SC RE Chap6 Liquids

Properties of Reservoir LiquidsProperties of Reservoir Liquids

Adrian C Todd

Heriot-Watt UniversityHeriot-Watt University

DEPARTMENT OF PETROLEUM ENGINEERING

Heriot-Watt UniversityHeriot-Watt University

DEPARTMENT OF PETROLEUM ENGINEERING

Composition Petroleum engineers require a compositional

description tool to use as a basis for predicting reservoir and well fluid behaviour.

Two approaches used.

Compositional model.

Black oil model.

The black oil model is a simplistic approach and used for many years to describe composition and behaviour of reservoir fluids

Black Oil Model Considers fluid made up of two components Gas dissolved in oil.-solution gas

Stock Tank Oil

Compositional changes in gas when changing P&T are ignored.

A difficult concept for thermodynamic enthusiasts.

At the core of many petroleum engineering calculations and assocaited procedures and reports

Assocciated Black Oil parameters.

Gas solubility and Formation Volume Factors

Black Oil Model

Reservoir Fluid

2 componentsSolution Gas

Stock Tank Oil

Solution Gas

Stock Tank Oil

Rs - Solution Gas to Oil Ratio

Bo - Oil Formation Volume Factor

Reason for Fluid Composition Models

To predict physical properties.

Exploration

Exploitation

Multiphase transport

Black Oil Models

Prediction of reservoir fluid density

Prediction of solution gas-oil ratio

Prediction of oil formation volume factor

Largely empirical correlations

Important to determine the applicability of the correlation used.

Gas Solubility

Although the gas, like the oil is a multicomponent fluid the black oil model treats it as if we are dealing with a two component system.

Amount of gas in solution in the oil depends on reservoir conditions of T & P and the respective compositions.

Solubility of gas, function of pressure, temperature, composition of gas & oil.

Gas Solubility Black oil model treats the amount of gas in

solution in terms of the gas produced

1. Undersaturated

Oil Reservoir

Solution Gas

Stock Tank Oil

Rsi scf/stb

+

1 stb. oil

Bo res. Bbl. oil

Gas Solubility

Definition. The gas solubility,Rs is defined as the number

of cubic feet ( cubic metre) of gas measured at standard conditions which will dissolve in one barrel( cubic metre) of stock tank oil when subjected to reservoir temperature and pressure.

Gas SolubilityAbove bubble point

pressure.

Oil is undersaturated

Solution GOR is constant

At and below bubble point pressure two

phases produced in the reservoir as gas comes

out of solution.

Solution GOR reduces

Gas Solubility

Below bubble point gas released and mobility effected by relative permeability considerations.

Gas separation in the production tubing is different and considered to remain with associated oil.

Two basic liberation mechanisms.

Flash liberation

Differential liberation

Gas Solubility

Flash Liberation

The gas is evolved during a definite reduction in pressure and the gas is kept in contact with the liquid until equilibrium has been established.

Differential Liberation.

The gas being evolved is being continuously removed from contact with the liquid and the liquid is in equilibrium with the gas being evolved over a finite pressure range.

These processes considered in more detail in PVT section.

Oil Formation Volume Factor, Bo Volume occupied by oil between surface conditions and

reservoir is that of the total system, the ‘stock tank’ oil and its associated ‘solution gas’.

A unit volume of stock tank oil to surface with its associated gas will occupy at reservoir conditions a volume greater than unity.

Relationship between volume of oil and its dissolved gas and the volume at stock tank conditions is called the Oil Formation Volume Factor.

Bo

Oil Formation Volume Factor, Bo

Definition The oil formation volume factor, is the volume

in barrels ( cubic metre) occupied in the reservoir, at the prevailing pressure and temperature, by one stock tank barrel ( one stock tank cubic meter) of oil plus its dissolved gas.

Oil Formation Volume Factor, Bo

Above bubble point as pressure reduces oil

expands due to compressibility.

Below bubble point oil shrinks as a result of

gas coming out of solution.

Gas Solubility

Above bubble pointAll gas in solution

At bubble pointAll gas in solution

Below bubble pointFree gas and solution gas

At surface conditionsNo gas in solution

Oil Formation Volume Factor, Bo

Above bubble pointoil expands as

pressure reduced

At bubble pointAll gas in solution

Below bubble pointoil shrinks

At surface conditionsOil at stock tank

conditions

Oil Formation Volume Factor, Bo

Reciprocal of the oil formation volume factor is called the shrinkage factor, bo.

bo=1/Bo

The formation volume factor ,Bo multiplied by volume of stock tank oil gives the reservoir volume.

Shrinkage factor multiplied by reservoir volume gives stock tank oil volume

Oil Formation Volume Factor, Bo

Important to appreciate that processing of oil & gas will effect the amount of gas produced.

This will effect values of oil formation volume factor and solution gas to oil ratio.

The amount of gas and oil produced depends on the

processing conditions

The black oil model is an ‘after the event’ description of the

reservoir fluids.

Integrated Reservoirs

Final amount of stock tank oil and produced gas will depend on a fully optimised processing throughout the system from fields to vessel transport.

Total Formation Volume Factor, Bt

Sometimes convenient to know volume of the oil in the reservoir by one stock tank unit of oil plus the free gas that was originally dissolved in it.

Total formation volume factor is used, Bt.

Sometimes termed two-phase volume factor.

Total Formation Volume Factor, Bt

Definition The total formation volume factor is the

volume in barrels (cubic metre ) that 1.0 stock tank barrel ( cubic metre ) and its initial complement of dissolved gas occupies at reservoir temperature and pressure conditions.

t o g sb sB B B R R

Rsb = the solution gas to oil ratio at the bubble point.

Total Formation Volume Factor, Bt

Sometimes used in the material balance equation

Does not have volume significance in the reservoir.

t o g sb sB B B R R

OIL

Hg

P = Pb

Bob

OIL

Hg

GAS

P < Pb

Bo

Bg(Rsb-Rs)

Bt

Total Formation Volume Factor, Bt

t o g sb sB B B R R

Above Pb, Bt = Bo

Below the bubble pointSolution Gas & Free Gas

Stock Tank OilSaturated

Rs scf/stb

+

1 stb. oil

Bo res. Bbl. oil & dissolved gas/stb

R= + R-Rs scf/stb

(R-Rs)Bg res. bbl.free gas / stb

Oil ReservoirOil

Gas

Oil Compressibility Volume changes of oil above the bubble point are very

significant in recovering undersaturated oil.

Oil formation volume factor reflects these changes

More fundamentaly in the coefficient of compressibility of the oil.

or oil compressibility

PboT

1 Vc

V P

oo

To

B1c

B P

In terms of Bo

Assuming compressibility does

not change with pressure, between conditions 1 & 2.

2o 2 1

1

Vc P P ln

V

Black Oil Correlations

Over the years many correlations developed based on the black oil model.

Based on measured data on oils of interest.

Empirical correlations relate black oil parameters, Bo & Rs

to reservoir tempersture

reservoir pressure

oil & gas surface density.

Black Oil Correlations

Important to appreciate that these correlations are empirical

apply to a particular set of oils using a best fit approach.

Using correlation for fluids whose properties not similar to the correlation can lead to errors.

Black Oil Correlations

Based on crudes across various oil provinces

Most common, Standing, Lasater & others

bP fPb= f ( Rs,g, o,T )Where Pb=bubble point Rs=solution gas-oil ratiog=gravity of dissolved gaso=density of stock tank oil t= temperature

Standing’s Correlation

For calculation of bubble point pressure

For calculation of oil formation volume factor

1.20.5

go s

o

B 0.9759 0.000120 R 1.25T

0

0.83

0.00091T 0.0125( API 1.4sb

g

RP 18.2 10

Standing’s CorrelationOil formation volume factor

Gas gravity = 0.6

GOR=300scf/stb

Oil gravity =0.3

Temperature =120oF

Standing’s Correlation Gas Solubility

Black Oil Correlations

Correlations and ranges

Prediction of Fluid Density The estimation of the density of a reservoir

liquid is important to the petroleum engineer.

Specific Gravity of a Liquid

Specific gravity is the density ratio between water at the same T&P.Usually 60o/60o

Both liquid and water are measured at 60o and 1 atmos. pressure

oo

w

API Gravity

Specific gravity relative to water @ 60oF

141.5. 131.5

@ 60oDegrees API

SpecificGravity F

Prediction of Fluid Density

Several methods of estimating density at reservoir conditions.

Methods depend on the availability and nature of data.

When compositional data available Ideal Solution Principle can be used.

When we have produced gas and oil data empirical methods can be used.

Ideal Solution Principle

An ideal solution is a hypothetical liquid

No change in characteristics of liquids is caused by mixing.

The properties of the mixture are strictly additive.

Ideal solution principles can be applied to petroleum mixtures to determine density.

Ideal Solution Principle

Calculate density at 14.7 psia and 60oF of the following hydrocarbon liquid mixture.

From Tables of Physical

propertieso

74.69 lb.39.73

1.88 cu.ft.

Prediction of Fluid Density

Liquids in the reservoir contain quantities of dissolved gas.

This gas clearly cannot contribute to a liquid density at surface conditions.

Use a ‘pseudo liquid density’ in the method to calculate density at reservoir conditions.

Prediction of Fluid Density

‘pseudo liquid density’

Apparent liquid density of C1 & C2 vs. system density

pseudo liquid density’

Step 1 : System density is assummed.

Step 2: Apparent density of C1 & C2 determined

Step 3. System density calculated using apparent liquid densitiy

values from step 2.

Step 4: New values of apparent density determined.

Repeat steps 2-4 until convergence

Physical Properties Table

Prediction of Fluid Density Trial & error method very tedious.

Standing & Katz correlation devised a correlation which removes tedious approach.

Density of C3+ material calculated using additive volume.

Weight per. Cent of C2 in C2+ material calculated.

Weight per cent of C1 in C1+ material calculated

Pseudo Density of system including C1 & C2 at surface read from correlation.

Standing & Katz correlation

Step 1: Density of C3+

Step 2:Wgt.% C2 in C2+

Step 3:Wgt.% C1 in C1+

Step 4: Density of system including C1 & C2

Calculating Reservoir Fluid Density

The pseudo density needs to be converted to reservoir density by taking the effect of reservoir conditions.

Firstly pressure

Secondly temperature.

Pressure & temperature effects determined by Standing & Katz.

Effect of Pressure

Step 1: Pseudo density at surface

Step 2: Correction for pressure

Density at pressure = density at atmos + correction value

Effect of Temperature

Step 1: Density at pressure and 60oF

Step 2: temperature correction

Density at reservoir conditions

= density at atmos temp - correction value.

Standing & Katz correlation

Step 1: Density of C3+

Step 2:Wgt % C2 in C2+

Step 3:Wgt % C1 in C1+

Pseudo density at surface

Reservoir Density, Gas Solubility, Gas Composition and Surface Gravity Known

Recombine mixture according to volume.

Volume fraction of gas is the same as mole fraction.

Add volumes per bbl of crude oil

Get weight % of C1 & C2

Determine pseudo density from Standing & Katz

Correct for reservoir pressure and temperature.

Formation Volume Factor of Gas Condensate

For a wet gas and gas condensate reservoirs at surface produce liquids.

The formation -volume factor of a gas condensate, Bgc, is the volume of gas in the reservoir required to produce 1.0 stb of condensate at the surface.

Viscosity of Oil

Viscosity of oil at reservoir conditions less than dead oil because of dissolved gases.

Correlations are available from the literature.

Interfacial Tension Interfacial tension,IFT, an important physical property in context

of recovery.

In particular for gas condensates.

Arises from inbalance of molecular forces at the interface between phases.

In recent years magnitude of surface, gravitational and viscous forces can have significant effect on mobility of various phases.

Major advance in relation to gas condensates where previously considered liquid drop out was immobile.

Fluids can now be mobile due to low IFT values.

Comparison of Reservoir Fluid Models Suitablity of the two approaches depends on the nature of the

fluid.

Heavier oils where GOR is low-Black Oil model is suitable

For more volatile systems compositional models are more capable of predictiong behaviour.

Computational needs of compositional model used to be a restriction when carrying out large reservoir simulations.

Full systems modelling from reservoir to the refinery puts the ‘black oil model’ in a former era.

Comparison of Reservoir Fluid Models Black Oil Model

2 components -solution gas and stock tank oil

Bo,& Rs etc

Empirical correlations

After the event description of fluid properties.

Compositional Models

N components based on paraffin series

Equation of state based calculations

Feed forward calculation of fluid properties