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Classification Of Reservoir And Reservoir Fluids
Petroleum reservoirs are broadly classified as oil or gas reservoirs. These broad classifications are further subdivided depending on:
- The composition of the reservoir hydrocarbon mixture
- Initial reservoir pressure and temperature
- Pressure and temperature of the surface production
The conditions under which these phases exist are a matter of considerable practical importance. The experimental or the mathematical determinations of these conditions are conveniently expressed in different types of diagrams commonly called phase diagrams. One such diagram is called the pressure-temperature diagram.
The Cricondentherm is defined as the maximum temperature above which liquid cannot be formed regardless of pressure. The corresponding pressure is termed the Cricondentherm pressure.
The Cricondenbar is the maximum pressure above which no gas can be formed regardless of temperature. The corresponding temperature is called the Cricondenbar temperature.
The critical point for a multicomponent mixture is referred to as the state of pressure and temperature at which all intensive properties of the gas and liquid phases are equal. At the critical point, the corresponding pressure and temperature are called the critical pressure pc and critical temperature Tc of the mixture.
Phase envelope (two-phase region)
The region enclosed by the bubble point curve and the dew-point curve, wherein gas and liquid coexist in equilibrium, is identified as the phase envelope of the hydrocarbon system.
The dashed lines within the phase diagram are called quality lines. They describe the pressure and temperature conditions for equal volumes of liquids. Note that the quality lines converge at the critical point.
The bubble-point curve is defined as the line separating the liquid-phase region from the two-phase region.
The dew-point curve is defined as the line separating the vapor-phase region from the two-phase region.
In general, reservoirs are conveniently classified on the basis of the location of the point representing the initial reservoir pressure pi and temperature T with respect to the pressure-temperature diagram of the reservoir fluid. Accordingly, reservoirs can be classified into basically two types.
If the reservoir temperature T is less than the critical temperature Tc of the reservoir fluid, the reservoir is classified as an oil reservoir.
If the reservoir temperature is greater than the critical temperature of the hydrocarbon fluid, the reservoir is considered a gas reservoir.
Depending upon initial reservoir pressure pi, oil reservoirs can be sub classified into the following categories:
Under saturated oil reservoir
If the initial reservoir pressure pi is greater than the bubble-point pressure pb of the reservoir fluid, the reservoir is labeled an under saturated oil reservoir.
Saturated oil reservoir
When the initial reservoir pressure is equal to the bubble-point pressure of the reservoir fluid, the reservoir is called a saturated oil reservoir.
If the initial reservoir pressure is below the bubble point pressure of the reservoir fluid, the reservoir is termed a gas-cap or two-phase reservoir, in which the gas or vapor phase is underlain by an oil phase. The appropriate quality line gives the ratio of the gas-cap volume to reservoir oil volume
Crude oils cover a wide range in physical properties and chemical compositions, and it is often important to be able to group them into broad categories of related oils. In general, crude oils are commonly classified into the following types:
- Ordinary black oil
- Low-shrinkage crude oil
- High-shrinkage (volatile) crude oil
- Near-critical crude oil
The above classifications are essentially based upon the properties exhibited by the crude oil, including physical properties, composition, gas-oil ratio, appearance, and pressure-temperature phase diagrams.
Ordinary black oil
It should be noted that quality lines which are approximately equally spaced characterize black oil phase diagram. The liquid shrinkage curve approximates a straight line except at very low pressures. When produced, ordinary black oils usually yield gas-oil ratios between 200–700 scf/STB and oil gravities of 15 to 40 API. The stock tank oil is usually brown to dark green in color.
The diagram is characterized by quality lines that are closely spaced near the dew-point curve. The other associated properties of this type of crude oil are:
- Oil formation volume factor less than 1.2 bbl/STB
- Gas-oil ratio less than 200 scf/STB
- Oil gravity less than 35° API
- Black or deeply colored
- Substantial liquid recovery at separator conditions
Volatile crude oil
If quality lines are close together near the bubble-point and are more widely spaced at lower pressures. This type of crude oil is commonly characterized by a high liquid shrinkage immediately below the bubble-point.
The other characteristic properties of this oil include
- Oil formation volume factor less than 2 bbl/STB
- Gas-oil ratios between 2,000–3,200 scf/STB
- Oil gravities between 45–55° API
- Lower liquid recovery of separator conditions
- Greenish to orange in color
Another characteristic of volatile oil reservoirs is that the API gravity of the stock-tank liquid will increase in the later life of the reservoirs
Near-critical crude oil
If the reservoir temperature T is near the critical temperature Tc of the hydrocarbon system the hydrocarbon mixture is identified as a near-critical crude oil. Because all the quality lines converge at the critical point, an isothermal pressure drop may shrink the crude oil from 100% of the hydrocarbon pore volume at the bubble-point to 55% or less at a pressure 10 to 50 psi below the bubble point. The near-critical crude oil is characterized by a high GOR in excess of 3,000 scf/STB with an oil formation volume factor of 2.0 bbl/STB or higher. The compositions of near-critical oils are usually characterized by 12.5 to 20 mol% heptanes-plus, 35% or more of ethane through hexanes, and the remainder methane.
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Following are some of the topics in General Composition Of Petroleum in which we provide help:
- General Composition Of Petroleum
- Physical Properties Of Hydrocarbons
- Origin of Petroleum
- Fundamental properties Of Fluid Permeated Rocks
- The Klinkenberg Effect
- Capillary Pressure
- Relative Permeability
- Drainage Process
- Three phase Relative Permeability
- Rock Compressibility
- Fundamentals Of Reservoir Fluid Behavior
- Classification Of Reservoir And Reservoir Fluids
- Gas Reservoirs
- Fundamentals Of Reservoir Fluid Flow
- Types Of Fluids
- Properties Of natural Gases
- Behavior Of Ideal Gases
- Behavior of Real Gases
- Compressibility Of Natural Gases
- Properties Of Crude Oil Systems
- Gas Solubility
- Determination And Application of Reservoir Fluid Properties
- Composition Of The Reservoir Fluid
- Differential Liberation Test
- Separator Tests
- Fluid Analysis Data On Gas
- Constant-Volume Depletion
- Oil Recovery mechanisms And The material Balance Equation
- Primary Recovery Mechanisms
- The Depletion Drive Mechanism
- Gas Cap Drive
- The Water Drive Mechanism
- Water Production
- The Gravity-Drainage-Drive Mechanism
- The Combination-Drive Mechanism
- The Material Balance Equation
- Change in Pore Volume Due to Initial Water and Rock Expansion
- Gas Reservoirs Help
- The Volumetric Method
- The material Balance Method