Q913 rfp w2 lec 5

Reservoir Fluid Properties Course (1st Ed.)

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mailto:[email protected]

http://www.about.me/AlamiNia

1. Reservoir Fluid Course

2. HC Alteration

3. Properties of Natural Gases

4. Properties of Crude OilsA. density

B. Gas Solubility

2013 H. AlamiNia Reservoir Fluid Properties Course: Reservoir Hydrocarbons (Bo & Bt & Constants) 2

1. Formation Volume FactorA. Oil

B. Total (two phase)

2. Property Constants


Laboratory Determination of the PVT RelationshipsIn determining the PVT relationships (including the

gas solubility-pressure relationship) in the laboratory, it is necessary to record the volume of oil and volume of liberated gas as the pressure is reduced below saturation pressure.

The manner in which the solution gas is liberated from the oil will significantly affect all the PVT relationships. There are two types of separation (liberation, vaporization) process, namely:Flash liberation

Differential liberation



Recombination

Courtesy IPE, Tehran, 2012

The Oil Shrinkage

By transferring an oil mixture from reservoir conditions to standard conditions, most of the gaseous components dissolved in the oil at reservoir conditions are lost.

It, therefore, seems as though the oil shrinks during production.

The volumetric changes taking place In the reservoir, During passage of the well and In the process plant,

Can be studied by performing PVT experiments on the reservoir fluid.


Oil Formation Volume Factor

The oil formation volume factor, Bo, is defined as the ratio of the volume of oil (plus the gas in solution) at the prevailing reservoir temperature and pressure (bbl) to the volume of oil at standard conditions (STB).

Evidently, Bo is always greater than or equal to unity. The oil formation volume factor can be expressed mathematically as


𝑩𝒐 =𝑽𝒐 𝒑,𝑻

𝑽𝒐 𝒔𝒄

Oil Formation Volume Factor vs. P Diagram


Bo Behavior

As the pressure is reduced below the initial reservoir pressure, pi, the oil volume increases due to the oil expansion. This behavior results in an increase in the oil formation

volume factor and will continue until the bubble-point pressure is reached.

At Pb, the oil reaches its maximum expansion and consequently attains a maximum value of Bob for the oil formation volume factor.


Bo Behavior (Cont.)

As the pressure is reduced below Pb, volume of the oil and Bo are decreased as the solution gas is liberated.

When the pressure is reduced to atmospheric pressure and the temperature to 60°F, the value of Bo is equal to one.



Numerical Value of the Bo

As in the case of the gas solubility determination, the numerical value

of the oil formation volume factor at different pressures will depend upon

the method of gas liberation.

Methods of Calculating Bo & Bob

There is some mathematical and graphical correlations as:Standing's Correlation

Vasquez and Beggs' Correlation

Glaso's Correlation

Marhowi's Correlation


Oil Formation Volume Factor for Undersaturated OilsWith increasing p above the Pb, the oil formation

volume factor decreases due to the compression of the oil.

To account for the effects of oil compression on Bo, bob is first calculated by using any of the methods. The calculated Bo is then adjusted to account for the effect of increasing the pressure above the Pb.

This adjustment step is accomplished by using the isothermal compressibility coefficient as described below.


Bo for Undersaturated Oils (Cont.)

The isothermal compressibility coefficient (as expressed mathematically by Co=-1/v (∂ V/∂ p) T) can be equivalently written in terms of the oil formation volume factor:


𝑪𝒐 =−1

𝑩𝒐

𝜕𝑩𝒐𝜕𝒑

⟹ 𝒑𝒃

𝒑

−𝑪𝒐𝒅𝒑 = 𝑩𝒐𝒃

𝑩𝒐 1

𝑩𝒐𝒅𝑩𝒐

𝑩𝒐 = 𝑩𝒐𝒃𝒆−𝑪𝒐 𝒑−𝒑𝒃

Total Formation Volume Factor

To describe the pressure-volume relationship of hydrocarbon systems below their bubble-point pressure, it is convenient to express this relationship in terms of the total formation volume factor as a function of pressure. The total formation volume factor defines the total volume of a system regardless of the number of phases present.

The total formation volume factor, as denoted by Bt, is defined as the ratio of the total volume of the hydrocarbon system at the prevailing pressure and temperature per unit volume of the stock-tank oil.


Bt Definition

Because naturally occurring hydrocarbon systems usually exist in either one or two phases, the term "two-phase formation volume factor" has become synonymous with the total formation volume.

Mathematically, Bt is defined by the following relationship:


𝑩𝒕 =𝑽𝒐 𝒑,𝑻 + 𝑽𝒈 𝒑,𝑻

𝑽𝒐 𝒔𝒄

Bo and Bt versus P Relationships


Graph Description

It should be noted that Bo and Bt are identical at pressures above or equal to the bubble-point pressure because only one phase, the oil phase, exists at these pressures.

It should also be noted that at pressures below the bubble-point pressure, the difference in the values of the two oil properties represents the volume of the evolved solution gas as measured at system conditions per stock-tank barrel of oil.


The Concept of the Two-Phase Formation Volume Factor


The Concept of the Bt

Consider a crude oil sample placed in a PVT cell at its Pb and reservoir temperature. Assume that the volume of the oil sample is sufficient to yield one stock-tank barrel of oil at standard conditions. Let Rsb represent the gas solubility at Pb·

By lowering the cell pressure to p, a portion of the solution gas is evolved and occupies a certain volume of the PVT cell. Let Rs and Bo represent the corresponding gas solubility and oil formation volume factor at p.



PVT Cell

Courtesy IPE, Tehran, 2012

Bt Expression

Obviously, the term (Rsb - Rs) represents the volume of the free gas as measured in scf per stock-tank barrel of the oil. The volume of the free gas at the cell conditions is then

The volume of the remaining oil at the cell condition is ((V) p, T=Bo)

From the definition of the two-phase formation volume factor


𝑽𝒈 𝒑,𝑻= 𝑹𝒔𝒃 − 𝑹𝒔 𝑩𝒈

𝑩𝒕 = 𝑩𝒐 + 𝑹𝒔𝒃 − 𝑹𝒔 𝑩𝒈

Total System Isothermal Compressibility CoefficientAll solutions of transient fluid-flow problems

contain a parameter called the total system isothermal compressibility, written as Ct.

This property of the reservoir fluids and the porous rock is a measure of the change in volume of the fluid content of porous rock with a change in pressure, and it may vary considerably with pressure. The total system isothermal compressibility is defined

mathematically by the following relationship


𝑪𝒕 = 𝑺𝒐𝑪𝒐 + 𝑺𝒘𝑪𝒘 + 𝑺𝒈𝑪𝒈 + 𝑪𝒇

Bubble-Point Pressure

The bubble-point pressure Pb of a hydrocarbon system is defined as the highest pressure at which a bubble of gas is first liberated from the oil. This important property can be measured

experimentally for a crude oil system by conducting a constant-composition expansion test (i.e., flash liberation test). In the absence of the experimentally measured Pb,

Several graphical and mathematical correlations for determining Pb have been proposed. These correlations are essentially based on the

assumption that the bubble-point pressure is a strong function of gas solubility, gas gravity, oil gravity, and temperature, or Pb = f (Rs, γg, API, T)


Pure Component Property Constants

Many of the physical properties of pure components have been measured and compiled over the years. These properties provide essential information for studying the volumetric behavior and determining the thermodynamic properties of pure components and their mixtures. The most important of these properties are:Pc, Tc, Vc, Zc, ω, MW

Pure component property constants are often used as the basis for models such as corresponding states correlations for PVT equations of state.

They are often used in composition-dependent mixing rules for the parameters to describe mixtures.


Mixtures vs. Pure Components

. Petroleum engineers are usually interested in the behavior of hydrocarbon mixtures rather than pure components.

However, the above characteristic constants of the pure component can be used with the independent state variables such as pressure, temperature, and composition to characterize and define the physical properties and the phase behavior of mixtures.


Generalized Correlations for Estimating There are numerous correlations for estimating the

physical properties of petroleum fractions. Most of these correlations use the specific gravity γ and the boiling point Tb as correlation parameters.

Selecting proper values for the above parameters is very important because slight changes in these parameters can cause significant variations in the predicted results.


Riazi-Daubert Generalized Correlations

They developed a simple two-parameter equation for predicting the physical properties of pure compounds and undefined hydrocarbon mixtures.

Where: θ=any physical property, Tb = normal boiling point, °R γ=specific gravity and a, b, c = correlation constants are given in Table


𝜽 = 𝒂 𝑻𝒃𝒃𝜸𝒄

Boiling Points

Numerous graphical correlations have been proposed over the years for determining the physical and critical properties of petroleum fractions. Most of these correlations use the normal boiling point as one of the correlation parameters. There are five different methods of defining the normal

boiling point: Volume Average Boiling Point (VABP)Weight Average Boiling Point (WABP) Molal Average Boiling Point (MABP) Cubic Average Boiling Point (CABP) Mean Average Boiling Point (MeABP)



Molecular Weight

Figure shows a convenient graphical correlation for determining the molecular weight of petroleum

fractions from their mean average boiling points (MeABP) and API

gravities.


Critical Temperature

The critical temperature of a petroleum fraction can be

determined by using the graphical correlation shown in Figure.


Critical Pressure

Figure is a graphical correlation of the critical pressure of the

undefined petroleum fractions as a function of the mean average

boiling point (MeABP) and the API gravity.

True Critical Points of Mixtures

Pseudo critical constants are necessary if one is to use most corresponding states correlations to estimate mixture PVT{y} or derived properties. However, these pseudo critical constants often differ

considerably from the true critical points for mixtures.

There is Estimation techniques for the latter can be evaluated by comparison with experimental data.


1. Tarek, A. (1989). Hydrocarbon Phase Behavior (Gulf Publishing Company, Houston). Ch2 & Ch3 & Ch4.


1. Constant-mass expansion Experiment

2. Constant-Volume Depletion Experiment

3. Differential Liberation Experiment: Procedure


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