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Transcript of Composition & PVT (Fluid properties as a function of ... · PDF fileComposition & PVT (Fluid...
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Composition & PVT (Fluid properties
as a function of Pressure, Volume
and Temperature)
Statoil module – Field development
Magnus Nordsveen
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Compositions and PVT important for:
• Value and market
• Field development solution
– Reservoir (gas, oil, heavy oil)
– Wells and flowlines
– Processing (subsea, platform, onshore plant)
– Pipeline transport to shore (gas, condensate, oil)
– Offloading to ship (condensate and oil)
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Compositions and PVT important for:
• Wells and flowlines
–Pressure and temperature drop
• Phase transfer (gas/oil split)
• Densities
• Viscosities
• Surface tension
• Conductivities
• Heat capacity
– Wax, hydrates, Asphaltenes
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Content
• Compositions
• Phase transfer, phase envelops and reservoir types
• Water, Hydrates and Ice
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
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Compositions of gas and oil
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
C
C
C C C
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Compositions of gas and oil
• Isomers: Different structure configurations of same carbon numbers
• 75 isomers of decane C10H22 (single bounds)
• 366319 isomers of C20H42 (single bounds)
• Complexity further increased by double bounds, triple bounds, rings, other atoms
C C
H
H
H
H
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’Normal’, paraffinic oil
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Lab analysis of samples
• Gas Chromatography and distillation
• Mass spectrometry (not standard)
• Viscosity measurements
• Boiling point
• Wax appearance temperature, wax deposition, etc.
• Hydrate equilibrium temperature (HET)
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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
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• 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
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Content
• Compositions
• Phase transfer, phase envelops and reservoir types
• Water, Hydrates and Ice
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Phase diagram for a single component
Critical point
Trippel point
P
T
Solid Liquid
Gas
Dense phase
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Phase diagram for C3 (99%) and nC5 (1%)
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Phase diagram for C3 (50%) and nC5 (50%)
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Phase envelope of a gas condensate reservoir
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C
C
C
Gas Condensate
OilHeavy oil
C = Critical point
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• Holdup: b – liquid volume fraction in the cross section
• Oil density: r
• Gas density: r
• Effective density: r br b r
• Gravitational pressure drop: dPgrav = r
(g: gravity, H: Height)
• Total pressure drop: dP = dP + dP
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Holdup Effective
density
[kg/m3]
Height
[m]
dPgrav
[bar]
dPfric*
[bar]
dP*
[bar]
0 80 2000 16 ? ?
0.5 440 2000 86 ? ?
1 800 2000 157 ? ?
*need more detailed calculations (will be addressed later in course)
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Equations of state (EOS) & Phase envelope
• An 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
2v
a
bv
RTP
v
RTP
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Equations of state (EOS) & Phase envelope
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• 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.
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Content
• Compositions
• Phase transfer, phase envelops and reservoir types
• Water, Hydrates and Ice
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Water in hydrocarbon reservoirs - flowlines
In reservoir:
– Separate liquid water layer
– Water vapour in gas layer
In wells/flowlines:
– Condensed water in gas condensate flowlines
– Produced water from oil reservoirs
• Liquid water and hydrocarbons are essentially immiscible in each other
– However, liquid water and oil can form emulsions/dispersions
• With water, oil and gas present in flowlines, there are generally
– 2 liquid fields and 1 gas field
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Gas hydrates (Burning “snow”)
• Ice/snow crystals of water and gas
molecules
• Can cause pipeline blockage
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Gas hydrates
Hydrate formation requires:
High enough pressure Hydrates can be stable at 10-15 bar
Low enough temperature But still good summer temperature
Access to small molecules C1, C2, C3, I-C4, CO2, H2S, N2
Access to free water Condensed water is good enough
Gas molecules stabilise cages made of water molecules.
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Gas hydrates
Gas molecules stabilise cages made of water molecules.
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Hydrate formation domain
0
50
100
150
200
250
300
350
400
0 5 10 15 20 25 30
Temperatur (°C)
Try
kk (
bara
)
Hydrate domain
Temperature (°C)
Pressu
re (
bar)
No hydrates
Normal operational
domain
Chemicals move
the hydrate curve
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Hydrate formation curves Mono Ethylene Glycol (MEG) as inhibitor “defroster”
Chemicals move
the hydrate curve
No hydrates
Normal operational
domain
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Safety Hazards of Moving Hydrate Plugs (From Chevron Canada Resources, 1992)
A hydrate plug moves
down a flowline at very
high velocites.
Closed Valve
Closed ValveIf the velocity is high enough, the
momentum of the plug can cause pressures
large enough to rupture the flowline.
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Ice
• In deep waters the sea bed temperature can be lower than 0 C
– Ormen Lange: -1 C at sea bed
• Large pressure drop can give large temperature drop due to the Joule Thompson
effect
– Over chokes
– In long gas condensate flowlines
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Ice formation temperature as function of pressure
-2.5
-2
-1.5
-1
-0.5
0
0 50 100 150 200 250 300
Pressure [bar]
Tem
pera
ture
[oC
]
Condensed water
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Ice formation temperature as function of MEG
-4
-3.5
-3
-2.5
-2
-1.5
-1
-0.5
0
0 1 2 3 4 5 6 7 8 9 10
wt% MEG in water+MEG
oC
Tem
p
MEG wt%
Ice
Water
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Ice
• Normally hydrates are formed before ice
• Inhibition to avoid hydrates will also hinders ice
• However, in depressurized flowlines (hydrates will not form) ice may form
• Statoil has not experienced ice formation in flowlines
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Thank you