Trisakti 2012 Pvt Dasar

7/28/2019 Trisakti 2012 Pvt Dasar

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Properties of Reservoir Fluids

as function of

PVT

Pressure

Volume

Temperature


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Main Reservoir Fluids:

Black Oil p>pb Bo, o, co are ASSUMED constant

Solution-Gas Drive ppd Bg, g, cg = f(p)

PVT Behaviour


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Schematic Phase Diagrams Generic (single and multi-component cases) Black Oil Solution-Gas Drive Dry Gas

Black Oil (p>pb) Properties: Bo, o, co (ASSUMED constant)

Solution-Gas Drive (ppd) Properties: Bg, g, cg

Summary of Fluid Properties and Sources

Reservoir Fluids


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Pressure - Volume Behaviour

Single Component System

Liquid

Gas

Pressure

Volume

Bubble

point

FIRST BUBBLE

OF GAS

LAST DROP

OF LIQUID

Dew

point


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Pressure vs Temperature



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3D Phase Diagram


Liquid

Gas

Pressure

VolumeTe

mpera

ture

Liquid

GasCritical

point


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Pressure - Volume Behaviour

Two Component System

Liquid

Gas

Pressure

Volume

Bubble

point

FIRST BUBBLE

OF GAS LAST DROP

OF LIQUID

Dew

point


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P - T Behaviour

2 Component System


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Note the "Bubble Point" and "Dew Point" lines.

Location of critical point determines fluid type.

Diagram for a

Mult i-Component System


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Hydrocarbon Reservoir Fluids types

Reservoir Fluids


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Black Oil :

o>40o API, (GOR)i


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Volatile Oil:

o


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Retrograde Gas :

45


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Wet Gas: (GOR)i >50,000 scf/STB.

Reservoir Fluids

Wet Gas p-T Diagram


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Dry Gas

Reservoir Fluids

Dry Gas p-T Diagram


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Formation Volume Factor: Bo,g,w

The Formation Volume Factor"converts" surfacevolumes to downhole conditions.

Typical values:Oil: 1.2 to 2.4 RB/STBGas: 0.003 to 0.01 rcf/scf

100 to 333 scf/rcf (=expansion factor)

Bo,g,w =Fluidvolume at standard conditions

Fluid volume at reservoir conditions

Reservoir Fluids


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Formation Volume factors

BoBw

Bg

Reservoir conditions

Surface conditions

GasWaterOil

OilGas

Solution

gas

Water

Solutiongas

Rs Rsw


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Retrograde Gas Condensate

Bg

Reservoir conditions

Surface conditions

Gas

Gas

Condensate

GLR


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Viscosity: o,g,w

Is a measure of a fluid's internal resistance to flow,- the proportionality of shear rate to shear stress- a sort of internal friction.

Fluid viscosity depends on pressure, temperature and fluidcomposition.

Typical values:

Oil: 0.2 to 30 cpGas: 0.01 to 0.05 cp

Reservoir Fluids


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Compressibility

Important reservoir parameters:

drained area

permeability

reservoir thickness

porosity

compressibility

Of importance is the TOTAL system compressibility:

ct = chc.Shc + cw.Sw + cf

HC: hydrocarbon, w: water, f: formation


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Hydrocarbon Compressibility: co,g

Oil

Typical values p > pb 5 to 20 x10-6 psi-1

p < pb 30 to 200 x10-6 psi-1

Gas

Typical values 50 to 1000 x10-6 psi-1

dp

dR

B

B

dp

dB

Bc so

o

go

oo +=

1

dp

dB

Bc

g

gg

1=

Compressibility


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Water

Typical values 3 to 5 x10-6 psi-1

Formation

Typical values: 2 to 10 x10-6 psi-1 normal

10 to 100 x10-6 psi-1 very high

dp

dR

B

B

dp

dB

Bc sw

w

gw

ww +=

1

dp

dcf

1=

Compressibility


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Rs/pb Bo o co

Standing ; ; - -

Lasater - - -

Vasquez and Beggs - ;

Glaso -

Lasater- Standing - - -

Petrosky and Farshad -

Beggs and Robinson - ; -

Beal - - -

; generally used as default)

Oil PVT Correlations used in Topaze or Saphir

Fluid Correlations


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z-factor g

Dranchuk, et al. -

Beggs and Brill ; -

Hall and Yarborough -

Lee, et al. - ;

Carr, et al. -

; generally used as default

Gas PVT Correlations used in Topaze or Saphir

Gas compressibility (cg) is computed fromthe z-factor using:

dp

dz

zpdp

dB

Bc

g

gg

111==

Gas Correlations


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Black Oil PVT Properties: (general behavior, pb=5000 psia)

General Oil Properties


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Oil Reservoir below Bubble Point:

"Solution-Gas Drive"

1. Pressure above Bubble Point. Wells

produce oil and associated gas.

2. Pressure drops below Bubble Point.

Bubbles of solution gas form in

reservoir.

3. Critical gas saturation reached.

Gas is now mobile.

4. Gas flows towards producing wells.

Wells now produce oil, associated gas

and solution gas.


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1. As fluid is produced, the reservoir pressure drops towards abandonment.

2. The Oil production is high at first, rapidly dropping off as more gas is produced.

3. At critical gas saturation, the Gas-Oil ratio rises rapidly to a maximum, then

falls as the lower gas compressibility offsets the increased gas mobility.

Oil Reservoir below Bubble Point:

"Solution-Gas Drive"


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Dry Gas

In terms of equations solutions the main difference betweenthe oil and gas case is that the gas properties are highlypressure dependent.

Viscosity g and Compressibility ctare function of thepressure


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Dry gas

In order to keep the liquid flow equations linear, the variationsin gas properties are accounted for by the real gas pseudo-pressure function

( )( ) ( )

m pp dp

p z pp

p

= 2

0

.

.

Pseudo-pressure function is then substituted forpressure in the analysis.

To take into account the varying mgcg a pseudo- time can beused in the analysis.


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References

1. Fundamentals of Reservoir Engineering Calhoun (1953).

2. Properties of Petroleum Fluids McCain (1990).

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