Composition & PVT (Fluid properties

as a function of Pressure, Volume

and Temperature)

Statoil module – Field development

Magnus Nordsveen

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)

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

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

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

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

’Normal’, paraffinic oil

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)

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

• 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

Content

• Compositions

• Phase transfer, phase envelops and reservoir types

• Water, Hydrates and Ice

Phase diagram for a single component

Critical point

Trippel point

P

T

Solid Liquid

Gas

Dense phase

Phase diagram for C3 (99%) and nC5 (1%)

Phase diagram for C3 (50%) and nC5 (50%)

Phase envelope of a gas condensate reservoir

C

C

C

Gas Condensate

OilHeavy oil

C = Critical point

• 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

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)

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

Equations of state (EOS) & Phase envelope

• 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.

Content

• Compositions

• Phase transfer, phase envelops and reservoir types

• Water, Hydrates and Ice

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

Gas hydrates (Burning “snow”)

• Ice/snow crystals of water and gas

molecules

• Can cause pipeline blockage

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.

Gas hydrates

Gas molecules stabilise cages made of water molecules.

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

Hydrate formation curves Mono Ethylene Glycol (MEG) as inhibitor “defroster”

Chemicals move

the hydrate curve

No hydrates

Normal operational

domain

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.

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

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

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

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

Thank you