3 - PVT

1. Status: Draft
Basic PVT (Fluid behaviour as a
function of Pressure, Volume and
Temperature)
Statoil module – Field development
Magnus Nordsveen

2. Status: Draft
Content
• Phase envelops
• Hydrates
• Characterisations of fluids
• Equation of states (EOS)
Comp Mole%
N2 0.95
CO2 0.6
H20 0.35
C1 95
C2 2.86
C3 0.15
iC4 0.22
nC4 0.04
iC5 0.1
nC5 0.03
C6 0.07
C7 0.1
C8 0.08
C9 0.03
C10+ 0.13
Gas field

3. Status: Draft
Phase diagram for a single component
Critical point
Trippel point
P
T
Solid Liquid
Gas
Dense phase

4. Status: Draft
2 phase
mixture
Phase envelope of an oil reservoir

5. Status: Draft
Phase envelope of a gas condensate reservoir
2 phase
mixture
Liquid Gas
Tres, Pres

6. Status: Draft
Phase envelops for 3 reservoir types
C
C
C
Gas Condensate
Oil
Heavy oil
C = Critical point
Temperature
Pressure

7. Status: Draft
Water-hydrocarbon phase behaviour
• Liquid water and hydrocarbons are essentially immiscible in each other
• Water vapour in the gas will be governed by gas composition and the vapour
pressure of the liquid phase
• With water, oil and gas present, there will be two liquid fields and one gas field
• A gas reservoir is often saturated with water vapour
• When gas is produced through a well and flowline, temperature drops and water
condenses
• Condensed water amounts to some m3 per MSm3 produced gas

8. Status: Draft
0
50
100
150
200
250
300
350
400
0 5 10 15 20 25 30
Temperature (°C)
Pressure
(bara)
Hydrate domain
Right temperature
No hydrates can
exist in this region
Hydrate formation
Right
pressure Access to small molecules
Access
to
free
water

9. Status: Draft
Effect of thermodynamic hydrate inhibitors:
Methanol, Ethanol, MEG, salt
0
50
100
150
200
250
300
350
400
0 5 10 15 20 25 30
Temperatur (°C)
Trykk
(bara)
Hydrate
domain
Temperature (°C)
Pressure
(bar)
No hydrates
Normal
operational
domain
Chemicals move
the hydrate curve

10. Status: Draft
Characterisation of fluids
• Based on fluid properties (old)
• Based on composition
Definitions:
Standard conditions [STP] for temperature and pressure: 15 oC, 1 atm
GOR = Volume of gas/ Volume of oil [Sm3/Sm3]
WC = Volume rate of water/ Volume rate of liquid [-]
o = o/w at STP (oil density / water density) - specific gravity of oil
g = g/a at STP (gas density / air density) - specific gravity of gas
API = 141.5/ o – 131.5 (American Petroleum Institute measure of oil density)

11. Status: Draft
‘Old’ type characterization
• Useful when no composition exists
• The fluid is characterized by:
– API gravity / o
– g
– GOR
• Fluid properties as: Bubble point Pressure (Pb), gas-oil ratio (RSGO), densities,
viscosities, etc are functions (correlations) of the above parameters

12. Status: Draft
Reservoir fluid types (GOR)
Fluid type Physical behaviour Typical GOR
[Sm3/Sm3]
Dry gas No hydrocarbon liquid condensation during production > 100 000 (at least))
Wet gas Hydrocarbon liquid condensation in reservoir is
negligible during production. Condensation in wells,
flowlines and separators.
> 10 000
Gas
Condensate
Condensation of hydrocarbons in reservoir is
significant during production. Condensation in wells,
flowlines and separators.
500 < > 10 000
Oil Gas bubbles is formed in reservoir during production < 500

13. Status: Draft
Reservoir fluid types (API)
Oil type Typical API [-]
Light oil > 30
Oil 22 < > 30
Heavy oil 10 < > 22
Extra heavy oil < 10
Comment: Arguably the most important fluid property for production of
heavy oils is viscosity which is very dependent on pressure and
temperature. Viscosity could thus be used as classification of reservoir
types. However, during production the temperature and pressure (and thus
viscosity) can change considerably along the well/flowline to the
processing facility.
Viscosity typically increases with decreasing API

14. Status: Draft
Characterisation of fluids based on
composition
• Thousands of components from methane to large
polycyclic compounds
• Carbon numbers from 1 to at least 100 (for heavy oils
probably about 200)
• Molecular weights range from 16 g/mole to several
thousands g/mole
Comp Mole%
N2 0.95
CO2 0.6
H20 0.35
C1 95
C2 2.86
C3 0.15
iC4 0.22
nC4 0.04
iC5 0.1
nC5 0.03
C6 0.07
C7 0.1
C8 0.08
C9 0.03
C10+ 0.13

15. Status: Draft
Gas chromatography
Fingerprint analysis
’Normal’, paraffinic oil
Waxy oil
Biodegraded oil

16. Status: Draft
Characterization challenge
• Low carbon number components:
–Possible to measure with reasonable accuracy
–Known properties
• Higher carbon number components:
– consists of many variations with different properties
– cannot measure individual components
• Characterization: Lump C10 and higher into C10+
Comp Mole%
N2 0.95
CO2 0.6
H20 0.35
C1 95
C2 2.86
C3 0.15
iC4 0.22
nC4 0.04
iC5 0.1
nC5 0.03
C6 0.07
C7 0.1
C8 0.08
C9 0.03
C10+ 0.13

17. Status: Draft
Fluid properties based on composition
•

 i
i
mix x 


18. Status: Draft
Equations of state (EOS)
• Any equation correlating P (pressure), V (volume) and T (temperature) is called
an equation of state
• Ideal gas law: PV = nRT <=> (good approx. for P < 4 bar)
– n: moles, R: gas constant,  : molar volume
• Van der Waals cubic EOS:
– a: is a measure for the attraction between the particles
– b: is the volume excluded from  by the particles
2
v
a
b
v
RT
P 


v
RT
P 

19. Status: Draft
Equations of state (EOS) & Phase envelope
Family of PV isotherms for a pure component Family of PV isotherms for a cubic EOS

20. Status: Draft
PVTSim
• In the oil industry we typically use software packages to characterize the fluid
based on a measured composition
• In Statoil we use PVTSim from Calsep
• Ref: Phase Behavior of Petroleum Reservoir Fluids (Book),
Karen Schou Pedersen and Peter L. Christensen, 2006.

21. Status: Draft
Thank you