft

psi

ftsq/insq144

ftcu/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

Typical Shape - Oil Viscosity

0.3

1.1

0 6000p, psig

o, cp

pb

Field Data for Correlations

• Accurate value of pb will improve accuracy of

results of all correlations - otherwise use

correlation for pb

• Rsb required in all correlations - derive from

production data

• API of stock tank oil required in all

correlations - get from oil sales data

• gSP of separator gas required in most

correlations - get from gas sales data

• Reservoir temperature, T - get from well logs

or other sources

Production/Pressure History of Typical Black Oil

3000

6000

9000

100

75

50

25

4000

3000

2000

1000

019791978 19811980

Time

Pro

ducin

ggas/o

il ra

tio

Oil

pro

ducin

gra

te,

MS

TB

/dR

eserv

oir

pre

ssure

, psia

Compressibility factor

BEHAVIOR OF REAL GASES

• At higher pressures, the use of the ideal

gas equation-of-state may lead to errors

as great as 500%, as compared to errors

of 2–3% at atmospheric pressure.

Z = f (Pr, Tr)

• Pseudo-reduced pressure

• Pseudo-reduced temperature

Example

A gas reservoir has the following gas composition: the initial reservoir

pressure and temperature are 3000 psia and 180°F, respectively.

Calculate the gas compressibility factor under initial reservoir conditions.

Pc and Tc from the table

Solution

Determine the pseudo-critical pressure

Calculate the pseudo-reduced pressure and temperature

Determine the z-factor from Figure

z = 0.85

Example

Using the data in the last example and assuming real gas behavior, calculate the

density of the gas phase under initial reservoir conditions. Compare the results

with that of ideal gas behavior.

Solution

Calculate the apparent molecular weight

Ma = 20.23Determine the pseudo-critical pressure

Ppc = 666.38Calculate the pseudo-critical temperature

Tpc = 383.38Calculate the pseudo-reduced pressure and temperature

Determine the z-factor from Figure

z = 0.85Calculate the density

Calculate the density of the gas

assuming an ideal gas behavior

Determination of Z factor when gas composition is not available

For Miscellaneous Gases

GAS FORMATION VOLUME FACTOR

Assuming that the standard conditions are represented by psc =14.7

psia and Tsc = 520, the above expression can be reduced to the

following relationship:

In other field units, the gas formation volume factor can be expressed

in bbl/scf, to give:

The reciprocal of the gas formation volume factor is called

the gas expansion factor and is designated by the symbol

Eg, or:

ExampleA gas well is producing at a rate of 15,000 ft3/day from a gas reservoir at an

average pressure of 2,000 psia and a temperature of 120°F. The specific gravity is

0.72. Calculate the gas flow rate in scf/day.

Solution

Calculate the gas flow rate in scf/day by multiplying the gas flow

rate (in ft3/day) by the gas expansion factor Eg as expressed in

scf/ft3:

Gas flow rate = (151.15) (15,000) = 2.267 MMscf/day

Two phase formation volume factor

go

STB

insolutiongasremaininginsolutiongasoriginalof

STBSTB

insolutiongasoil

STB

insolutiongasoil

t

RsRsi

V

VVo

V

gasVfree

V

V

V

gasVfreeV

][

..

..

...........

....

....

Relation between oil formation volume factor ,Solution

GOR and gas deviation factor with reservoir pressure

Example

. Acylinder is fitted with a leak –proof piston and calibrated so that the volume

within the cylinder can be read from a scale for any position of the piston .

The cylinder is immersed in a constant temperature bath , maintained at

160 F , which is the reservoir temperature of X field. Forty-five thousand cu

cm of the gas , measured at 14.7 psia and 60 F, is charged into the cylinder.

The volume is decreased in the steps indicated below , and the

corresponding pressures are read with a dead weight tester after

temperature equilibrium is reached.

V,cu cm 2529 964 453 265 180 156.5 142.2

P,psia 300 750 1500 2500 4000 5000 6000

Calculate..

1. Calculate and place in tabular form the ideal volumes

for the 45000 cu cm, at 160 F at each pressure, and the

gas deviation factor

2. Calculate the gas volume factors at each pressure, in

units of cubic feet of reservoir space per standard cubic

foot of gas and also, in units of standard cubic feet per

cubic foot of reservoir space .

3. Plot the deviation factor and the gas volume factors

calculated in part 2 versus pressure on the same graph.

4. Express the gas volume factor at 2500 psia and 160 F in

units of cuft/SCF/cuft, bbl/SCF, and SCF/bbl.

14.7 45000 620@300 2629

520 300

o oi i

i o

PVPV

T T

x xPsia Vi cc

x

The same , we can get Vi at each pressure

@750 psia = 1052 cc

@1500 Psia = 525.8 cc

@........

Z

• Gas deviation factor = Actual volume /

ideal volume

Both volumes at the same conditions of

temperature and pressure.

Z@300 Psia = 2529/2629 = 0.962

Z@750 Psia = 964/1052 =0.916

Gas volume factors at each

pressure• Bg=ZnRT/P

• N=(1/379.4) for one scf

• Bg= (Z/P)x(1/379.4)x10.73x620

• = 17.53 (Z/P)

• @300 psia Bg= 17.53 x (0.962/300)=

• = 0.0562 cuft/scf

• @750 psia…..and so on..

• Plot the deviation factor Z and the gas

volume factors Bg calculated in part 2

versus pressure on the same graph.

• Express the gas volume factor at 2500

psia and 160 F in units of cuft/SCF,

SCF/cuft, bbl/SCF, and SCF/bbl.