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Reservoir Fluid Properties Course (1st Ed.)

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mailto:[email protected]

http://www.about.me/AlamiNia

1. Samples

2. Sample Analysis

3. Samples Quality Control

4. K-Factor as A QC

2013 H. AlamiNia Reservoir Fluid Properties Course: Reservoir Hydrocarbons (Natural gas & Crude Oil) 2

1. Reservoir Fluid Course

2. HC Alteration

3. Properties of Natural Gases

4. Properties of Crude OilsA. density

B. Gas Solubility


Reservoir

To optimize the production from an oil or a gas field, it is essential to have extensive knowledge of The volumetric and Phase changes

The reservoir fluid is likely to undergo on its way from petroleum reservoir to oil refinery.

Reservoir pressures typically range from 100 to 1500 bar (~1450-21000 psi!), and reservoir temperatures from 50 to 200 ° C (~120-390 °F).

The well connecting the reservoir to the topside facilities can have a length of more than 2 km.


Well and Flowlines

The pressure and temperature will gradually decrease in production well. It will further decrease in flowlines connecting the well to the process plant and in the process plant itself.

Figure illustrates schematically the production path of a reservoir fluid.



Course Followed By Reservoir Fluid

Course Followed By Reservoir Fluid from Reservoir to Ambient

Conditions

Reservoir Fluid Alteration

The conditions in the reservoir itself will also change as a result of production.

A reservoir fluid, which in the exploration phase was either single-phase gas or single-phase oil, may sometime after production split into two phases. This phase split is the result of material being removed

from the reservoir.

With more space available for the remaining reservoir fluid, the pressure will decrease and may after some time reach the saturation pressure, at which a second phase (gas or oil) starts to form.


PVT Properties

PVT properties is the general term used to express the volumetric behavior of a reservoir fluid as a function of pressure and temperature.

An essential PVT property is The saturation pressure

At reservoir temperature.


Fluid Composition Alteration

From the time the reservoir pressure reaches the saturation pressure and a second phase starts to form, the composition of the produced well stream will most likely change Because the production primarily comes from either the

gas or the liquid zone.

It is customary to use the volumes of oil and gas at atmospheric pressure and 15 ° C (60°F) as reference values.

Atmospheric pressure (1 atm or 1.01325 bar) (14.5 psi) and 15 ° C are referred to as standard conditions.


Natural Gas Expression

Conventionally, natural gas compositions are expressed in terms of mole fraction, weight fraction, and volume percent. These are derived as follows: Mole Fraction: the number of moles of the component

divided by the total number of moles of all the components in the mixture. (yi=ni/n)

Weight Fraction: is defined as the weight of that component divided by the total weight. (wi=mi/m)

Volume Fraction: is defined as the volume of that compound divided by the total volume of the mixture. (vi=Vi/V)


Mixture Apparent Molecular Weight

If yi represents the mole fraction of the ith component in a gas mixture, the apparent molecular weight is defined

mathematically by the following equation:


𝑴𝑾𝒂 =

𝒊=1

𝒚𝒊 ∙ 𝑴𝑾𝒊

Ideal Gas Mixture Density and Specific Gravity The density of an ideal gas mixture is calculated by:

The specific gravity is defined as the ratio of the gas density to that of the air. Both densities must be taken at the same temperature and pressure, or:


𝝆𝒈 =𝒑𝑴𝑾𝒂𝑹𝑻

𝜸𝒈 =𝝆𝒈

𝝆𝒂𝒊𝒓=𝑴𝑾𝒂𝑴𝑾𝒂𝒊𝒓

=𝑴𝑾𝒂28.96

Compressibility of Natural Gases

A knowledge of the variability of fluid compressibility with pressure and temperature is essential in performing many reservoir engineering calculations.

For a liquid phase, the compressibility is small and usually assumed to be constant.

For a gas phase, the compressibility is neither small nor constant.


Gas Compressibility Definition

By definition, the isothermal gas compressibility is the change in volume per unit volume for a unit change in pressure, or, in equation form:

For an ideal gas, Z = 1 and (∂Z/∂p) T = 0, therefore Cg=1/p

For calculating isothermal pseudo-reduced compressibility (Cr) in terms of the pseudo-reduced pressure and temperature by simply replacing p. with (Ppc Ppr) we have Cr=CgPpc


1

𝒑𝒔𝒊𝑪𝒈 = −

1

𝑽

𝜕𝑽

𝜕𝒑𝑻

=1

𝒑−1

𝒁

𝜕𝒁

𝜕𝒑𝑻

Gas Formation Volume Factor Definition The gas formation volume factor is used to relate

the volume of gas, as measured at reservoir conditions, to the volume of the gas as measured at standard conditions, i.e., 60°F and 14. 7 psia.

This gas property is then defined as the actual volume occupied by a certain amount of gas at a specified pressure and temperature, divided by the volume occupied by the same amount of gas at standard conditions.


Bg Expression

In an equation form, the relationship is expressed as

Where Bg = gas formation volume factor, ft3/scf

Vp, T = volume of gas at pressure p and temperature T, ft3.

And V sc = volume of gas at standard conditions, scf


𝑩𝒈 =𝑽𝒑,𝑻

𝑽𝒔𝒄

Bg Expression for Real Gases

Applying the real gas EoS to the above relationship gives


𝑩𝒈 =

𝒁𝒏𝑹𝑻𝒑

𝒁𝒔𝒄 = 1)𝒏𝑹𝑻𝒔𝒄𝒑𝒔𝒄

=𝒑𝒔𝒄 = 14.7

𝑻𝒔𝒄 = 60 + 460 = 520

𝒁𝑻

𝒑

= 0.02827𝒁𝑻

𝒑,𝒇𝒕3

𝒔𝒄𝒇

= 0.005035𝒁𝑻

𝒑,𝒃𝒃𝒍

𝒔𝒄𝒇

Gas Expansion Factor

The reciprocal of the gas formation volume factor is called the Gas Expansion Factor and designated by the symbol Eg, or


𝑬𝒈

= 35.37𝒑

𝒁𝑻,𝒔𝒄𝒇

𝒇𝒕3

= 198.6𝒑

𝒁𝑻,𝒔𝒄𝒇

𝒃𝒃𝒍

Physical and Chemical Properties of Crude OilsPetroleum (an equivalent term is “crude oil") is a

complex mixture consisting predominantly of hydrocarbons, and containing sulfur, nitrogen, oxygen, and helium as minor constituents.

The physical and chemical properties of crude oils vary considerably and are dependent on the concentration of the various types of hydrocarbons and minor constituents present.


Physical Properties of Petroleum

Physical properties of primary interest in petroleum engineering studies include: Fluid densities

Isothermal compressibility

Solution gas-oil ratios

Oil formation volume factor

Fluid viscosities

Bubble-point pressure

Surface tension


Determination of Physical Properties

Data on most of these fluid properties is usually determined by laboratory experiments performed on samples of actual reservoir fluids.

In the absence of experimentally measured properties of crude oils, it· is necessary for the petroleum engineer to determine the properties from empirically derived correlations.


Crude Oil Density

Density:The crude oil density is defined as the mass of a unit

volume of the crude at a specified pressure and temperature. It is usually expressed in pounds per cubic foot.

Specific gravity:

The specific gravity of a crude oil is defined as the ratio of the density of the oil to that of water. Both densities are measured at 60°F and atmospheric pressure.


𝜸𝒐 =𝝆𝒐𝝆𝒘

Crude Oil Density Determination

As the density of water at 60°F is close to 1 g/cm3, the 60°F/60°F specific gravity of an oil sample will take approximately the same value as the density of the oil sample in g/cm3.

During the last forty years, numerous methods of calculating the density of crude oils have been proposed. There are two approaches available in the literature to calculate liquid density:The equation-of-state approach

The liquid density-correlation approach.


Standing's Method

Standing (1981) proposed an empirical correlation for estimating the oil formation volume factor as a function of the gas solubility Rs, the specific gravity of stock tank oil γo, the specific gravity of solution gas γg and the system temperature T.

Where T =system temperature, °R & γo = specific gravity of stock-tank oil


𝝆𝒐 =62.4𝜸𝒐 + 0.0136𝑹𝒔𝜸𝒈

0.972 + 0.000147 𝑹𝒔𝜸𝒈𝜸𝒐

0.5

+ 1.25 𝑻 − 460

1.175

API

Although the density and specific gravity are used extensively in the petroleum industry, the API gravity is the preferred gravity scale.

This gravity scale is precisely related to the specific gravity by the following expression:

The density of an oil from a flash to standard conditions has traditionally been expressed as API gravity.

The API gravities of crude oils usually range from 47°API for the lighter crude oils to 10° API for the heavier asphaltic crude oils.


𝑨𝑷𝑰 =141.5

𝑺𝑮 = 𝜸𝒐− 131.5

Gas Solubility

The gas solubility Rs is defined as the number of standard cubic feet of gas which will dissolve in one stock-tank barrel of crude oil at certain pressure and temperature.

The solubility of a natural gas in a crude oil is a strong function of the pressure, the temperature, the API gravity, and the gas gravity.

To determine Rs, beside experimental analysis there are many correlations (including: Beal's Correlation, Standing's Correlation, Lasater's Correlation, Vasquez-Beggs' Correlation, Glaso's Correlation, Marhoun's Correlation)


Rs vs. P and Rs vs. T Relationships


Rs Relationships

API Gravity-Rs Relationship Gas Gravity vs. Gas Solubility Relationship2013 H. AlamiNia Reservoir Fluid Properties Course: Reservoir Hydrocarbons (Natural gas & Crude Oil) 34

Rs vs. P

For a particular gas and crude oil to exist at a constant temperature, the solubility increases with pressure until the saturation pressure is reached.

At the saturation pressure (bubble-point pressure) all the available gases are dissolved in the oil and the gas solubility reaches its maximum value.



An Idealized Rs-P Diagram foran Undersaturated Oil

A typical gas solubility curve, as a function of pressure for an

undersaturated crude oil

Rs vs. P in Reality

Rather than measuring the amount of gas that will dissolve in a given stock-tank crude oil as the pressure is increased, it is customary to determine the amount of gas that will come out of a sample of reservoir crude oil as pressure decreases.

As the pressure is reduced from the initial reservoir pressure pi, to the bubble-point pressure Pb, no gas evolves from the oil and consequently the gas solubility remains constant at its maximum value of Rsb·

Below the bubble-point pressure, the solution gas is liberated and the value of Rs decreases with pressure.


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


1. Formation Volume FactorA. Oil

B. Total (two phase)

2. Property Constants


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