Basic PVT (Fluid behaviour as a
function of Pressure, Volume and
Temperature)
Statoil module – Field development
Magnus Nordsveen
Status: Draft
Content
•
•
•
•
Phase envelops
Gas field
Hydrates
Characterisations of fluids
Equation of states (EOS)
Status: Draft
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
Phase diagram for a single component
Dense phase
P
Critical point
Solid
Liquid
Gas
Trippel point
T
Status: Draft
Phase envelope of an oil reservoir
2 phase
mixture
Status: Draft
Phase envelope of a gas condensate reservoir
Tres, Pres
Gas
Liquid
2 phase
mixture
Status: Draft
Phase envelops for 3 reservoir types
Gas Condensate
C
C
Pressure
Oil
Heavy oil
C
C = Critical point
Temperature
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
Status: Draft
Hydrate formation
Hydrate domain
400
Access to small molecules
Right pressure
Pressure (bara)
300
250
200
150
Right temperature
Access to free water
350
100
No hydrates can
exist in this region
50
0
0
5
10
15
Temperature (°C)
Status: Draft
20
25
30
Effect of thermodynamic hydrate inhibitors:
Methanol, Ethanol, MEG, salt
400
350
Chemicals move
the hydrate curve
(bara)
Trykk
(bar)
Pressure
300
250
Hydrate
domain
200
No hydrates
150
Normal
operational
domain
100
50
0
0
5
10
15
20
Temperature
(°C)
Temperatur (°C)
Status: Draft
25
30
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)
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
Status: Draft
Reservoir fluid types (GOR)
Fluid type
Dry gas
Wet gas
Gas
Condensate
Oil
Status: Draft
Physical behaviour
No hydrocarbon liquid condensation during production
Hydrocarbon liquid condensation in reservoir is
negligible during production. Condensation in wells,
flowlines and separators.
Condensation of hydrocarbons in reservoir is
significant during production. Condensation in wells,
flowlines and separators.
Gas bubbles is formed in reservoir during production
Typical GOR
[Sm3/Sm3]
> 100 000 (at least))
> 10 000
500 < > 10 000
< 500
Reservoir fluid types (API)
Oil type
Light oil
Oil
Heavy oil
Extra heavy oil
Typical API [-]
> 30
22 < > 30
10 < > 22
< 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
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
Status: Draft
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 chromatography
Fingerprint analysis
’Normal’, paraffinic oil
Biodegraded oil
Status: Draft
Waxy oil
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+
Status: Draft
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
Fluid properties based on composition
•
 mix   xi  i
Status: Draft
Equations of state (EOS)
• Any equation correlating P (pressure), V (volume) and T (temperature) is called
an equation of state
P
RT
v
• Ideal gas law: PV = nRT <=>
(good approx. for P < 4 bar)
– n: moles, R: gas constant,  : molar volume
• Van der Waals cubic EOS: P 
RT
a
 2
vb v
– a: is a measure for the attraction between the particles
– b: is the volume excluded from  by the particles
Status: Draft
Equations of state (EOS) & Phase envelope
Family of PV isotherms for a pure component
Status: Draft
Family of PV isotherms for a cubic EOS
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.
Status: Draft
Thank you
Status: Draft