sc re chap6 liquids
DESCRIPTION
HW reservoir 6TRANSCRIPT
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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
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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
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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
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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
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Reason for Fluid Composition Models
To predict physical properties.
Exploration
Exploitation
Multiphase transport
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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.
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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.
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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
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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.
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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
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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
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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.
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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
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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.
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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.
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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
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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
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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
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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.
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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.
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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.
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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.
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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
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Total Formation Volume Factor, Bt
t o g sb sB B B R R
Above Pb, Bt = Bo
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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
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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
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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.
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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.
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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
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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
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Standing’s CorrelationOil formation volume factor
Gas gravity = 0.6
GOR=300scf/stb
Oil gravity =0.3
Temperature =120oF
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Standing’s Correlation Gas Solubility
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Black Oil Correlations
Correlations and ranges
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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
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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.
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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.
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Ideal Solution Principle
Calculate density at 14.7 psia and 60oF of the following hydrocarbon liquid mixture.
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From Tables of Physical
propertieso
74.69 lb.39.73
1.88 cu.ft.
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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.
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Prediction of Fluid Density
‘pseudo liquid density’
Apparent liquid density of C1 & C2 vs. system density
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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
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Physical Properties Table
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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.
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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
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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.
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Effect of Pressure
Step 1: Pseudo density at surface
Step 2: Correction for pressure
Density at pressure = density at atmos + correction value
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Effect of Temperature
Step 1: Density at pressure and 60oF
Step 2: temperature correction
Density at reservoir conditions
= density at atmos temp - correction value.
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Standing & Katz correlation
Step 1: Density of C3+
Step 2:Wgt % C2 in C2+
Step 3:Wgt % C1 in C1+
Pseudo density at surface
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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.
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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.
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Viscosity of Oil
Viscosity of oil at reservoir conditions less than dead oil because of dissolved gases.
Correlations are available from the literature.
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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.
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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.
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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