mk trmb09 pvt
DESCRIPTION
GTRANSCRIPT
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