This document provides an overview of reservoir fluid properties, including crude oil, water, and gas properties. It discusses key properties such as formation volume factors, viscosity, surface tension, and gas solubility. It summarizes various empirical correlations used to estimate these properties based on temperature, pressure, oil composition and other factors. The document is from a course on reservoir fluid properties and focuses on definitions and methods for calculating important PVT properties.
This document provides an overview of methods for calculating reservoir fluid properties, including crude oil and water properties. It discusses calculating the total formation volume factor (Bt) using correlations like Standing's and Glaso's. It also covers calculating crude oil viscosity, including dead-oil viscosity using Beal's correlation, saturated oil viscosity using Chew-Connally, and undersaturated oil viscosity using Vasquez-Beggs. The document provides equations and discusses experimental data ranges for various fluid property correlations.
This document provides an overview of reservoir fluid properties including:
1. Crude oil properties such as density, gas solubility, bubble point pressure, formation volume factor, compressibility, and correlations to calculate these properties.
2. Water properties including water formation volume factor, viscosity, gas solubility in water, and water isothermal compressibility.
3. The total formation volume factor and viscosity of crude oil are also discussed along with definitions of dead-oil, saturated-oil, and undersaturated oil viscosities.
This document provides an overview of methods for calculating key reservoir fluid properties including: oil formation volume factor (Bo), gas solubility (Rs), bubble point pressure (Pb), oil density, and oil compressibility (Co). It describes several commonly used correlations for determining these properties as functions of temperature, pressure, gas and oil specific gravities. The correlations compared include those developed by Standing, Vasquez-Beggs, Glaso, Marhoun, and Petrosky-Farshad. The document also addresses calculating fluid properties for both undersaturated and saturated oil conditions.
This document provides an overview of key reservoir fluid properties including methods for calculating z-factors, gas properties such as compressibility and viscosity, crude oil properties like density and solution gas, and empirical correlations for determining properties like gas solubility, bubble point pressure, and formation volume factors. The document discusses various correlations for estimating properties in the absence of laboratory measurements and defines important concepts such as gas solubility, solution gas, and bubble point pressure.
This document provides an overview of methods for calculating key gas properties including:
1. The z-factor, which can be calculated using correlations like Hall-Yarborough or Dranchuk-Abu-Kassem that were developed based on the Standing-Katz chart.
2. Isothermal gas compressibility (Cg), which can be determined from the z-factor or using models that relate it to reduced gas density.
3. Gas formation volume factor (Bg) and gas expansion factor (Eg), which relate the volume of gas at reservoir conditions to standard conditions.
4. Gas viscosity, which can be estimated using correlations like Carr-Kobayashi-Burrows that are functions of
This document provides an overview of reservoir fluid properties and natural gas behavior. It discusses:
1. The importance of understanding reservoir fluid properties to predict volumetric behavior as a function of pressure. These properties are determined experimentally or through correlations.
2. Natural gas is a mixture of hydrocarbon and non-hydrocarbon gases. The properties of gas mixtures can be determined using appropriate mixing rules for the individual components.
3. Deviations from ideal gas behavior increase with pressure and temperature and gas composition. Equations of state and compressibility factors are used to more accurately model real gas behavior.
This document outlines topics covered in a reservoir engineering course, including reservoir fluid behaviors, properties of petroleum reservoirs, gas behavior, and properties of crude oil systems. It specifically discusses properties of interest like density, solution gas, bubble point pressure, formation volume factor, viscosity and more. It provides empirical correlations to estimate properties like gas solubility, bubble point pressure, and formation volume factor as a function of parameters like solubility, gas gravity, oil gravity and temperature. The document is focused on understanding physical properties of crude oil and gas reservoirs which is important for reservoir engineering applications and problem solving.
This document provides an overview of three primary reservoir fluid property experiments: constant-mass expansion (CME), constant-volume depletion (CVD), and differential liberation (DL). It describes the objectives, procedures, and key results of each experiment. The CME experiment measures formation volume factor, compressibility, and relative fluid volumes at varying pressures. The CVD simulates reservoir depletion, measuring properties like liquid dropout and gas compositions. The DL characterizes differential gas liberation from oil during pressure decline.
This document provides an overview of methods for calculating reservoir fluid properties, including crude oil and water properties. It discusses calculating the total formation volume factor (Bt) using correlations like Standing's and Glaso's. It also covers calculating crude oil viscosity, including dead-oil viscosity using Beal's correlation, saturated oil viscosity using Chew-Connally, and undersaturated oil viscosity using Vasquez-Beggs. The document provides equations and discusses experimental data ranges for various fluid property correlations.
This document provides an overview of reservoir fluid properties including:
1. Crude oil properties such as density, gas solubility, bubble point pressure, formation volume factor, compressibility, and correlations to calculate these properties.
2. Water properties including water formation volume factor, viscosity, gas solubility in water, and water isothermal compressibility.
3. The total formation volume factor and viscosity of crude oil are also discussed along with definitions of dead-oil, saturated-oil, and undersaturated oil viscosities.
This document provides an overview of methods for calculating key reservoir fluid properties including: oil formation volume factor (Bo), gas solubility (Rs), bubble point pressure (Pb), oil density, and oil compressibility (Co). It describes several commonly used correlations for determining these properties as functions of temperature, pressure, gas and oil specific gravities. The correlations compared include those developed by Standing, Vasquez-Beggs, Glaso, Marhoun, and Petrosky-Farshad. The document also addresses calculating fluid properties for both undersaturated and saturated oil conditions.
This document provides an overview of key reservoir fluid properties including methods for calculating z-factors, gas properties such as compressibility and viscosity, crude oil properties like density and solution gas, and empirical correlations for determining properties like gas solubility, bubble point pressure, and formation volume factors. The document discusses various correlations for estimating properties in the absence of laboratory measurements and defines important concepts such as gas solubility, solution gas, and bubble point pressure.
This document provides an overview of methods for calculating key gas properties including:
1. The z-factor, which can be calculated using correlations like Hall-Yarborough or Dranchuk-Abu-Kassem that were developed based on the Standing-Katz chart.
2. Isothermal gas compressibility (Cg), which can be determined from the z-factor or using models that relate it to reduced gas density.
3. Gas formation volume factor (Bg) and gas expansion factor (Eg), which relate the volume of gas at reservoir conditions to standard conditions.
4. Gas viscosity, which can be estimated using correlations like Carr-Kobayashi-Burrows that are functions of
This document provides an overview of reservoir fluid properties and natural gas behavior. It discusses:
1. The importance of understanding reservoir fluid properties to predict volumetric behavior as a function of pressure. These properties are determined experimentally or through correlations.
2. Natural gas is a mixture of hydrocarbon and non-hydrocarbon gases. The properties of gas mixtures can be determined using appropriate mixing rules for the individual components.
3. Deviations from ideal gas behavior increase with pressure and temperature and gas composition. Equations of state and compressibility factors are used to more accurately model real gas behavior.
This document outlines topics covered in a reservoir engineering course, including reservoir fluid behaviors, properties of petroleum reservoirs, gas behavior, and properties of crude oil systems. It specifically discusses properties of interest like density, solution gas, bubble point pressure, formation volume factor, viscosity and more. It provides empirical correlations to estimate properties like gas solubility, bubble point pressure, and formation volume factor as a function of parameters like solubility, gas gravity, oil gravity and temperature. The document is focused on understanding physical properties of crude oil and gas reservoirs which is important for reservoir engineering applications and problem solving.
This document provides an overview of three primary reservoir fluid property experiments: constant-mass expansion (CME), constant-volume depletion (CVD), and differential liberation (DL). It describes the objectives, procedures, and key results of each experiment. The CME experiment measures formation volume factor, compressibility, and relative fluid volumes at varying pressures. The CVD simulates reservoir depletion, measuring properties like liquid dropout and gas compositions. The DL characterizes differential gas liberation from oil during pressure decline.
This document provides an overview of a course on reservoir fluid properties. The course covers:
1. Reservoir fluid behaviors and properties of petroleum reservoirs including oil and gas.
2. Introduction to physical properties of gases including gas behavior, properties such as compressibility factor and how they are calculated for pure components and mixtures.
3. Behavior of ideal gases and real gases, definitions of compressibility factor, and use of the corresponding states principle and mixing rules to determine properties of gas mixtures.
The document discusses procedures and results from differential liberation experiments used to characterize reservoir fluids. Key points:
- Differential liberation experiments slowly depressurize a reservoir fluid sample to measure properties like oil and gas volumes, gas composition, and solution gas-oil ratio at different pressures.
- Properties measured include formation volumes factors (Bo and Bg) which indicate volume changes from reservoir to surface conditions, and solution gas-oil ratio (Rs) which provides ratio of gas to oil volumes.
- Trends in Bo, Bg and Rs with pressure provide insight into fluid behavior during production.
This document provides an overview of key concepts in reservoir fluid properties including:
- Formation volume factors (Bo and Bt) which relate the volume of oil and gas in the reservoir to stock tank conditions.
- Methods for determining PVT properties like gas solubility and Bo/Bt through laboratory experiments as pressure changes.
- Key fluid properties like bubble point pressure, compressibility, and molecular weight that impact reservoir performance.
- Techniques for estimating fluid properties using correlations with parameters like boiling point and API gravity.
The document provides an overview of a course on reservoir fluid properties. It discusses different types of hydrocarbon reservoirs and how they are classified. It describes the phase behavior of hydrocarbon mixtures using pressure-temperature diagrams. Key points on these diagrams are defined, including the bubble point curve, dew point curve, and critical point. Based on the position of the initial reservoir pressure and temperature on the diagram, reservoirs can be classified as oil or gas reservoirs. Oil reservoirs are further divided into undersaturated, saturated, and gas-cap categories. Common types of crude oils like ordinary black oil, low-shrinkage oil, and volatile oil are also described. Gas reservoirs include retrograde gas-condensate, near-critical gas-condens
The document discusses laboratory analysis techniques for gas condensate systems, including recombination and analysis of separator samples, constant-composition expansion tests, and constant-volume depletion tests. It describes the procedures for these various laboratory experiments in detail, including determining fluid properties like compressibility factors and calculating quantities like retrograde liquid saturation and cumulative gas production. The goal is to better understand the pressure-volume-temperature behavior and compositional changes that occur during depletion of a gas condensate reservoir.
This document provides an overview of methods for calculating properties of reservoir fluids including gas and crude oil. It discusses empirical correlations for calculating z-factors, gas properties like compressibility and viscosity, and crude oil properties like density, solubility of dissolved gas, and bubble point pressure. The key empirical correlations presented for estimating gas solubility (Rs) and methods for determining bubble point pressure are Standing, Vasquez-Beggs, Glaso, Marhoun, Petrosky-Farshad, and correlations based on experimental PVT data.
This document provides an overview of reservoir fluid properties and phase behavior. It discusses that reservoir fluids are mixtures of hydrocarbons and other components like water and gases. It explains the molecular structures of hydrocarbon components and defines terms like C1, C7+. The document covers phase behavior of single-component and multi-component systems using pressure-volume and pressure-temperature diagrams. It illustrates concepts of vapor pressure curves, critical points, and phase envelopes which define the different states that reservoir fluids can exist in based on temperature and pressure conditions.
This document provides an overview of key concepts for performing phase equilibrium calculations on reservoir fluids, including:
1) Cubic equations of state and properties required for components in mixtures like critical temperature, pressure, and acentric factor.
2) Calculating these properties for hydrocarbon components and lumping heavier fractions into pseudocomponents.
3) Using equations of state to relate fugacity coefficients to vapor-liquid equilibrium and calculate K-factors for flash calculations.
This document provides an overview of equations of state (EoS) models for characterizing reservoir fluids. It discusses several commonly used cubic EoS models including the van der Waals, Redlich-Kwong, Soave-Redlich-Kwong (SRK), and Peng-Robinson (PR) equations. It also covers the application of EoS models to mixtures and the characterization of C7+ hydrocarbon components in petroleum fluids. The document is intended as training material for understanding advanced EoS and modeling complex reservoir fluids.
This document provides an overview of equations of state and the compressibility factor. It discusses the ideal gas law and deviations from it, using the compressibility factor Z to quantify these deviations. Various equations of state are presented, including the van der Waals and virial equations. Cubic equations of state are discussed in depth, along with their history and widespread use in the petroleum industry. The challenges of modeling fluid properties in the critical region and at high pressures are also addressed.
This document covers reservoir engineering concepts related to properties of gas, oil, and water in reservoirs. It discusses key properties like gas compressibility, oil viscosity and density. It explains how to calculate properties of dead oil, saturated oil and undersaturated oil using various correlations. Laboratory analysis and experiments for determining fluid properties are also summarized, including different types of tests. The document provides methods to estimate properties like oil and water viscosity, gas solubility in water, and water compressibility.
This document describes procedures for analyzing reservoir fluid properties in the laboratory, including crude oil properties, water properties, and various laboratory tests. It discusses measuring the total formation volume factor, viscosity, surface tension, and other properties of crude oil and water. It also describes primary tests conducted on-site, routine laboratory tests like compositional analysis and constant-composition expansion, and special laboratory PVT tests. The constant-composition expansion test measures saturation pressure and compressibility by reducing pressure in a cell and measuring volume changes. The results are used to calculate fluid densities and compressibility coefficients above the saturation pressure.
This document discusses laboratory experiments for analyzing reservoir fluid properties, including differential liberation (vaporization) tests and separator tests. Differential liberation tests measure properties such as gas and oil volumes, densities, and compositions as pressure is reduced, better simulating reservoir separation. Separator tests determine volumetric behavior as fluids pass through surface separation, providing data to optimize conditions and calculate petroleum engineering parameters. The document explains procedures, calculations, and objectives of the tests.
The document provides an overview of a course on reservoir fluid properties. It discusses different types of hydrocarbon reservoirs including oil reservoirs which can be undersaturated, saturated, or gas-capped. Gas reservoirs include retrograde gas-condensate reservoirs where pressure reduction causes condensation, wet gas reservoirs which produce liquid at surface, and dry gas reservoirs which only produce gas. Pressure-temperature diagrams are used to classify reservoirs and illustrate phase behavior of reservoir fluids.
This document discusses compositional analysis of reservoir fluid samples. It describes how bottom hole and separator samples are taken and analyzed in the lab using gas chromatography and true boiling point distillation. Quality control checks are important to ensure samples are representative, such as verifying bottom hole samples are single-phase and separator oil and gas phase envelopes intersect at separator conditions. The ratio of component mole fractions in separator phases, known as the K-factor, is also used for quality control.
This document provides an overview of reservoir engineering 1 course material covering reservoir fluids and gas properties. It discusses:
1. Classification of oil and gas reservoirs based on pressure-temperature diagrams and fluid compositions. Reservoir fluids can exist as gas, liquid, solid, or combinations and behave differently based on reservoir conditions.
2. Key gas properties like compressibility factor, density, viscosity that are important for reservoir calculations. Real gases deviate from ideal gas behavior more at high pressures.
3. Methods for determining gas properties including compressibility factor charts and equations of state that account for non-ideal behaviors and non-hydrocarbon gas components.
Q913 rfp w3 lec 12, Separators and Phase envelope calculationsAFATous
This document outlines course material on reservoir fluid properties, separators, and phase envelope calculations. It covers topics such as PT flash processes, mixture saturation points, phase envelope determination using Michelsen's technique, and separator calculations to optimize pressure and determine stock tank oil properties. Examples of phase envelopes are shown for oil and gas condensate mixtures, illustrating properties like critical points. The document provides information to understand fluid behavior relevant to production operations.
This document provides an overview of a reservoir fluid properties course covering reservoir hydrocarbons including natural gas and crude oil. The course discusses sampling and analysis of reservoir fluids, properties of natural gases such as density and compressibility, properties of crude oils like density and gas solubility, and how reservoir fluids change from reservoir conditions to downstream production and processing facilities as pressure and temperature decrease. Key concepts covered include gas formation volume factor, gas expansion factor, gas solubility and its relationship to pressure and temperature, and methods for determining fluid properties.
This document provides an overview of reservoir fluid properties and flash calculations. It covers topics such as cubic equations of state used to model real gases, non-cubic equations of state, equations of state for mixtures, and modeling hydrocarbons. The document then focuses on flash calculations, which are used to determine the composition and amounts of hydrocarbon liquid and gas that coexist at reservoir conditions. It discusses PT flash processes, equilibrium ratios, calculating mixture saturation points, and using equations of state to model phase behavior.
The document discusses the differential liberation (vaporization) test, which simulates the separation process that occurs as reservoir fluids flow from the reservoir to the surface. The test involves gradually reducing the pressure in a visual PVT cell containing a reservoir oil sample and measuring the volume of gas liberated at each step. Key data collected includes the amount of gas in solution, oil volume shrinkage, gas composition and properties, and remaining oil density as functions of pressure. Differential oil formation volume factors and solution gas-oil ratios are calculated from the experimental data but must not be confused with actual PVT properties due to the test simulating differential behavior.
This document discusses methods for calculating porosity and water saturation from different types of porosity. It presents equations for corrected porosity, effective porosity, and water saturation. These include the RW equation for water saturation, models like the Indonesian model, Waxman-Smits, and DW model. It notes presenting final results for water saturation calculated from different porosity types and thanking the reader.
This document provides an overview of a course on reservoir fluid properties. The course covers:
1. Reservoir fluid behaviors and properties of petroleum reservoirs including oil and gas.
2. Introduction to physical properties of gases including gas behavior, properties such as compressibility factor and how they are calculated for pure components and mixtures.
3. Behavior of ideal gases and real gases, definitions of compressibility factor, and use of the corresponding states principle and mixing rules to determine properties of gas mixtures.
The document discusses procedures and results from differential liberation experiments used to characterize reservoir fluids. Key points:
- Differential liberation experiments slowly depressurize a reservoir fluid sample to measure properties like oil and gas volumes, gas composition, and solution gas-oil ratio at different pressures.
- Properties measured include formation volumes factors (Bo and Bg) which indicate volume changes from reservoir to surface conditions, and solution gas-oil ratio (Rs) which provides ratio of gas to oil volumes.
- Trends in Bo, Bg and Rs with pressure provide insight into fluid behavior during production.
This document provides an overview of key concepts in reservoir fluid properties including:
- Formation volume factors (Bo and Bt) which relate the volume of oil and gas in the reservoir to stock tank conditions.
- Methods for determining PVT properties like gas solubility and Bo/Bt through laboratory experiments as pressure changes.
- Key fluid properties like bubble point pressure, compressibility, and molecular weight that impact reservoir performance.
- Techniques for estimating fluid properties using correlations with parameters like boiling point and API gravity.
The document provides an overview of a course on reservoir fluid properties. It discusses different types of hydrocarbon reservoirs and how they are classified. It describes the phase behavior of hydrocarbon mixtures using pressure-temperature diagrams. Key points on these diagrams are defined, including the bubble point curve, dew point curve, and critical point. Based on the position of the initial reservoir pressure and temperature on the diagram, reservoirs can be classified as oil or gas reservoirs. Oil reservoirs are further divided into undersaturated, saturated, and gas-cap categories. Common types of crude oils like ordinary black oil, low-shrinkage oil, and volatile oil are also described. Gas reservoirs include retrograde gas-condensate, near-critical gas-condens
The document discusses laboratory analysis techniques for gas condensate systems, including recombination and analysis of separator samples, constant-composition expansion tests, and constant-volume depletion tests. It describes the procedures for these various laboratory experiments in detail, including determining fluid properties like compressibility factors and calculating quantities like retrograde liquid saturation and cumulative gas production. The goal is to better understand the pressure-volume-temperature behavior and compositional changes that occur during depletion of a gas condensate reservoir.
This document provides an overview of methods for calculating properties of reservoir fluids including gas and crude oil. It discusses empirical correlations for calculating z-factors, gas properties like compressibility and viscosity, and crude oil properties like density, solubility of dissolved gas, and bubble point pressure. The key empirical correlations presented for estimating gas solubility (Rs) and methods for determining bubble point pressure are Standing, Vasquez-Beggs, Glaso, Marhoun, Petrosky-Farshad, and correlations based on experimental PVT data.
This document provides an overview of reservoir fluid properties and phase behavior. It discusses that reservoir fluids are mixtures of hydrocarbons and other components like water and gases. It explains the molecular structures of hydrocarbon components and defines terms like C1, C7+. The document covers phase behavior of single-component and multi-component systems using pressure-volume and pressure-temperature diagrams. It illustrates concepts of vapor pressure curves, critical points, and phase envelopes which define the different states that reservoir fluids can exist in based on temperature and pressure conditions.
This document provides an overview of key concepts for performing phase equilibrium calculations on reservoir fluids, including:
1) Cubic equations of state and properties required for components in mixtures like critical temperature, pressure, and acentric factor.
2) Calculating these properties for hydrocarbon components and lumping heavier fractions into pseudocomponents.
3) Using equations of state to relate fugacity coefficients to vapor-liquid equilibrium and calculate K-factors for flash calculations.
This document provides an overview of equations of state (EoS) models for characterizing reservoir fluids. It discusses several commonly used cubic EoS models including the van der Waals, Redlich-Kwong, Soave-Redlich-Kwong (SRK), and Peng-Robinson (PR) equations. It also covers the application of EoS models to mixtures and the characterization of C7+ hydrocarbon components in petroleum fluids. The document is intended as training material for understanding advanced EoS and modeling complex reservoir fluids.
This document provides an overview of equations of state and the compressibility factor. It discusses the ideal gas law and deviations from it, using the compressibility factor Z to quantify these deviations. Various equations of state are presented, including the van der Waals and virial equations. Cubic equations of state are discussed in depth, along with their history and widespread use in the petroleum industry. The challenges of modeling fluid properties in the critical region and at high pressures are also addressed.
This document covers reservoir engineering concepts related to properties of gas, oil, and water in reservoirs. It discusses key properties like gas compressibility, oil viscosity and density. It explains how to calculate properties of dead oil, saturated oil and undersaturated oil using various correlations. Laboratory analysis and experiments for determining fluid properties are also summarized, including different types of tests. The document provides methods to estimate properties like oil and water viscosity, gas solubility in water, and water compressibility.
This document describes procedures for analyzing reservoir fluid properties in the laboratory, including crude oil properties, water properties, and various laboratory tests. It discusses measuring the total formation volume factor, viscosity, surface tension, and other properties of crude oil and water. It also describes primary tests conducted on-site, routine laboratory tests like compositional analysis and constant-composition expansion, and special laboratory PVT tests. The constant-composition expansion test measures saturation pressure and compressibility by reducing pressure in a cell and measuring volume changes. The results are used to calculate fluid densities and compressibility coefficients above the saturation pressure.
This document discusses laboratory experiments for analyzing reservoir fluid properties, including differential liberation (vaporization) tests and separator tests. Differential liberation tests measure properties such as gas and oil volumes, densities, and compositions as pressure is reduced, better simulating reservoir separation. Separator tests determine volumetric behavior as fluids pass through surface separation, providing data to optimize conditions and calculate petroleum engineering parameters. The document explains procedures, calculations, and objectives of the tests.
The document provides an overview of a course on reservoir fluid properties. It discusses different types of hydrocarbon reservoirs including oil reservoirs which can be undersaturated, saturated, or gas-capped. Gas reservoirs include retrograde gas-condensate reservoirs where pressure reduction causes condensation, wet gas reservoirs which produce liquid at surface, and dry gas reservoirs which only produce gas. Pressure-temperature diagrams are used to classify reservoirs and illustrate phase behavior of reservoir fluids.
This document discusses compositional analysis of reservoir fluid samples. It describes how bottom hole and separator samples are taken and analyzed in the lab using gas chromatography and true boiling point distillation. Quality control checks are important to ensure samples are representative, such as verifying bottom hole samples are single-phase and separator oil and gas phase envelopes intersect at separator conditions. The ratio of component mole fractions in separator phases, known as the K-factor, is also used for quality control.
This document provides an overview of reservoir engineering 1 course material covering reservoir fluids and gas properties. It discusses:
1. Classification of oil and gas reservoirs based on pressure-temperature diagrams and fluid compositions. Reservoir fluids can exist as gas, liquid, solid, or combinations and behave differently based on reservoir conditions.
2. Key gas properties like compressibility factor, density, viscosity that are important for reservoir calculations. Real gases deviate from ideal gas behavior more at high pressures.
3. Methods for determining gas properties including compressibility factor charts and equations of state that account for non-ideal behaviors and non-hydrocarbon gas components.
Q913 rfp w3 lec 12, Separators and Phase envelope calculationsAFATous
This document outlines course material on reservoir fluid properties, separators, and phase envelope calculations. It covers topics such as PT flash processes, mixture saturation points, phase envelope determination using Michelsen's technique, and separator calculations to optimize pressure and determine stock tank oil properties. Examples of phase envelopes are shown for oil and gas condensate mixtures, illustrating properties like critical points. The document provides information to understand fluid behavior relevant to production operations.
This document provides an overview of a reservoir fluid properties course covering reservoir hydrocarbons including natural gas and crude oil. The course discusses sampling and analysis of reservoir fluids, properties of natural gases such as density and compressibility, properties of crude oils like density and gas solubility, and how reservoir fluids change from reservoir conditions to downstream production and processing facilities as pressure and temperature decrease. Key concepts covered include gas formation volume factor, gas expansion factor, gas solubility and its relationship to pressure and temperature, and methods for determining fluid properties.
This document provides an overview of reservoir fluid properties and flash calculations. It covers topics such as cubic equations of state used to model real gases, non-cubic equations of state, equations of state for mixtures, and modeling hydrocarbons. The document then focuses on flash calculations, which are used to determine the composition and amounts of hydrocarbon liquid and gas that coexist at reservoir conditions. It discusses PT flash processes, equilibrium ratios, calculating mixture saturation points, and using equations of state to model phase behavior.
The document discusses the differential liberation (vaporization) test, which simulates the separation process that occurs as reservoir fluids flow from the reservoir to the surface. The test involves gradually reducing the pressure in a visual PVT cell containing a reservoir oil sample and measuring the volume of gas liberated at each step. Key data collected includes the amount of gas in solution, oil volume shrinkage, gas composition and properties, and remaining oil density as functions of pressure. Differential oil formation volume factors and solution gas-oil ratios are calculated from the experimental data but must not be confused with actual PVT properties due to the test simulating differential behavior.
This document discusses methods for calculating porosity and water saturation from different types of porosity. It presents equations for corrected porosity, effective porosity, and water saturation. These include the RW equation for water saturation, models like the Indonesian model, Waxman-Smits, and DW model. It notes presenting final results for water saturation calculated from different porosity types and thanking the reader.
This document provides an overview of reservoir engineering fundamentals including:
- Three types of reservoir fluids based on compressibility: incompressible, slightly compressible, and compressible.
- Three flow regimes in reservoirs: steady-state, unsteady-state, and pseudosteady-state.
- Common reservoir geometries that influence fluid flow including radial, linear, spherical, and hemispherical.
- Darcy's law and its applications to steady-state fluid flow in reservoirs, including for different fluid types and geometries.
This document provides an overview of a reservoir engineering course focused on Darcy's Law and permeability. It covers key topics like laboratory analysis of rock properties including porosity, saturation and permeability. It also discusses linear and radial flow models based on Darcy's Law and techniques for determining permeability in the laboratory and averaging permeabilities for heterogeneous reservoirs. The document emphasizes that permeability is an important property that controls fluid flow in reservoirs and was first mathematically defined by Henry Darcy. It provides the equations for linear and radial flow based on Darcy's Law.
1) The document discusses methods for calculating water saturation (SW) and formation water resistivity (RW) using well log data and interactive petrophysics programs.
2) It describes various models and techniques for determining SW, such as Archie's equation, Rwa approach, crossplots, and other empirical models. It also discusses six ways to calculate RW, including from Archie's equation, resistivity-porosity crossplots, and direct water sampling.
3) The results section calculates SW using different well log measurements and models, and determines RW from temperature and resistivity crossplots. It concludes by discussing factors that affect the accuracy of SW and RW calculations.
The forth lecture in the module Particle Technology, delivered to second year students who have already studied basic fluid mechanics.
Fluid flow in porous media covers the basic streamline and turbulent flow models for pressure drop as a function of flow rate within the media. The Modified Reynolds number determines the degree of turbulence in the fluid. The industrial processes of deep bed (sand) filtration and fluidisation are included.
The document discusses the importance of petrophysics in analyzing well logs and reservoirs. It explains that petrophysics goes beyond basic log analysis by seeking to understand why rocks hold fluids in certain ways based on their properties. This allows petrophysicists to better quantify remaining oil in existing fields and determine whether oil is movable or trapped as residual saturation. With aging fields and marginal developments, advanced petrophysical analysis is needed to understand fluid distributions and plan future well performance and recovery.
- The document discusses reservoir characteristics including rock and fluid properties that are important to understand for optimal hydrocarbon recovery. Techniques like seismic data, well logging, and testing provide valuable data to build reservoir models.
- Key rock properties that impact hydrocarbon storage and flow include porosity, permeability, and wettability. Core analysis in the lab and well logs provide data on these properties.
- Understanding fluid properties like phase behavior under reservoir conditions of pressure and temperature is also important for predicting production performance and fluid composition.
The document discusses relative permeability, which describes the ability of fluids to flow through porous media in the presence of other fluids. It covers factors that affect relative permeability like fluid saturations, rock properties, wettability, and pressure. Different wettability types can impact relative permeability curves and residual saturations. Mobility ratios also influence waterflood performance. Proper representation and measurement of relative permeability is important for reservoir evaluation and optimization.
Petrophysical Study of Reservoir Rocks: Use of Image Analysis Software (IAS...Cristian Medina
This document discusses using image analysis software (IAS) and mercury injection capillary pressure (MICP) data to characterize reservoir rocks. It finds that IAS provides a good estimate of porosity measured from core analysis, but the techniques measure different pore sizes and have limitations. MICP describes pore throats while IAS visualizes pores. The study also resolves discrepancies between IAS and core porosity measurements and finds pore shape relationships and pore size distributions can inform reservoir performance. The techniques are complementary and carbonate reservoirs pose more challenges for characterization.
This document discusses key properties of crude oil, including:
1) Oil is classified based on properties like specific gravity, viscosity, density, etc. with specific gravity and viscosity most commonly used. Specific gravity is represented by API gravity which ranges from 8 to 58 degrees.
2) Bubble point pressure is the pressure at which a small amount of gas is in equilibrium with oil. When pressure drops below this point, gas is liberated from the oil.
3) Other properties discussed include formation volume factor (ratio of reservoir to surface volumes), solution gas-oil ratio (amount of gas dissolved in oil), and compressibility (change in volume with pressure change).
Fluid saturations refer to the fraction of pore volume occupied by water, oil, or gas in a reservoir. The sum of all fluid saturations must equal 1. Fluid saturations can be measured directly from core analysis under reservoir conditions or indirectly from well log or capillary pressure analysis. Factors like drilling mud composition and changes in pressure/temperature can affect measured fluid saturations in cores. While core saturations may not accurately reflect reservoir saturations, they provide useful information on fluid contacts, minimum water saturations, and validation of indirect methods.
This document summarizes a presentation on reservoir fluid properties and their determination. It discusses current methods used to determine properties through experimentation and calculations, and problems related to smoothing experimental data and developing correlations. Specifically, it outlines issues with how differential liberation data is currently adjusted, trends in experimental data, and non-physical trends that can occur in correlations developed with limited data or constrained models. The presentation recommends alternative adjustment methods and using trend tests to evaluate correlations.
- Permeability is a property of porous rocks that measures their ability to transmit fluids. Higher permeability means fluids can flow more easily through the rock.
- Darcy's law states that for laminar flow through a permeable medium, the flow rate is proportional to the permeability of the medium and the pressure gradient, and inversely proportional to the fluid viscosity.
- There are different units used to measure and describe permeability, including darcies and millidarcies. Permeability is a key parameter in evaluating reservoir performance and fluid flow.
The document discusses how to use social media tools like Twitter, Facebook, YouTube, and blogs for business purposes. It provides tips on setting up accounts, engaging audiences, and creating compelling content for each channel. The goal is to build relationships and demonstrate your brand online through content sharing and participation in online communities. Proper use of social media can provide benefits like rapid growth, greater reach, and interconnectedness with customers and partners.
This document summarizes market research on the pharmacy market in Greater Noida, India. It estimates the current market size to be approximately 2 crore 96 lakh (29.6 million) rupees per month using a bottom-up approach, and approximately 1 crore 75 lakh (17.5 million) rupees using a top-down approach based on Greater Noida's population. The market was segmented based on commercial complexes, in-sector complexes, unorganized complexes, and hospital pharmacies. The market is expected to grow at 15% annually in line with India's domestic pharmaceutical industry growth rate. The conclusion recommends hospital pharmacies for high volume sales and in-sector or unorganized pharmacies
This document provides an overview of reservoir fluid properties analysis and various laboratory experiments used to characterize reservoir fluids, including:
- Routine laboratory tests such as compositional analysis, constant-composition expansion, differential liberation, and separator tests are used to characterize reservoir hydrocarbon fluids.
- Constant-composition expansion experiments are performed to determine saturation pressure, compressibility coefficients, and fluid volumes as a function of pressure. This involves placing a fluid sample in a cell and reducing pressure while measuring volume changes.
- Compositional analysis provides the most complete description of reservoir fluids, including mole fractions and properties of individual hydrocarbon components. More sophisticated analysis now separates components through C30 or higher.
- Other laboratory experiments include differential liberation
The document discusses key concepts of the black oil model used to describe reservoir fluids.
The black oil model treats reservoir fluids as having two components - solution gas dissolved in stock tank oil. It ignores compositional changes in gas with changing pressure and temperature. The model is used to predict properties like gas solubility, oil formation volume factor, and fluid density which are important for reservoir evaluation.
Correlations are commonly used to relate black oil parameters like gas solubility and oil formation volume factor to variables like temperature, pressure, oil and gas specific gravity. The black oil model provides a simplified approach that has been used for decades in many petroleum engineering calculations despite some limitations.
Equations for Black Oil Properties from Flash, Differential an.docxYASHU40
Equations for Black Oil Properties from Flash, Differential and Separator Data
At bubble point (pb)
Let Bob = BoSb and Rsb = RsSb , taking the Separator Test values to be correct at the bubble point.
Bob = BoSb
Rsb = RsSb
Above bubble point (pb)
Use Flash Expansion Data (Vt/Vb)f and BoSb to obtain Bo above pb.
Bo = BoSb(Vt/Vb)f
Rs = RsSb = constant
Bo below bubble point (pb)
Use Differential Expansion Data (Bod/Bodb) and BoSb to obtain Bo below pb.
Bo = BoSb(Bod/Bodb)
Rs below bubble point (pb)
Where, RsSb = total gas in solution at bubble point (pb),
Rs = (Rsdb – Rsd) = solution gas liberated while dropping pressure from pb to p in a differential test (this will be different than if done as a flash or separator test)
(BoSb/Bodb) is used to correct the differential-test-obtained Rs to what would have been obtained from a separator test for oil at pressure p.
Rs = RsSb – (Rsdb – Rsd)(Bosb/Bodb)
Oil Compressibility Equations
In terms of ordinary derivative [Eqn (1)]
Obtaining co from Flash Expansion Test data………[Eqn (2)]
Integrated form of Eqn (2) [Eqn (3)]
Integrated form of Eqn (3) [Eqn (4)]
Test Data
Flash Data (p ≥ pb )
Differential Data (p ≤ pb )
Separator Test Data
p
(Vt/Vb)f
p
Bod = (Vo/VResid)d
Rsd
(Separator p = 200 psig)
5000
0.9639
pb = 2620
Bodb = 1.600
854.0
BoSb = 1.474 RVB/STB
4500
0.9703
2350
1.554
763.0
RsSb = 768 SCF/STB
4000
0.9771
2100
1.515
684.0
3500
0.9846
1850
1.479
612.0
3000
0.9929
1600
1.445
544.0
2900
0.9946
1350
1.412
479.0
2800
0.9964
1100
1.382
416.0
2700
0.9983
850
1.351
354.0
pb = 2620
1.000
600
1.320
292.0
350
1.283
223.0
159
1.244
157.0
0
1.075
0.0
0
1.000
In class problems:
1. At p = 2800 psig, determine: Bo, Rs.
2. At p = pb = 2620 psig, determine: Bob, Rsb.
3. At p = 1850 psig, determine: Bo, Rs.
Homework problems:
4. At p = 4500 psig, determine: Bo, Rs.
5. At p = pb = 2620 psig, determine: Bob, Rsb.
6. At p = 23500 psig, determine: Bo, Rs.
7. Determine the oil compressibility (co) between the bubble point pressure (pb = 2620) and p = 3500 psi.
Answers: 1. Bo = 1.4687 RVB/STB; Rs = 768 SCF/STB. 2,5. Bo = 1.474 RVB/STB; Rs = 768 SCF/STB.
3. Bo = 1.3625 RVB/STB; Rs = 545 SCF/STB. 4. Bo = 1.4302 RVB/STB; Rs = 768 SCF/STB.
6. Bo = 1.4316 RVB/STB; Rs = 684.17 SCF/STB 7. 0.0000176 1/psi
A. Informational Questions on Black Oil, Correlations and the Regression Process
1. What is a correlation? Give one example for gas and two for oil.
2. Regression is a process that involves several steps: (a) Determine which variables are significant;
(b) Determine a functional form; (b) Determine constants for that function to minimize error.
For black oil correlations, which three quantities appear in all correlations as the basic three variables?
Give three example functional forms:
3. Explain a “black oil” model for reservoir fluid properties. ...
Laboratory and Theoretical investigations of petroleum reservoir fluid propri...Mohamed Lamoj
In this study, complete PVT lab experiments were done and then evaluate the most frequently used empirical black oil PVT correlations for application in the Middle East. Empirical PVT Correlations for Middle East crude oil have been compared as a function of commonly available PVT data. Correlations have been compared for: Bubble point pressure; solution gas oil ratio, oil formation volume factor, oil density, and oil viscosity. After evaluates the Empirical correlations the crude sample was characterized using different EOS to arrive at one EOS model that accurately describes the PVT behavior of crude oil produced.
15meos_PPT_16x9_Black Oil Property Correlations - State of the ArtMuhammad Al-Marhoun
This paper evaluates correlations to estimate properties of black oil reservoirs. It gathered black oil samples from around the world to perform a statistical analysis of existing property correlations. The paper finds the best correlations for estimating solution gas-oil ratio, bubblepoint pressure, oil formation volume factor, oil density at reservoir conditions, oil compressibility above and below bubblepoint, and oil viscosity. It provides updated equations that improve estimates of some properties like bubblepoint pressure and solution gas-oil ratio. The paper concludes some correlations need more research, like those for bubblepoint and dead oil viscosities, while most correlations for viscosity above bubblepoint are adequate. It also provides a method to adjust differential liberation data to separator conditions.
This document discusses the classification of hydrocarbon reservoirs based on the composition of reservoir fluids and pressure-temperature phase behavior. Reservoirs are broadly classified as oil or gas reservoirs based on reservoir temperature relative to the critical temperature. Oil reservoirs are further divided into undersaturated, saturated, and gas-cap categories based on initial reservoir pressure. Gas reservoirs include retrograde gas-condensate, wet gas, and dry gas depending on reservoir temperature relative to cricondentherm and critical temperature. Pressure-temperature diagrams are used to classify reservoirs and describe fluid phase behavior under different conditions.
This paper presents new correlations to calculate Modified Black-Oil (MBO) PVT properties for gas condensate and volatile oil fluids using readily available parameters without needing fluid samples or elaborate calculations. The correlations were developed using data from PVT experiments on 13 fluid samples and validated against material balance calculations and reservoir simulations. Correlations are presented for oil-gas ratio, solution gas-oil ratio, oil formation volume factor, and gas formation volume factor. The correlations showed good matches to experimental data with average errors ranging from 1-15% depending on the property.
This paper presents new correlations to predict Modified Black Oil (MBO) PVT properties for volatile oil and gas condensate reservoirs using commonly available production data instead of PVT reports or complex EOS calculations. The correlations were developed using data from 14 actual reservoir fluid samples representing different fluid compositions and behaviors. MBO properties were generated at 12 separator conditions using commercial PVT software and a statistical approach. The new correlations show reasonable agreement with MBO properties from the software. They were also validated against full compositional simulations and material balance calculations. The correlations explicitly account for separator configuration and conditions, which previous correlations did not. They provide a simpler way to model volatile oil and gas condensate reservoirs using the MBO approach.
General Material Balance Equation 1.pptxssuser4978d4
The document discusses the derivation of the general material balance equation used to evaluate reservoir performance. It describes the assumptions made, including that the reservoir is treated as a single region with average pressure and temperature. The key terms in the equation are defined, such as initial oil/gas in place, cumulative production, and formation volume factors. An example calculation is shown applying the material balance equation to determine original oil/gas in place and quantify water influx from an aquifer.
Knowledge Management: Estimate Oil API Using logs before Testing or SamplingBalaji Chennakrishnan
This document presents a novel approach to directly estimate API oil gravity from standard wireline logs using a density log vs. N cross plot. Traditionally, density, neutron, and sonic logs are used to determine porosity and lithology. Ratios M, N, and P can also be computed from these logs. The presented method observes clustering of points on a cross plot of density log vs. N that correlate to different API gravities of produced oil. The study calibrated this method using production and sample data from wells across various basins. Results show this cross plot method can reliably estimate API gravity of between 15-40 directly from logs before formation testing.
Paper-Journal of Petroleum Science and EngineeringMohamed Elias
The document presents a new inflow performance relationship (IPR) model developed based on field data from almost 50 oil reservoirs with solution gas drive.
It begins by reviewing existing IPR models, including empirical correlations from Vogel, Fetkovich, Klins, Wiggins, and Sukarno, as well as analytical correlations. The new model is then compared to these existing models using 12 field cases, finding the new model and Fetkovich's model provided the best matches with average errors of 6.6% and 7% respectively. However, the new model only requires data from a single test point versus Fetkovich's multi-rate test. The application of the new IPR model is
Gas condensate reservoirs contain fluids that are intermediate between oil and gas. At initial reservoir conditions, the fluid is gas, but during production liquid forms due to pressure and temperature changes. Most gas condensate reservoirs exist at pressures between 3,000-6,000 psi and temperatures of 200-400°F. Efficient production requires either gas reinjection to maintain pressure above dew points or gas cycling to recover liquids and reinject dry gas. Pressure depletion alone is inefficient as it leaves liquids in place and lowers production rates over time.
This document provides an overview of methods for calculating gas properties including:
1. Empirical correlations for calculating z-factors such as Hall-Yarborough and Dranchuk-Abu-Kassem.
2. Calculation of gas compressibility, gas formation volume factor, and gas expansion factor using real gas equations of state.
3. Empirical correlations for calculating gas viscosity including Carr-Kobayashi-Burrows and Lee-Gonzalez-Eakin.
This document provides an overview of methods for calculating natural gas properties including:
1. Empirical correlations for calculating gas compressibility factors such as Hall-Yarborough, Dranchuk-Abu-Kassem, and Dranchuk-Purvis-Robinson.
2. Calculation of gas formation volume factor and gas expansion factor from gas compressibility factors and properties.
3. Empirical correlations for calculating gas viscosity including Carr-Kobayashi-Burrows and Lee-Gonzalez-Eakin.
Improved Characterization of Heptane Plus Fraction of Niger Delta Light CrudesDr. Amarjeet Singh
Accurate determination of molecular weight of heptane plus(C_(7^+ )) fractions is essential in reliable phase behavior calculations and compositional EOS modeling studies. Empirical correlations provide cheaper alternatives in time and cost, to obtaining reliable molecular weight data than by experiments, though with compromised accuracies.
Several empirical correlations developed to predict molecular weight of C_(7^+ ) fractionsof petroleum were reviewed. A new correlation for calculating molecular weight of heptane plus fractions of light crudes was developed from a database compiled from Niger Delta fields for over 1,200 light crude oil assays, conventional PVT reports, and literature data. The correlation was developed using rational multiple regression analysis method.
The new correlation’s performance was compared with five others which do not depend on boiling point temperatures. Results showed that the new correlation has superior performance with the lowest absolute average and relative mean square errors. The new correlation had an average relative error of 8.15%, root mean square error of 0.09% and correlation coefficient of 0.955.
Peer Reviewed CETI 14-045: Experimental Investigation of Wet Gas Dew Point Pr...Uchenna Odi, PhD, MBA
This document presents experimental research on how carbon dioxide concentration affects the dew point pressure of wet gas mixtures. The researchers developed a new method to determine dew point pressure by tracking changes in total isothermal compressibility during depressurization experiments. Their results show that higher carbon dioxide concentration lowers the dew point pressure as expected. They compare their experimental data to calculations from the Peng Robinson equation of state to validate their new method. This relationship between carbon dioxide concentration and dew point pressure can be used to more accurately model hydrocarbon recovery processes in wet gas reservoirs.
This document appears to be lecture slides for a course on well logging in Farsi. It includes sections on topics that will be covered, references for further reading, and what appears to be notes on concepts like mud logging, sonic logs, resistivity logs, cross plots, and other well logging tools and techniques. The slides are attributed to Hossein AlamiNia from Islamic Azad University, Quchan Branch.
This document appears to be lecture notes for a class on stimulating and activating oil wells. It includes:
1. An introduction and information about the instructor.
2. Outlines for lecture topics, including well completion, well interventions, and references.
3. Schedules for class sessions with times allocated for presentations, breaks, and reviewing upcoming topics.
The document provides an overview of the class structure and topics to be covered for stimulating and activating oil wells. It outlines the lecture schedule and allocates time for presentations and reviews within the class sessions.
This document appears to be lecture notes from a geology laboratory class presented by Hossein AlamiNia from the Islamic Azad University of Ghoochan. The notes cover various topics relating to rock properties and characteristics, including rock heterogeneity, different classification systems, and methods for describing and analyzing rocks in a lab. Links are provided to online resources with additional information and sample data.
Best Competitive Marble Pricing in Dubai - ☎ 9928909666Stone Art Hub
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Starting a business is like embarking on an unpredictable adventure. It’s a journey filled with highs and lows, victories and defeats. But what if I told you that those setbacks and failures could be the very stepping stones that lead you to fortune? Let’s explore how resilience, adaptability, and strategic thinking can transform adversity into opportunity.
The Steadfast and Reliable Bull: Taurus Zodiac Signmy Pandit
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The fashion industry is dynamic and ever-changing, continuously sculpted by trailblazing visionaries who challenge norms and redefine beauty. This document delves into the profiles of some of the most iconic fashion personalities whose impact has left a lasting impression on the industry. From timeless designers to modern-day influencers, each individual has uniquely woven their thread into the rich fabric of fashion history, contributing to its ongoing evolution.
2. 1. Crude Oil Properties:
A.
B.
C.
D.
Formation volume factor for P=<Pb (Bo)
Isothermal compressibility coefficient (Co)
Formation volume factor for P>Pb (Bo)
Density
3. 1. Crude Oil Properties:
A. Total formation volume factor (Bt)
B. Viscosity (μo)
a. Dead-Oil Viscosity
b. Saturated(bubble-point)-Oil Viscosity
c. Undersaturated-Oil Viscosity
C. Surface Tension (σ)
2. Water Properties
A.
B.
C.
D.
Water Formation Volume Factor (Bw)
water viscosity (μw)
Gas Solubility in Water (Rsw)
Water Isothermal Compressibility (Cw)
4.
5. Total Formation Volume Factor
To describe the P-V 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 (Bt)
defines the total volume of a system
regardless of the number of phases present.
is defined as the ratio of the total volume of the
hydrocarbon mixture (i.e., oil and gas, if present),
at the prevailing pressure and temperature
per unit volume of the stock-tank oil.
Fall 13 H. AlamiNia
Reservoir Fluid Properties Course (2nd Ed.)
5
6. Two-Phase Formation Volume Factor
expression
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 :
above the Pb; no free gas exists
the expression is reduced to the equation that describes
the oil formation volume factor, Bo, that is:
Fall 13 H. AlamiNia
Reservoir Fluid Properties Course (2nd Ed.)
6
7. Bt and Bo vs. Pressure
A typical plot of Bt
as a function of
pressure for an
undersaturated
crude oil.
at pressures below
the Pb, 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.
Fall 13 H. AlamiNia
Reservoir Fluid Properties Course (2nd Ed.)
7
8. Volume of the Free Gas at P and T
Consider a crude oil sample placed in a PVT cell at its
bubble-point pressure, 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.
If the cell pressure is lowered 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.
the term (Rsb – Rs) represents
the volume of the free gas
as measured in scf per stock-tank barrel of oil.
Fall 13 H. AlamiNia
Reservoir Fluid Properties Course (2nd Ed.)
8
9. Bt Calculation
The volume of
There are several
the free gas
correlations that
at the cell conditions is
can be used to estimate
the two phase formation
(Vg)p,T [bbl of gas/STB of volume factor
when the experimental
oil] and Bg [bbl/scf]
data are not available;
The volume of
the remaining oil
three of these methods
at the cell condition is
are:
from the definition
Fall 13 H. AlamiNia
Standing’s correlations
Glaso’s method
Marhoun’s correlation
Reservoir Fluid Properties Course (2nd Ed.)
9
10. Bt: Standing’s and
Whitson-Brule Correlation
for predicting Bt Standing (1947)
used a total of 387 experimental data points
to develop a graphical correlation
with a reported average error of 5%
In developing his graphical correlation, Standing
used a combined correlating parameter by:
Whitson and Brule (2000) expressed Standing’s
graphical correlation by:
Fall 13 H. AlamiNia
Reservoir Fluid Properties Course (2nd Ed.)
10
11. Bt: Glaso’s Correlation
Glaso (1980) developed
a generalized correlation for estimating Bt
The experimental data on 45 crude oil samples
from the North Sea.
a standard deviation of 6.54% for Bt correlation
Glaso modified Standing’s correlating parameter A* and
used a regression analysis model
with the exponent C given by:
Fall 13 H. AlamiNia
Reservoir Fluid Properties Course (2nd Ed.)
11
12. Bt: Marhoun’s Correlation
Marhoun (1988)
Based on 1,556 experimentally determined Bt
used a nonlinear multiple-regression model
to develop a mathematical expression for Bt.
an average absolute error of 4.11%
with a standard deviation of 4.94% for the correlation
The empirical equation is:
with the correlating parameter F given by:
a = 0.644516, b = −1.079340,
c = 0.724874, d = 2.006210,
Fall 13 H. AlamiNia
e = − 0.761910
Reservoir Fluid Properties Course (2nd Ed.)
12
13.
14. Crude Oil Viscosity
Crude oil viscosity is an important physical property
that controls and influences
the flow of oil through porous media and pipes.
The oil viscosity
in general, is defined as
the internal resistance of the fluid to flow.
is a strong function of the T, P, oil gravity, γg, and Rs.
Whenever possible, should be determined
by laboratory measurements at reservoir T and P.
The viscosity is usually reported in standard PVT analyses.
Fall 13 H. AlamiNia
Reservoir Fluid Properties Course (2nd Ed.)
14
15. Crude Oil Viscosity Calculation
In absence of laboratory data, correlations, which
usually vary in complexity and accuracy depending
upon the available data on the crude oil, may used.
According to the pressure, the viscosity of crude
oils can be classified into three categories:
Dead-Oil Viscosity:
the viscosity of crude oil at atmospheric pressure
(no gas in solution) and system temperature.
Saturated(bubble-point)-Oil Viscosity:
the viscosity of the crude oil at the Pb and reservoir T
Undersaturated-Oil Viscosity:
the viscosity of the crude oil at a P above the Pb and reservoir T
Fall 13 H. AlamiNia
Reservoir Fluid Properties Course (2nd Ed.)
15
16. Estimation of the Oil Viscosity
Estimation of the oil viscosity at
P equal to or below the Pb is a two-step procedure:
Step 1. Calculate the viscosity of the oil without
dissolved gas (dead oil), μob, at the reservoir T
Step 2. Adjust the dead-oil viscosity to account for the
effect of the gas solubility at the pressure of interest.
At pressures greater than the Pb of the crude oil,
another adjustment step, i.e. Step 3, should be made
to the bubble-point oil viscosity, μob, to account for
the compression and
the degree of under-saturation in the reservoir.
Fall 13 H. AlamiNia
Reservoir Fluid Properties Course (2nd Ed.)
16
17. Methods of Calculating Viscosity of
the Dead Oil
Several empirical methods are proposed
to estimate the viscosity of the dead oil, including:
Beal’s correlation
The Beggs-Robinson correlation
Glaso’s correlation
Sutton and Farshad (1986) concluded that
Glaso’s correlation showed the best accuracy
of the three correlations.
Fall 13 H. AlamiNia
Reservoir Fluid Properties Course (2nd Ed.)
17
18. μod: Beal’s Correlation
Beal (1946) graphical correlation
for determining the viscosity of the dead oil
From a total of 753 values
for dead-oil viscosity at and above 100°F,
as a function of T and the API gravity of the crude
Standing (1981) expressed the proposed graphical
correlation in a mathematical relationship as follows:
μod = viscosity of the dead oil as measured
at 14.7 psia and reservoir temperature, cp
T = temperature, °R
Fall 13 H. AlamiNia
Reservoir Fluid Properties Course (2nd Ed.)
18
19. μod: The Beggs-Robinson Correlation
Beggs and Robinson (1975)
originated from analyzing 460 dead-oil viscosity
measurements.
An average error of −0.64% with a standard deviation of
13.53% was reported for the correlation when tested
against the data used for its development.
Sutton and Farshad (1980) reported an error of 114.3%
when the correlation was tested against 93 cases from
the literature.
Fall 13 H. AlamiNia
Reservoir Fluid Properties Course (2nd Ed.)
19
20. μod: Glaso’s Correlation
Glaso (1980) proposed a generalized mathematical
relationship for computing the dead-oil viscosity.
from experimental measurements on 26 crude oil
samples
The above expression can be used
within the range of 50–300°F for the system
temperature and 20–48° for the API gravity of the crude.
Fall 13 H. AlamiNia
Reservoir Fluid Properties Course (2nd Ed.)
20
21.
22.
23. Methods of Calculating
the Saturated Oil Viscosity
Several empirical methods are proposed to
estimate the viscosity of the saturated oil,
including:
The Chew-Connally correlation
The Beggs-Robinson correlation
Fall 13 H. AlamiNia
Reservoir Fluid Properties Course (2nd Ed.)
23
24. μob: The Chew-Connally correlation
Chew and Connally (1959) presented a graphical correlation
to adjust the dead-oil viscosity according to Rs at saturation
pressure. (from 457 crude oil samples)
Standing (1977) expressed the correlation:
μob = viscosity of the oil at Pb, cp
μod = viscosity of the dead oil at 14.7 psia and reservoir T, cp
The experimental data used by Chew and Connally to
develop their correlation encompassed the following ranges
of values for the independent variables:
Pressure, psia: 132–5,645, Temperature, °F: 72–292
Rs , scf/STB: 51–3,544, Dead oil viscosity, cp: 0.377–50
Fall 13 H. AlamiNia
Reservoir Fluid Properties Course (2nd Ed.)
24
25. μob: The Beggs-Robinson correlation
Beggs and Robinson (1975) empirical correlation
From 2,073 saturated oil viscosity measurements
accuracy of −1.83% with a standard deviation of 27.25%.
The ranges of the data used
to develop Beggs and Robinson’s equation are:
Pressure, psia: 132–5,265,
Temperature, °F: 70–295
API gravity: 16–58,
Gas solubility, scf/STB: 20–2,070
Fall 13 H. AlamiNia
Reservoir Fluid Properties Course (2nd Ed.)
25
26. Method of Calculating
the Viscosity of the Undersaturated Oil
Oil viscosity at pressures above the bubble point is
estimated by first calculating the oil viscosity at its
Pb and adjusting the bubble-point viscosity to
higher pressures.
The Vasquez-Beggs (1980) Correlation
From a total of 3,593 data points,
The average error of the viscosity correlation is −7.54%
The data used have the following ranges:
• P, psia: 141–9,151, Rs, scf/STB: 9.3–2,199,
• Viscosity, cp: 0.117–148, γg: 0.511–1.351, API : 15.3–59.5
Fall 13 H. AlamiNia
Reservoir Fluid Properties Course (2nd Ed.)
26
27.
28. Surface/Interfacial Tension
The surface tension is defined as
the force exerted on the boundary layer between a
liquid phase and a vapor phase per unit length.
This force is caused by differences between the molecular
forces in the vapor phase and those in the liquid phase, and
also by the imbalance of these forces at the interface.
The surface tension can be measured in the
laboratory and is unusually expressed in dynes per
centimeter.
The surface tension is an important property in
reservoir engineering calculations and
designing enhanced oil recovery projects.
Fall 13 H. AlamiNia
Reservoir Fluid Properties Course (2nd Ed.)
28
29. Surface Tension Correlation for
Pure Liquid
Sugden (1924) suggested a relationship that
correlates
the surface tension of a pure liquid
in equilibrium with its own vapor.
The correlating parameters are
molecular weight M of the pure component,
the densities of both phases, and
a newly introduced temperature independent parameter
Pch (parachor).
Fall 13 H. AlamiNia
Reservoir Fluid Properties Course (2nd Ed.)
29
30. Parachor Parameter
The parachor
is a dimensionless constant
characteristic of a pure
compound and
is calculated by imposing
experimentally measured
surface tension and density Fanchi’s linear equation
data on the Equation and
is only valid for components
solving for Pch.
heavier than methane.
The Parachor values for a
(Pch) i = 69.9 + 2.3 Mi
selected number of pure
compounds are given in
the Table as reported by
Weinaug and Katz (1943).
Fall 13 H. AlamiNia
Mi = molecular weight of
component i
(Pch)i =
parachor of component i
Reservoir Fluid Properties Course (2nd Ed.)
30
31. Surface Tension Correlation for
Complex Hc Mixtures
For a complex hydrocarbon mixture, Katz et al.
(1943)
employed the Sugden correlation for mixtures by
introducing the compositions of the two phases into the
Equation.
Mo & Mg = apparent molecular weight of the oil & gas phases,
xi and yi = mole fraction of component i in the oil & gas phases,
n = total number of components in the system,
ρo & ρg = density of the oil and gas phase, lb/ft3
Fall 13 H. AlamiNia
Reservoir Fluid Properties Course (2nd Ed.)
31
32.
33. Water Formation Volume Factor
The water formation volume factor can be
calculated by the following mathematical
expression:
Where the coefficients A1 − A3 are: (T in °R)
Fall 13 H. AlamiNia
Reservoir Fluid Properties Course (2nd Ed.)
33
34. μw: Meehan
Meehan (1980) proposed a water viscosity correlation
that accounts for both the effects of P and salinity:
μwT = brine viscosity at 14.7 psi & reservoir temperature T, cp
ws = weight percent of salt in brine, T = temperature in °R
The effect of pressure “p” on the brine viscosity
can be estimated from:
μw = viscosity of the brine at pressure and temperature
Fall 13 H. AlamiNia
Reservoir Fluid Properties Course (2nd Ed.)
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35. μw: Brill and Beggs
Brill and Beggs (1978)
presented a simpler equation,
which considers only temperature effects:
T is in °F and
μw is in cP
Fall 13 H. AlamiNia
Reservoir Fluid Properties Course (2nd Ed.)
35
36. Gas Solubility in Water
The following correlation can be used to determine
the gas solubility in water:
The temperature T is expressed in °F
Fall 13 H. AlamiNia
Reservoir Fluid Properties Course (2nd Ed.)
36
37. Water Isothermal Compressibility
Brill and Beggs (1978) proposed
the following equation for estimating
water isothermal compressibility,
ignoring the corrections for
dissolved gas and solids:
Fall 13 H. AlamiNia
Reservoir Fluid Properties Course (2nd Ed.)
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38. 1. Ahmed, T. (2010). Reservoir engineering
handbook (Gulf Professional Publishing).
Chapter 2