Status: Draft

Basic PVT (Fluid behaviour as a

function of Pressure, Volume and

Temperature)

Statoil module – Field development

Magnus Nordsveen

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

Status: Draft

Phase diagram for a single component

Critical point

Trippel point

P

T

Solid Liquid

Gas

Dense phase

Status: Draft

2 phase

mixture

Phase envelope of an oil reservoir

Status: Draft

Phase envelope of a gas condensate reservoir

2 phase

mixture

Liquid Gas

Tres, Pres

Status: Draft

Phase envelops for 3 reservoir types

C

C

C

Gas Condensate

OilHeavy oil

C = Critical point

Temperature

Pre

ssure

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

0 50

100 150 200 250 300 350 400

0 5 10 15 20 25 30 Temperature (°C)

Pre

ssu

re (

bara

) Hydrate domain

Right temperature

No hydrates can exist in this region

Hydrate formation

Rig

ht

pressu

re

Access to small molecules Access to

free w

ate

r

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)

Try

kk (

bara

)

Hydrate domain

Temperature (°C)

Pressu

re (

bar)

No hydrates

Normal operational

domain

Chemicals move

the hydrate curve

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)

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 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

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

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

Status: Draft

Gas chromatography Fingerprint analysis

’Normal’, paraffinic oil Waxy oil

Biodegraded oil

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

Status: Draft

Fluid properties based on composition

•

iimix x

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

2v

a

bv

RTP

v

RTP

Status: Draft

Equations of state (EOS) & Phase envelope

Family of PV isotherms for a pure component Family of PV isotherms for a cubic EOS

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.

Status: Draft

Thank you