Q913 rfp w1 lec 2

Reservoir Fluid Properties Course (1st Ed.)

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mailto:[email protected]

http://www.about.me/AlamiNia

1. Petroleum Engineering & Its Importance

2. Petroleum Formation

3. Petroleum ExtractionA. Drilling

B. Production

4. Consumption of Oil

2013 H. AlamiNia Reservoir Fluid Properties Course: Petroleum Reservoir Fluids 2

1. Reservoir Fluids

2. Phase Behavior of Hydrocarbons

3. Phase Envelopes

4. HC Classifications


Reservoir Fluid Constituents

Petroleum reservoir fluids are multicomponent mixtures consisting primarily of hydrocarbons.Methane (CH4) is the simplest of all hydrocarbons, and

also the most common component in petroleum reservoir fluids. Because methane contains one carbon atom, it is often referred to as C1.

Hydrocarbons with seven and more carbon atoms are called C7+ components, and the entity of all C7+ components is called the C7+ fraction.

Petroleum reservoir fluids may contain hydrocarbons as heavy as C 200.


C7+ Components

A particular C7+ component will belong to one of the following component classes: Paraffins: A paraffinic compound consists of hydrocarbon segments

of the type C, CH, CH 2, or CH 3. The carbon atoms are connected by single bonds. Paraffins are also sometimes referred to as alkanes.

Naphthenes: These compounds are similar to paraffins in the sense that they are built of the same types of hydrocarbon segments, but they differ from paraffins by containing one or more cyclic structures. Naphthenes are also called cycloalkanes.

Aromatics: Similar to naphthenes, aromatics contain one or more cyclic structures, but the carbon atoms in an aromatic compound are connected by aromatic double bonds.

The percentage contents of paraffinic (P), naphthenic (N), and aromatic (A) components in a reservoir fluid is often referred to as the PNA distribution.



Molecular Structures

Molecular Structures of Some Petroleum Reservoir Fluid

Constituents

Non HC Components

Petroleum reservoir fluids may also contain inorganic compounds, of whichNitrogen (N 2), Carbon dioxide (CO 2), And hydrogen sulfide (H 2 S)

Are the most common.

Water (H 2 O) is another important reservoir fluid constituent. As water has limited miscibility with hydrocarbons, most of the water in a reservoir is usually found in a separate water zone located beneath the gas and oil zones.


Phase Behavior Definition

A "phase" is defined as any homogeneous part of a system that is physically distinct and separated from other parts of the system by definite boundaries. For example, ice, liquid water, and water vapor

constitute three separate phases of the pure substance H20. Whether a substance exists in a solid, liquid, or gas

phase is determined by the temperature and pressure acting on the substance. It is known that ice (solid phase) can be changed to

water (liquid phase) by increasing its temperature and, by further increasing temperature, water changes to steam (vapor phase). This change in phases is termed Phase Behavior.


Properties of Reservoir Fluid ConstituentsThe pure component vapor pressures and the pure

component critical points are essential in calculations of component and mixture properties.

The pure component vapor pressures are experimentally determined by measuring corresponding values of temperature (T) and pressure (P) at which the substance undergoes a transition from liquid to gas.


Single-Component Systems

The simplest type of hydrocarbon system to consider is that containing one component. The word ''component'' refers to the number of molecular or atomic species present in the substance. A single-component system is composed entirely of one kind of atom or molecule. We often use the word "pure'' to describe a single-component system.


Qualitative Understanding

The qualitative understanding of the relationship between temperature T, pressure p, and volume V of pure components can provide an excellent basis for understanding the phase behavior of complex petroleum mixtures.

The foregoing relationship is conveniently introduced in terms of experimental measurements conducted on a pure component as the component is subjected to changes in pressure and volume at constant temperature.


P-V Diagram for a Single Component System


Isothermal Paths

Suppose a fixed quantity of a pure component is placed in a cylinder fitted with a frictionless piston at a fixed temperature T 1. Consider the initial p exerted on the system to be low enough that the entire system is in the vapor state (E).

Step 1. The pressure is increased isothermally (F). On the diagram, where the liquid begins to condense.

The corresponding pressure is known as the dew-point pressure Pd, and is defined as the pressure at which the first droplet of liquid is formed.


Isothermal Paths (Cont.)

Step 2. The piston is moved further into the cylinder as more liquid condenses. This condensation process is characterized by a constant pressure and represented by the horizontal line FG.

At point G, traces of gas remain and the corresponding pressure is called the bubble-point pressure Pb, and defined as the pressure at which the first sign of gas formation is detected.

A characteristic of a single-component system is that at a given temperature, the dew-point pressure and the bubble-point pressure are equal.

Step 3. As the piston is forced slightly into the cylinder, a sharp increase in the pressure (point H) is noted without an appreciable decrease in the liquid volume. That behavior evidently reflects the low compressibility of the liquid phase.


Isothermal Paths (Cont.)

By repeating the above steps at progressively increasing temperatures, a family of curves of equal temperatures (isotherms) is constructed. The dashed curve connecting the dew points is called

the dew-point curve (line FC) and represents the states of the ''saturated gas."

The dashed curve connecting the bubble points is called the bubble-point curve (line GC) and similarly represents the "saturated liquid."

These two curves meet at point C which is known as the critical point. The corresponding pressure and volume are called the critical pressure Pc and critical volume V, respectively.


P-T Diagram for a Pure Component System.


Binary Systems (Two-Component Systems)Methane and benzene, both common constituents

of oil and gas mixtures.

The vapor pressure curve ends in the critical point (CP), above which no liquid- to gas-phase transition can take place.

Vapor pressure curves of methane and benzene (full-drawn line). Phase envelope (dashed line) of a mixture of 25 mol% methane and 75 mol% benzene calculated using the Soave–Redlich–Kwong equation of state.


Vapor Pressure Curves of Methane and Benzene


The Phase Behavior of a Pure ComponentAt a given temperature, T 1, may be studied by placing

a fixed amount of this component in a cell kept at the temperature T 1. The cell volume may be varied by moving the piston up and down. At position A, the cell content is in a gaseous state. If the

piston is moved downwards, the volume will decrease and the pressure increase.

At position B a liquid phase starts to form.

By moving the piston further downwards, the volume will further decrease, but the pressure will remain constant until all gas is converted into liquid. This happens at position C.

A further decrease in the cell volume will result in a rapidly increasing pressure.



Pure Component Phase Behavior in PT and PV Diagrams

Related to previous and next slides.

The Phase Behavior of a Pure Component (Cont.)The left-hand-side curve illustrates the phase changes

when crossing a vapor pressure curve. A pure component can only exist in the form of two phases in equilibrium right at the vapor pressure curve. When the vapor pressure curve is reached, a

conversion from either gas to liquid or liquid to gas will start. This phase transition is associated with volumetric changes at constant T and P. At the point B the component is said to be at its dew point or

in the form of a saturated gas. At position C the component is at its bubble point or in the

form of a saturated liquid. At position A the state is undersaturated gas, and at D it is

undersaturated liquid.


Phase Envelopes

Petroleum reservoir fluids are multicomponent mixtures, and it is therefore of much interest to look for the mixture equivalent of the pure component vapor pressure curve.

With two or more components present, the two-phase region is not restricted to a single line in a PT diagram.

As is illustrated for a mixture of 25 mol% methane and 75 mol% benzene, the two-phase region of a mixture forms a closed area in P and T.

The line surrounding this area is called the phase envelope.



Composition of Natural Gas Mixture

The phase envelope has been calculated using the Soave–Redlich–

Kwong equation of state

Phase Envelopes (Cont.)

Next slide shows the phase envelope of a natural gas mixture of the composition given in previous slide. The phase envelope consists of a dew point branch and

a bubble point branch meeting in the mixture critical point. At the dew point branch the mixture is in gaseous form

in equilibrium with an incipient amount of liquid. At these conditions the gas (or vapor) is said to be saturated. At higher temperatures at the same pressure, there is

no liquid present. On the contrary, the gas may take up liquid

components without liquid precipitation taking place. The gas is therefore said to be undersaturated.


Phase Envelope of Natural Gas



At the bubble point branch the mixture is in liquid form in equilibrium with an incipient amount of gas, and the liquid is said to be saturated. At lower temperatures, at the same pressure the liquid

(or oil) is undersaturated. Right at the critical point, two identical phases are in

equilibrium, both having a composition equal to the overall composition. At temperatures close to the critical one and pressures

above the critical pressure there is only one phase present, but it can be difficult to tell whether it is a gas or a liquid. This term super-critical fluid is often used the super-critical region.



The highest pressure at which two phases can exist is called the cricondenbar and the highest temperature with two phases present is called the cricondentherm. The phenomenon called retrograde condensation is as

a dashed vertical line at T = -30°C. At this temperature, the mixture is in gaseous form at pressures above the upper dew point pressure, i.e., at pressures above approximately 75 bar. At lower pressure, the mixture will split into two

phases, a gas and a liquid. Liquid formation taking place as the result of a falling pressure is called retrograde condensation. If the pressure at a constant temperature is decreased to below the lower dew point pressure of approximately 15 bar, the liquid phase will disappear, and all the mixture will be in gaseous form again.


Classification of Reservoirs

Reservoirs can be classified into essentially two types.Oil reservoirs: If the reservoir temperature T is less than

the critical temperature Tc of the reservoir fluid, the reservoir is classified as an oil reservoir.

Gas reservoirs: If the reservoir temperature is greater than the critical temperature of the hydrocarbon fluid, the reservoir is considered a gas reservoir.


Oil Reservoirs

Depending upon initial reservoir pressure pi, oil reservoirs can be sub classified into the following categories:Undersaturated Oil Reservoir: If the initial reservoir

pressure Pi, is greater than the bubble-point pressure Pb of the reservoir fluid

Saturated Oil Reservoir: When the initial reservoir pressure is equal to the bubble-point pressure of the reservoir fluid

Gas-cap Reservoir: If the initial reservoir pressure is below the bubble point pressure of the reservoir fluid. The ratio of the gas-cap volume to reservoir oil volume is given by the appropriate quality line.



Typical P-T Diagram

Typical P-T Diagram for a Multi-Component System (Oil Reservoir)

Gas Reservoirs

Natural gases can be categorized on the basis of their phase diagram and the prevailing reservoir condition into four categories: Retrograde gas-condensate

Near-critical gas-condensate

Wet gas

Dry gas


P-T Diagram for a Wet Gas Reservoir



A Typical P-T Diagram

A Typical P-T Diagram for Dry Gas Reservoir

Classification of Petroleum Reservoir FluidsPetroleum reservoir fluids may be divided into:

Natural gas mixtures(Dry and wet gas)

Gas condensate mixtures

Near-critical mixtures or volatile oils(Low-shrinkage, High-shrinkage (volatile) and Near-critical

crude oil)

(Ordinary) Black oils


Classification Base

The various fluid types are distinguished by the location of the mixture-critical temperature relative to the reservoir temperature. The above classification is essentially based upon the properties exhibited by the crude oil, including:

Physical properties

Composition

Gas-oil ratio

Appearance

Pressure-temperature phase diagram


Exercise

Determine mentioned properties for each type of oil and gas reservoirs.



Phase Envelope of Various Types of Reservoir Fluids

The phase envelopes have been constructed using the Peng–

Robinson equation of state

Tracking P & T during Production in Gas ReservoirsDuring production from a reservoir, the temperature

remains approximately constant at the initial reservoir temperature, Tres, whereas the pressure decreases as a result of material being removed from the reservoir.

For a natural gas, this pressure decrease will have no impact on the number of phases. The gas will remain a single phase at all pressures.

For a gas condensate, a decreasing pressure will at some stage lead to the formation of a second phase. This happens when the pressure reaches the dew point branch at the temperature Tres. The second phase forming will be a liquid phase, a phase of a higher density than the original phase.


Composition of Gas Condensate Mixture


Tracking P & T during Production in Near-Critical MixtureWith a near-critical mixture, a pressure decrease will

also at some stage lead to the formation of a second phase. If the reservoir temperature is Tres, the second phase will be a gas phase, because the point at which the phase envelope is reached is on the bubble point branch. Such a mixture will be classified as a volatile oil. Had the reservoir temperature been slightly higher as

indicated by T'res, the entry into the two-phase region would take place at the dew point branch, and the mixture would be classified as a gas condensate mixture. Near-critical reservoir fluids are mixtures with critical

temperatures close to the reservoir temperature. Right inside the phase envelope the gas- and liquid-phase compositions and properties are similar.


Composition of Near-Critical Mixture


Close-Up of the Near-Critical Region

Next slide shows a close-up of the near-critical region of a Chinese reservoir fluid (Yang et al., 1997).

It illustrates the fact that the relative volumetric amounts of gas and liquid change rapidly with pressure and temperature in the vicinity of the CP. For example, at a temperature of 100°C only a marginal change in pressure is needed to change the liquid-phase amount from 50 to 100 vol%.



Near-Critical Part of Phase Envelope

The values stated are liquid volume percentages. CP stands for critical

point.

Tracking P & T during Production in Oil ReservoirsFinally with black oils, entry into the two-phase

region at the reservoir temperature will always take place at the bubble point side and, accordingly, the new phase forming is a gas.


Composition of Oil Mixture


1. Samples

2. Sample Analysis

3. Samples Quality Control

4. K-Factor as A QC


1. Pedersen, K.S., Christensen, P.L., and Azeem, S.J. (2006). Phase behavior of petroleum reservoir fluids (CRC Press). Ch1.

2. Tarek, A. (1989). Hydrocarbon Phase Behavior (Gulf Publishing Company, Houston). Ch1.


Q913 rfp w1 lec 2

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