Hadi Nugroho

Geological Department

Diponegoro University

2010

Modified by EBS 2014

Lesson 9 Reservoir Fluid Properties

(PVT)

Further Reading

McCain Jr, W.D. 1990, “Properties of Petroleum Fluids” 2nd Ed – Chapter 2

Satter, A. et al, “Practical Enhanced Reservoir Engineering”, Chapter 3

Dake, L.P. 1978, “Fundamentals of Reservoir Engineering”, Chapter-1 Section 1.8, Chapter 2

Cossé, R., Basics of Reservoir Engineering”, IFP – Chapter 3

Glover, P.W.J., 2001, “Formation Evaluation MSc Course Notes”, Chapter 2

Danesh, A., 1998, “PVT and Phase Behaviour of Petroleum Reservoir Fluids”, Chapter 2 and 5

Petroleum Reservoirs

Rock Properties

Pressure / Temperature

Fluid Properties

Reservoir Drive

Factors Controlling the Petroleum Properties

HC Composition

Pressure Temperature

Source Rock

Maturity

Source Rock Type

Migration Distance

Alteration Post

Entrapment

Geothermal Gradient Reservoir

Depth

Chemical Composition

Normal Paraffin (alkane)

Iso-paraffin (branched-chain paraffin)

Naphthene (cyclo-paraffin)

Aromatic (benzene)

NSO compounds

Chain

Cyclic / ring

Crude Oil and Gas

Indonesian Crude: PARAFINIC BASE, COMPONENT OF WAX

WITH LOW S (SULPHUR) CONTENT

Middle East Crude: AROMATIC BASE, COMPONENT OF LUBE &

ASPHALT WITH HIGH S (SULPHUR) CONTENT

H H H H H

H—C—C—C—C …… — C —H

H H H H H

C

H

H-C C-H

H

C

H-C C-H

H H H H H

H—C—C—C—C …… — C —H

H H H H H +

Hydrocarbon - Mixture of C1 – C50 at various composition for the individual crude, plus other specific materials and impurities

Fluid Properties

Density (Specific Gravity)

Viscosity

Compressibility

Phase Behavior

(PVT)

Gas Specific Gravity

γg = ρ g / ρair @ 60 oF or 15 oC where ρair = 1

Range of values: 0.6 – 0.9

Pipeline quality: 0.6 (mostly C1)

Wet gas: 0.9 (C5+ significant)

Gas follows rules (Equation of States) – gas deviation factor can be calculated knowing gas composition or specific gravity

Oil – Density (Specific Gravity)

Crude Type API gravity Density (kg/m3)

*)Light crude oil > 31.1 < 870

Medium oil 22.3 – 31.1 870 – 920

Heavy crude oil 10.0 – 22.3 920 – 1000

Extra heavy oil < 10.0 > 1000

or

*) Note: the boundary of light crude varies from one to another due to practical

reasons. NYMEX – 37o API, NEB Canada – 30.1o , PEMEX - 27o

Viscosity

Absolute (Dynamic) Viscosity: a measure of the internal resistance of a fluid to flow

Units: Pa s (pascal second) / mPa s (millipascal second)

Dyne s/cm2 (dyne second per square cm) / poise

Conversions: 1 Pa s = 1,000 mPa s = 10 poise

1 cp = 1 mPa s

Kinematic viscosity – a measure of resistive flow of a fluid under influence of gravity 1 cm2/s = 1 stokes

1 mm2/s = 1 cSt

Gas Viscosity Chart

Gas Viscosity value ranges 0.006 – 0.016 cp

Crude Oil Viscosity

Viscosity (cp)

Low < 5

Medium 5 – 10

High 10 - 30

Very High > 30

Notice that gas viscosity is a lot lower than oil --> when there is gas in the reservoir, gas is far more mobile than oil

Compressibility

Change in volume with respect to a change in pressure

Typical figures at a pressure of 2000 psia:

cw = 3 × 10−6/psi - water

co = 15 × 10−6/psi - oil

cg = 500 × 10−6/psi – gas

Gas is highly compressible – source of reservoir energy

Other Properties

Solution Gas – Oil Ratio (Rs) – gas volume dissolved in oil (SCF/STB or Sm3/STm3)

Formation Volume Factor (Bo or Bg) – volume of the fluid (oil or gas) at reservoir conditions corresponding to one stock tank unit of volume (RB/STB or Rm3/STm3)

Bubble Point Pressure (Pb) – pressure at which solution gas starts to liberate from the oil

Video

Petroleum Phases

Gas / vapor

(C1 – C5)

Liquid

(C5 – C23)

Solid

Phase Diagram for Pure C2 (left) and Pure C7 (right)

CP – Critical Point

Phase Diagram for a Mixture of C2 and C7

Phase Diagram Nomenclature

Cricondenbar

Cricondentherm –the maximum temperature above which liquid cannot be formed regardless of pressure

Cricondenbar –maximum pressure above which no gas can be formed regardless of temperature

Reservoir Classification Based on Fluids

Dry Gas

Wet Gas

Gas Condensate

Volatile Oil

Black Oil

Phase Separation Unit at Well Head

Dry Gas and Wet Gas

Composition C1 – C5 (C1 > 85%), liquids may be formed

Separator PT outside phase envelope Separator PT inside phase envelope -

so some liquids formed during

production

Retrograde Condensation

C1 ~ 65%, Gas Oil Ratio > 6,000 scf/bbl, Oil gravity > 45o API

Conversion factor from SCF/Bbl to SM3/SM3 - 0.177295

Volatile Oil

If P above Bubble Point, no gas cap

GOR increasing to 1,200 scf/bbl

Crude 38o API

Better recovery if pressure maintained above bubble point pressure

Conversion factor from Sm3/Sm3 to scf/bbl - 5,640317

Black Oil

No gas cap if P above Pb

GOR ~ 600 scf/bbl

Crude 23 – 38o API

Video

In Summary

Knowing fluid properties is crucial for field development

Gas & Gas Condensate follow gas rules, knowing composition and specific gravity may correlate to other properties

Crude properties are more complex and require lab determination early - prior to production

Fluid properties are essential parameters for reservoir simulation

Good Luck

and

Have a Nice Day