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Basic PVT (Fluid behaviour as afunction of Pressure, Volume and

Temperature)

Statoil module Field development

Magnus Nordsveen

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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 0.03C6 0.07

C7 0.1

C8 0.08

C9 0.03

C10+ 0.13

Gas field

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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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2 phase

mixture

Phase envelope of an oil reservoir

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Phase envelope of a gas condensate reservoir

2 phase

mixture

Liquid Gas

Tres, Pres

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Phase envelops for 3 reservoir types

C

C

C

Gas Condensate

Oil

Heavy oil

C = Critical point

Temperature

Pressure

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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 vapourpressure 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 watercondenses

Condensed water amounts to some m3 per MSm3 produced gas

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050

100150200250300350400

0 5 10 15 20 25 30Temperature (C)

Pressure

(bara)

Hydrate domain

Right temperature

No hydrates can

exist in this region

Hydrate formation

Right

pressure

Access to small molecules Accesstofreewater

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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

)

Hydratedomain

Temperature (C)

Pressure

(bar)

No hydrates

Normaloperational

domain

Chemicals move

the hydrate curve

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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)

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Old type characterization

Useful when no composition exists

The fluid is characterized by:

API gravity / og

GOR

Fluid properties as: Bubble point Pressure (Pb), gas-oil ratio (RSGO), densities,

viscosities, etc are functions (correlations) of the above parameters

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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

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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

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Characterisation of fluids based on

composition

Thousands of components from methane to largepolycyclic compounds

Carbon numbers from 1 to at least 100 (for heavy oilsprobably about 200)

Molecular weights range from 16 g/mole to severalthousands g/mole

Comp Mole%

N2 0.95

CO2 0.6

H20 0.35C1 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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Gas chromatographyFingerprint analysis

Normal, paraffinic oilWaxy oil

Biodegraded oil

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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 0.04iC5 0.1

nC5 0.03

C6 0.07

C7 0.1

C8 0.08

C9 0.03

C10+ 0.13

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Fluid properties based on composition

iimix x

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Equations of state (EOS)

Any equation correlating P (pressure), V (volume) and T (temperature) is calledan 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

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

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PVTSim

In the oil industry we typically use software packages to characterize the fluidbased 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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Thank you