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 discusses well testing and well test analysis software programs. It provides information on:
- The objectives of well testing including identifying fluid types and reservoir parameters
- Types of well tests including productivity tests for development wells and descriptive tests for exploration wells
- Popular well test software programs for analytical and numerical analysis including Saphir, PanSystem, Interpret 2000, and Weltest 200
- An overview of the Weltest 200 program which links analytical and numerical well test analysis through different modules
- Using an example of liquid productivity or IPR testing to demonstrate how well test data is incorporated and analyzed in the software
Skin factor is a dimensionless parameter that quantifies the formation damage around the wellbore. it also can be negative (which indicates improvement in flow) OR positive (which means formation damage exists). Positive skin can lead to severe well production issues and thus reducing the well revenue
This document provides information about reservoir engineering. It discusses how reservoir engineers use tools like subsurface geology, mathematics, and physics/chemistry to understand fluid behavior in reservoirs. It also describes different well classes used for injection/extraction, environmental impacts of enhanced oil recovery, and various reservoir engineering techniques like simulation modeling, production surveillance, and evaluating volumetric sweep efficiency. Thermal and chemical enhanced oil recovery methods are explained, including gas, steam, polymer, surfactant, microbial and in-situ combustion injection.
This 5 day training course is designed to give you a comprehensive account of methods and techniques used in modern well testing and analysis. Subsequently to outlining well test objectives and general methodologies applied, the course will provide real case studies and practice using modern software for Pressure Transient Analysis. These exercises will demonstrate clearly the limitations, assumptions and applicability of various techniques applied in the field.
1) The document discusses methods for determining reservoir pressure gradients, depths of fluid interfaces like gas-oil and oil-water contacts, and pressures at various points from measured well data.
2) Equations are provided to calculate pressure gradients between two depths, depths of hydrocarbon interfaces using gradients above and below the interface, and pressures at perforations or contacts using the gradient and depth.
3) An example problem demonstrates calculating gradients, gas-oil contact depth, oil-water contact depth, and pressures at the contacts and perforations using a table of depth and pressure measurements.
This document provides an overview of Darcy's law and permeability concepts covered in a reservoir engineering course. It begins by defining permeability as a property that controls fluid flow in porous media. Darcy's law is then introduced, which relates fluid flow rate to pressure drop, permeability, fluid properties, and geometry. The document goes on to discuss permeability measurement techniques, effective and relative permeability, reservoir properties, heterogeneity, and applications of Darcy's law to linear and radial flow models.
This document provides an introduction and overview of pressure transient testing and analysis. It discusses:
I. The importance of production data analysis for reservoir evaluation, management, and description.
II. Basic definitions like drawdown tests, buildup tests, and flow regimes. The objectives of well testing like determining permeability, skin, pore volume, and detecting heterogeneity.
III. The ideal reservoir model and assumptions made in pressure transient analysis, like radial flow, homogenous properties, and infinite-acting reservoirs. Equations used like the diffusivity equation.
The document covers reservoir engineering concepts including solutions to the diffusivity equation for radial flow of single-phase and compressible fluids. It discusses the pD and Ei-function solutions, and presents the unified steady-state flow regime equations for radial flow of single-phase and compressible fluids using the pD-function, m(p)-function, and pressure-squared approximations. It also covers the pseudo-steady state flow regime and relationships between pressure functions.
This document discusses well testing and well test analysis software programs. It provides information on:
- The objectives of well testing including identifying fluid types and reservoir parameters
- Types of well tests including productivity tests for development wells and descriptive tests for exploration wells
- Popular well test software programs for analytical and numerical analysis including Saphir, PanSystem, Interpret 2000, and Weltest 200
- An overview of the Weltest 200 program which links analytical and numerical well test analysis through different modules
- Using an example of liquid productivity or IPR testing to demonstrate how well test data is incorporated and analyzed in the software
Skin factor is a dimensionless parameter that quantifies the formation damage around the wellbore. it also can be negative (which indicates improvement in flow) OR positive (which means formation damage exists). Positive skin can lead to severe well production issues and thus reducing the well revenue
This document provides information about reservoir engineering. It discusses how reservoir engineers use tools like subsurface geology, mathematics, and physics/chemistry to understand fluid behavior in reservoirs. It also describes different well classes used for injection/extraction, environmental impacts of enhanced oil recovery, and various reservoir engineering techniques like simulation modeling, production surveillance, and evaluating volumetric sweep efficiency. Thermal and chemical enhanced oil recovery methods are explained, including gas, steam, polymer, surfactant, microbial and in-situ combustion injection.
This 5 day training course is designed to give you a comprehensive account of methods and techniques used in modern well testing and analysis. Subsequently to outlining well test objectives and general methodologies applied, the course will provide real case studies and practice using modern software for Pressure Transient Analysis. These exercises will demonstrate clearly the limitations, assumptions and applicability of various techniques applied in the field.
1) The document discusses methods for determining reservoir pressure gradients, depths of fluid interfaces like gas-oil and oil-water contacts, and pressures at various points from measured well data.
2) Equations are provided to calculate pressure gradients between two depths, depths of hydrocarbon interfaces using gradients above and below the interface, and pressures at perforations or contacts using the gradient and depth.
3) An example problem demonstrates calculating gradients, gas-oil contact depth, oil-water contact depth, and pressures at the contacts and perforations using a table of depth and pressure measurements.
This document provides an overview of Darcy's law and permeability concepts covered in a reservoir engineering course. It begins by defining permeability as a property that controls fluid flow in porous media. Darcy's law is then introduced, which relates fluid flow rate to pressure drop, permeability, fluid properties, and geometry. The document goes on to discuss permeability measurement techniques, effective and relative permeability, reservoir properties, heterogeneity, and applications of Darcy's law to linear and radial flow models.
This document provides an introduction and overview of pressure transient testing and analysis. It discusses:
I. The importance of production data analysis for reservoir evaluation, management, and description.
II. Basic definitions like drawdown tests, buildup tests, and flow regimes. The objectives of well testing like determining permeability, skin, pore volume, and detecting heterogeneity.
III. The ideal reservoir model and assumptions made in pressure transient analysis, like radial flow, homogenous properties, and infinite-acting reservoirs. Equations used like the diffusivity equation.
The document covers reservoir engineering concepts including solutions to the diffusivity equation for radial flow of single-phase and compressible fluids. It discusses the pD and Ei-function solutions, and presents the unified steady-state flow regime equations for radial flow of single-phase and compressible fluids using the pD-function, m(p)-function, and pressure-squared approximations. It also covers the pseudo-steady state flow regime and relationships between pressure functions.
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
1. The document discusses various mathematical models for estimating water influx into oil and gas reservoirs, including the Pot aquifer model, Schilthuis' steady-state model, and Hurst's modified steady-state model. It describes the assumptions and equations of each model.
2. Determining water influx is challenging due to uncertainties about aquifer properties which are rarely known with accuracy. Models require historical reservoir data to evaluate constants representing aquifer parameters.
3. Common water influx models include Pot aquifer, Schilthuis' steady-state, Hurst's modified steady-state, van Everdingen-Hurst unsteady-state, and others. The document provides details on implementing some of these models
The document discusses cement used in oil and gas wells. It covers cement composition, classes of cement, additives for controlling density, acceleration, retardation and viscosity. It also discusses cementing operations, equipment and performing a good cementing job. Key factors include casing centralization, pipe movement, drilling fluid viscosity, hole condition and achieving proper displacement velocity.
Overview of Reservoir Simulation by Prem Dayal Saini
Reservoir simulation is the study of how fluids flow in a hydrocarbon reservoir when put under production conditions. The purpose is usually to predict the behavior of a reservoir to different production scenarios, or to increase the understanding of its geological properties by comparing known behavior to a simulation using different geological representations.
This document outlines topics covered in a reservoir engineering course, including:
1. PSS regimes for radial flow of single- and multi-phase fluids and the effect of well location.
2. The skin concept and using skin factors in flow equations.
3. The superposition principle for accounting for multiple wells, rate changes, boundaries, and pressure changes.
4. Applications of superposition include predicting pressure behavior for multiple wells, multi-rate wells, bounded reservoirs using image wells, and pressure changes.
5. Transient well testing provides reservoir properties through pressure response analysis.
This document outlines the key concepts in reservoir engineering. It discusses reservoir characteristics including fluid types, flow regimes, and geometries. It then covers steady-state and unsteady-state flow, defining transient flow as the period where the reservoir boundary has no effect. The document derives the diffusivity equation from continuity, transport, and compressibility equations. It discusses the assumptions and solutions of the diffusivity equation, including constant-terminal pressure and rate solutions.
This document provides an overview of reservoir engineering concepts for predicting vertical oil well performance, including productivity index, inflow performance relationship, and methods for modeling these relationships. It discusses key topics like:
- Defining and measuring productivity index using stabilized well test data
- How productivity index, inflow performance relationship, and well flow rates relate under pseudosteady state conditions
- Factors influencing productivity index like fluid properties and relative permeability
- Empirical methods like Vogel's method for generating inflow performance curves over the life of depleting reservoirs
The document is from a course on reservoir engineering concepts for vertical wells, with the goal of teaching practical equations to model well performance and factors governing fluid flow.
Casing Seat depth and Basic casing design lecture 4.pdfssuserfec9d8
1. The maximum gas kick pressure from the total depth as the internal pressure.
2. Formation pore pressure at the casing shoe as the external pressure.
3. The casing must be designed to withstand the difference between the maximum internal gas kick pressure and external pore pressure, known as the resultant pressure.
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.
The document provides an overview of reservoir engineering concepts related to waterflooding projects for oil recovery. It discusses primary, secondary, and tertiary recovery categories. For waterflooding projects specifically, it outlines key factors to consider like reservoir geometry, fluid properties, depth, lithology, fluid saturations, uniformity, and natural driving mechanisms. It provides details on evaluating these factors and their implications for project suitability and design.
This document provides an overview of well log interpretation. It discusses how well logs are used to answer key questions about hydrocarbon-bearing formations like location, quantity, and producibility. The interpretation process involves identifying permeable zones using logs like SP and GR, then using resistivity and porosity logs to locate zones with hydrocarbons. Formations are further evaluated to determine porosity, fluid saturations, and other properties through techniques like density-neutron crossplots, environmental corrections, and determining formation temperature based on geothermal gradient. The goal is to locate potential producing zones and estimate hydrocarbon quantities and recoverability.
The document discusses the functions and types of casing strings used in oil and gas wells. It describes the different casing strings like conductor casing, surface casing, intermediate casing, and production casing. It also covers casing design criteria like classifications based on outside diameter, length, connections, weight, and grade. The mechanical properties of casing are discussed in relation to withstanding tensile, burst, and collapse loads during drilling and production operations.
prediction of original oil in place using material balance simulation. It's also useful for future reservoir performance and predict ultimate hydrocarbon recovery under various types of primary driving mechanisms.
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
What is the different between the net pay and resrvoir thicknessStudent
Prepared by Yasir Albeatiy
Contact me with information below:
E-Mail: yasiralbeatiy2015@gmail.com
Phone No. + Whatsapp : +9647828319225
Facebook Page: www.facebook.com/petroleumengineeringz
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.
Exploring formation pressures based on Chapter 5 of Heriot-Watt Drilling Engineering book. Pressure prediction, well planning, well bore stability aspects are also covered in the slide-pack.
- Reservoirs are classified based on the composition of hydrocarbons present, initial reservoir pressure and temperature, and the pressure and temperature of produced fluids.
- A pressure-temperature diagram is used to classify reservoirs and describe the phase behavior of reservoir fluids, delineating the liquid, gas, and two-phase regions.
- Based on the diagram, reservoirs are classified as oil reservoirs if the temperature is below the critical temperature, and gas reservoirs if above the critical temperature.
This document discusses reservoir characteristics, rock and fluid properties, and drive mechanisms. It provides information on:
1) Techniques like seismic data, well logging, core analysis, and well testing that are used to understand the reservoir and develop an accurate reservoir model.
2) Reservoir characteristics including rock type, porosity, permeability, and factors that allow hydrocarbon accumulation like sufficient pore space and traps.
3) Rock properties such as porosity, permeability, and how they impact fluid flow.
4) Fluid properties including phase behavior under varying pressures and temperatures, properties of different fluid types, and sampling techniques.
5) Common experiments done to analyze reservoir fluids using pressure-volume-temperature cells
This document discusses using the Ensemble Kalman Filter (EnKF) for history matching and production forecasts of oil reservoirs. It presents the EnKF algorithm and applies it to a synthetic 3D reservoir model. The EnKF allows updating reservoir properties like porosity and permeability from production data. Results show the EnKF ensemble matches observations better than without updating. Further work is needed to study the impact of observation availability and representativeness of the ensemble.
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
1. The document discusses various mathematical models for estimating water influx into oil and gas reservoirs, including the Pot aquifer model, Schilthuis' steady-state model, and Hurst's modified steady-state model. It describes the assumptions and equations of each model.
2. Determining water influx is challenging due to uncertainties about aquifer properties which are rarely known with accuracy. Models require historical reservoir data to evaluate constants representing aquifer parameters.
3. Common water influx models include Pot aquifer, Schilthuis' steady-state, Hurst's modified steady-state, van Everdingen-Hurst unsteady-state, and others. The document provides details on implementing some of these models
The document discusses cement used in oil and gas wells. It covers cement composition, classes of cement, additives for controlling density, acceleration, retardation and viscosity. It also discusses cementing operations, equipment and performing a good cementing job. Key factors include casing centralization, pipe movement, drilling fluid viscosity, hole condition and achieving proper displacement velocity.
Overview of Reservoir Simulation by Prem Dayal Saini
Reservoir simulation is the study of how fluids flow in a hydrocarbon reservoir when put under production conditions. The purpose is usually to predict the behavior of a reservoir to different production scenarios, or to increase the understanding of its geological properties by comparing known behavior to a simulation using different geological representations.
This document outlines topics covered in a reservoir engineering course, including:
1. PSS regimes for radial flow of single- and multi-phase fluids and the effect of well location.
2. The skin concept and using skin factors in flow equations.
3. The superposition principle for accounting for multiple wells, rate changes, boundaries, and pressure changes.
4. Applications of superposition include predicting pressure behavior for multiple wells, multi-rate wells, bounded reservoirs using image wells, and pressure changes.
5. Transient well testing provides reservoir properties through pressure response analysis.
This document outlines the key concepts in reservoir engineering. It discusses reservoir characteristics including fluid types, flow regimes, and geometries. It then covers steady-state and unsteady-state flow, defining transient flow as the period where the reservoir boundary has no effect. The document derives the diffusivity equation from continuity, transport, and compressibility equations. It discusses the assumptions and solutions of the diffusivity equation, including constant-terminal pressure and rate solutions.
This document provides an overview of reservoir engineering concepts for predicting vertical oil well performance, including productivity index, inflow performance relationship, and methods for modeling these relationships. It discusses key topics like:
- Defining and measuring productivity index using stabilized well test data
- How productivity index, inflow performance relationship, and well flow rates relate under pseudosteady state conditions
- Factors influencing productivity index like fluid properties and relative permeability
- Empirical methods like Vogel's method for generating inflow performance curves over the life of depleting reservoirs
The document is from a course on reservoir engineering concepts for vertical wells, with the goal of teaching practical equations to model well performance and factors governing fluid flow.
Casing Seat depth and Basic casing design lecture 4.pdfssuserfec9d8
1. The maximum gas kick pressure from the total depth as the internal pressure.
2. Formation pore pressure at the casing shoe as the external pressure.
3. The casing must be designed to withstand the difference between the maximum internal gas kick pressure and external pore pressure, known as the resultant pressure.
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.
The document provides an overview of reservoir engineering concepts related to waterflooding projects for oil recovery. It discusses primary, secondary, and tertiary recovery categories. For waterflooding projects specifically, it outlines key factors to consider like reservoir geometry, fluid properties, depth, lithology, fluid saturations, uniformity, and natural driving mechanisms. It provides details on evaluating these factors and their implications for project suitability and design.
This document provides an overview of well log interpretation. It discusses how well logs are used to answer key questions about hydrocarbon-bearing formations like location, quantity, and producibility. The interpretation process involves identifying permeable zones using logs like SP and GR, then using resistivity and porosity logs to locate zones with hydrocarbons. Formations are further evaluated to determine porosity, fluid saturations, and other properties through techniques like density-neutron crossplots, environmental corrections, and determining formation temperature based on geothermal gradient. The goal is to locate potential producing zones and estimate hydrocarbon quantities and recoverability.
The document discusses the functions and types of casing strings used in oil and gas wells. It describes the different casing strings like conductor casing, surface casing, intermediate casing, and production casing. It also covers casing design criteria like classifications based on outside diameter, length, connections, weight, and grade. The mechanical properties of casing are discussed in relation to withstanding tensile, burst, and collapse loads during drilling and production operations.
prediction of original oil in place using material balance simulation. It's also useful for future reservoir performance and predict ultimate hydrocarbon recovery under various types of primary driving mechanisms.
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
What is the different between the net pay and resrvoir thicknessStudent
Prepared by Yasir Albeatiy
Contact me with information below:
E-Mail: yasiralbeatiy2015@gmail.com
Phone No. + Whatsapp : +9647828319225
Facebook Page: www.facebook.com/petroleumengineeringz
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.
Exploring formation pressures based on Chapter 5 of Heriot-Watt Drilling Engineering book. Pressure prediction, well planning, well bore stability aspects are also covered in the slide-pack.
- Reservoirs are classified based on the composition of hydrocarbons present, initial reservoir pressure and temperature, and the pressure and temperature of produced fluids.
- A pressure-temperature diagram is used to classify reservoirs and describe the phase behavior of reservoir fluids, delineating the liquid, gas, and two-phase regions.
- Based on the diagram, reservoirs are classified as oil reservoirs if the temperature is below the critical temperature, and gas reservoirs if above the critical temperature.
This document discusses reservoir characteristics, rock and fluid properties, and drive mechanisms. It provides information on:
1) Techniques like seismic data, well logging, core analysis, and well testing that are used to understand the reservoir and develop an accurate reservoir model.
2) Reservoir characteristics including rock type, porosity, permeability, and factors that allow hydrocarbon accumulation like sufficient pore space and traps.
3) Rock properties such as porosity, permeability, and how they impact fluid flow.
4) Fluid properties including phase behavior under varying pressures and temperatures, properties of different fluid types, and sampling techniques.
5) Common experiments done to analyze reservoir fluids using pressure-volume-temperature cells
This document discusses using the Ensemble Kalman Filter (EnKF) for history matching and production forecasts of oil reservoirs. It presents the EnKF algorithm and applies it to a synthetic 3D reservoir model. The EnKF allows updating reservoir properties like porosity and permeability from production data. Results show the EnKF ensemble matches observations better than without updating. Further work is needed to study the impact of observation availability and representativeness of the ensemble.
This document outlines the topics covered in a Reservoir Engineering 1 course, including crude oil and water properties, laboratory experiments, and rock properties. The key laboratory experiments discussed are: compositional analysis to characterize reservoir fluids; constant-composition expansion tests to determine fluid properties over a range of pressures; differential liberation tests to analyze gas dissolved in oil; and separator tests to model fluid behavior during production and separation. Special core analysis tests measure critical rock properties such as porosity, permeability, and wettability that influence fluid flow. Accurate characterization of fluids and rocks through laboratory experiments is essential for reservoir evaluation and performance predictions.
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.
This document outlines the syllabus for a Reservoir Engineering 1 course. The 3 credit hour course is intended for sophomore and junior petroleum engineering students and covers fundamental reservoir engineering concepts and their practical applications. Lectures will be divided into two 50-slide presentations with a short break. Students will be assessed based on class activities, a midterm exam, and a final exam. The course schedule lists 16 lectures covering topics like petroleum reservoirs, fluid properties, laboratory experiments, and production methods. Major references and resources are also provided.
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 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 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.
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 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.
This document covers reservoir engineering concepts related to petroleum reservoirs. It discusses the classification of oil and gas reservoirs based on phase behavior and pressure-temperature relationships. It also summarizes key reservoir fluid properties for both gas and crude oil, including compressibility factors, density, molecular weight, and formation volume factors. The behaviors of real gases are contrasted with ideal gases and methods for determining compressibility factors are presented.
Physical and chemical properties of petroleumkhurasani
Petroleum is a naturally occurring liquid found beneath the Earth's surface that is refined into fuels. It consists mainly of hydrocarbons like alkanes, naphthenes, and aromatics. Petroleum forms from the thermal maturation of buried organic matter over millions of years. It varies in composition but is largely made up of carbon and hydrogen, with other elements like sulfur, oxygen, and nitrogen present in smaller amounts. The type of petroleum depends on factors like the organic material it formed from and temperature/pressure conditions during formation.
Heinemann zoltán e[1]._-_petroleum_recovery_Hanhndcnm
This document is the third volume in a textbook series on petroleum engineering by Zoltán E. Heinemann. It covers topics related to petroleum recovery methods. The volume is intended for readers with a background in properties of porous media and single- and two-phase flow in reservoirs. The topics discussed include volumetric reserves calculations, material balance methods, displacement efficiency concepts like solution gas drive and frontal displacement, sweep efficiency factors, and decline curve analysis. The textbook is part of a seven-volume series used to teach reservoir engineering at Montanuniversität Leoben.
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.
This document provides an overview of a reservoir engineering course covering topics like:
- PSS and skin concepts for radial flow of single- and multi-phase fluids
- Turbulent versus laminar flow and models for turbulent/non-Darcy flow
- The concept of superposition and its applications, including effects of multiple wells, rate changes, boundaries, and pressure changes
- Transient well testing methods and the information they provide about a reservoir's properties
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 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 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 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 reservoir fluid properties, including crude oil, water, and gas properties. It discusses key crude oil properties such as formation volume factor, viscosity, and surface tension. It describes methods for calculating total formation volume factor, oil viscosity at different pressures, and surface tension. Water properties like water formation volume factor and viscosity are also covered. Empirical correlations are presented for estimating various fluid properties in the absence of experimental data.
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.
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.
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.
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 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.
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.
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 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.
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 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 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 methods for determining the compressibility factor (Z) in gas mixtures. It defines different types of natural gas and describes using pseudocritical properties and reduced conditions to calculate Z based on corresponding states theory. The Standing-Katz method is commonly used to determine Z for sweet gases graphically using reduced pressure and temperature. This method can be modified to account for sour gases containing H2S and CO2 by adjusting the pseudocritical properties. An example calculation demonstrates determining the volume of a gas sample at different conditions using both the unmodified and modified Standing-Katz methods.
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.
Gases have no definite volume and assume the volume of any vessel. The behavior of gases is described by gas laws including Boyle's law, Charles' law, Avogadro's law, and the ideal gas law. Real gases deviate from ideal behavior at high pressures and low temperatures and are better described by equations like van der Waals. Key gas properties include gas formation volume factor, gas compressibility factor, gas viscosity, and gas solubility in oil. Gas formation volume factor relates the volume of gas at reservoir conditions to standard surface conditions.
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.
This presentation includes basic of PCOS their pathology and treatment and also Ayurveda correlation of PCOS and Ayurvedic line of treatment mentioned in classics.
A Strategic Approach: GenAI in EducationPeter Windle
Artificial Intelligence (AI) technologies such as Generative AI, Image Generators and Large Language Models have had a dramatic impact on teaching, learning and assessment over the past 18 months. The most immediate threat AI posed was to Academic Integrity with Higher Education Institutes (HEIs) focusing their efforts on combating the use of GenAI in assessment. Guidelines were developed for staff and students, policies put in place too. Innovative educators have forged paths in the use of Generative AI for teaching, learning and assessments leading to pockets of transformation springing up across HEIs, often with little or no top-down guidance, support or direction.
This Gasta posits a strategic approach to integrating AI into HEIs to prepare staff, students and the curriculum for an evolving world and workplace. We will highlight the advantages of working with these technologies beyond the realm of teaching, learning and assessment by considering prompt engineering skills, industry impact, curriculum changes, and the need for staff upskilling. In contrast, not engaging strategically with Generative AI poses risks, including falling behind peers, missed opportunities and failing to ensure our graduates remain employable. The rapid evolution of AI technologies necessitates a proactive and strategic approach if we are to remain relevant.
Executive Directors Chat Leveraging AI for Diversity, Equity, and InclusionTechSoup
Let’s explore the intersection of technology and equity in the final session of our DEI series. Discover how AI tools, like ChatGPT, can be used to support and enhance your nonprofit's DEI initiatives. Participants will gain insights into practical AI applications and get tips for leveraging technology to advance their DEI goals.
A workshop hosted by the South African Journal of Science aimed at postgraduate students and early career researchers with little or no experience in writing and publishing journal articles.
How to Build a Module in Odoo 17 Using the Scaffold MethodCeline George
Odoo provides an option for creating a module by using a single line command. By using this command the user can make a whole structure of a module. It is very easy for a beginner to make a module. There is no need to make each file manually. This slide will show how to create a module using the scaffold method.
Macroeconomics- Movie Location
This will be used as part of your Personal Professional Portfolio once graded.
Objective:
Prepare a presentation or a paper using research, basic comparative analysis, data organization and application of economic information. You will make an informed assessment of an economic climate outside of the United States to accomplish an entertainment industry objective.
it describes the bony anatomy including the femoral head , acetabulum, labrum . also discusses the capsule , ligaments . muscle that act on the hip joint and the range of motion are outlined. factors affecting hip joint stability and weight transmission through the joint are summarized.
2. 1. Reservoir Fluid Behaviors
2. Petroleum Reservoirs
A. Oil
B. Gas
3. Gas Behavior
4. Gas Properties:
A.
B.
C.
D.
Z Factor
Isothermal gas compressibility (Cg)
Gas formation volume factor (Bg)
Gas Viscosity
3. 1. Crude Oil Properties:
A.
B.
C.
D.
E.
F.
G.
H.
Density (gamma)
Solution gas (Rs)
Bubble-point pressure (Pb)
Formation volume factor (Bo)
Isothermal compressibility coefficient (Co)
Total formation volume factor (Bt)
Viscosity (mu)
Surface Tension (sigma)
2. Water Properties
4.
5. Properties of Crude Oil Systems
Petroleum (an equivalent term is crude oil) is a complex
mixture consisting predominantly of hydrocarbons and
containing sulfur, nitrogen, oxygen, and helium as
minor constituents.
The physical and chemical properties of crude oils vary
considerably and are dependent on the concentration
of the various types of hydrocarbons and minor
constituents present.
An accurate description of physical properties of crude
oils is of a considerable importance in the fields of both
applied and theoretical science and especially in the
solution of petroleum reservoir engineering problems.
Fall 13 H. AlamiNia
Reservoir Engineering 1 Course: Oil and Water Properties
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6. Physical Properties of Petroleum
Physical properties of primary interest in petroleum engineering
studies include:
Fluid gravity
Specific gravity of the solution gas
Gas solubility
Bubble-point pressure
Oil formation volume factor
Isothermal compressibility coefficient of undersaturated crude oils
Oil density
Total formation volume factor
Crude oil viscosity
Surface tension
Data on most of these fluid properties are usually determined by
laboratory experiments performed on samples of actual reservoir
fluids. In the absence of experimentally measured properties of
crude oils, it is necessary for the petroleum engineer to determine
the properties from empirically derived correlations.
Fall 13 H. AlamiNia
Reservoir Engineering 1 Course: Oil and Water Properties
6
7. Crude Oil Gravity
The crude oil density is defined as the mass of a unit volume
of the crude at a specified pressure and temperature. It is
usually expressed in pounds per cubic foot. The specific
gravity of a crude oil is defined as the ratio of the density of
the oil to that of water. Both densities are measured at 60°F
and atmospheric pressure:
Although the density and specific gravity are used
extensively in the petroleum industry, the API gravity is the
preferred gravity scale. This gravity scale is precisely related
to the specific gravity by the following expression:
The API gravities of crude oils usually range from 47° API for
the lighter crude oils to 10° API for the heavier asphaltic
crude oils.
Fall 13 H. AlamiNia
Reservoir Engineering 1 Course: Oil and Water Properties
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8. Specific Gravity of the Solution Gas
The specific gravity of the solution gas γg is
described by the weighted average of the specific
gravities of the separated gas from each separator.
This weighted-average approach is based on the
separator gas-oil ratio, or:
Where n = number of separators, Rsep = separator
gas-oil ratio, scf/STB, γsep = separator gas gravity,
Rst = gas-oil ratio from the stock tank, scf/ STB, γst
= gas gravity from the stock tank
Fall 13 H. AlamiNia
Reservoir Engineering 1 Course: Oil and Water Properties
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9. Gas Solubility
The gas solubility Rs is defined as the number of standard cubic
feet of gas that will dissolve in one stock-tank barrel of crude oil at
certain pressure and temperature.
The solubility of a natural gas in a crude oil is a strong function of
the pressure, temperature, API gravity, and gas gravity.
For a particular gas and crude oil to exist at a constant
temperature, the solubility increases with pressure until the
saturation pressure is reached.
At the saturation pressure (bubble-point pressure) all the
available gases are dissolved in the oil and the gas solubility
reaches its maximum value.
Rather than measuring the amount of gas that will dissolve in a
given stock-tank crude oil as the pressure is increased, it is
customary to determine the amount of gas that will come out of a
sample of reservoir crude oil as pressure decreases.
Fall 13 H. AlamiNia
Reservoir Engineering 1 Course: Oil and Water Properties
9
10. Gas-Solubility Pressure Diagram
A typical gas solubility curve, as a
function of pressure for an
undersaturated crude oil, is shown
here.
As the pressure is reduced from the
initial reservoir pressure pi, to the
bubble-point pressure Pb, no gas
evolves from the oil and
consequently the gas solubility
remains constant at its maximum
value of Rsb. Below the bubblepoint pressure, the solution gas is
liberated and the value of Rs
decreases with pressure.
Fall 13 H. AlamiNia
Reservoir Engineering 1 Course: Oil and Water Properties
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11. Empirical Correlations for
Estimating the Rs
The following five empirical correlations for
estimating the gas solubility are given below:
Standing’s correlation
The Vasquez-Beggs correlation
Glaso’s correlation
Marhoun’s correlation
The Petrosky-Farshad correlation
Fall 13 H. AlamiNia
Reservoir Engineering 1 Course: Oil and Water Properties
11
12. Standing’s Correlation
Standing (1947) proposed a graphical correlation for
determining the gas solubility as a function of pressure, gas
specific gravity, API gravity, and system temperature. The
correlation was developed from a total of 105
experimentally determined data points on 22 hydrocarbon
mixtures from California crude oils and natural gases. The
proposed correlation has an average error of 4.8%. Standing
(1981) expressed his proposed graphical correlation in the
following more convenient mathematical form:
With (x = 0.0125 API − 0.00091(T − 460)), where T = temperature,
°R, p = system pressure, psia γg = solution gas specific gravity
It should be noted that Standing’s equation is valid for applications
at and below the bubble-point pressure of the crude oil.
Fall 13 H. AlamiNia
Reservoir Engineering 1 Course: Oil and Water Properties
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13. Bubble-Point Pressure
The bubble-point pressure Pb of a hydrocarbon
system is defined as the highest pressure at which a
bubble of gas is first liberated from the oil.
This important property can be measured
experimentally for a crude oil system by conducting
a constant-composition expansion test.
In the absence of the experimentally measured
bubble-point pressure, it is necessary for the
engineer to make an estimate of this crude oil
property from the readily available measured
producing parameters.
Fall 13 H. AlamiNia
Reservoir Engineering 1 Course: Oil and Water Properties
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14. Pb Correlations
Several graphical and mathematical correlations for
determining Pb have been proposed during the last four
decades. These correlations are essentially based on
the assumption that the bubble-point pressure is a
strong function of gas solubility Rs, gas gravity γg, oil
gravity API, and temperature T, or:
Pb = f (RS, γg, API, T)
Several ways of combining the above parameters in a
graphical form or a mathematical expression are
proposed by numerous authors, including:
Standing
Vasquez and Beggs
Glaso
Marhoun
Petrosky and Farshad
Fall 13 H. AlamiNia
Reservoir Engineering 1 Course: Oil and Water Properties
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15. Glaso’s Correlation
Glaso (1980) used 45 oil samples, mostly from the
North Sea hydrocarbon system, to develop an accurate
correlation for bubble-point pressure prediction. Glaso
proposed the following expression:
Where p*b is a correlating number and defined by the
following equation:
Where Rs = gas solubility, scf/STB, t = system temperature, °F, γg =
average specific gravity of the total surface gases, a, b, c =
coefficients of the above equation having the following values: a =
0.816, b = 0.172, c = −0.989
For volatile oils, Glaso recommends that the temperature exponent
b, be slightly changed, to the value of 0.130.
Fall 13 H. AlamiNia
Reservoir Engineering 1 Course: Oil and Water Properties
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16.
17. Oil Formation Volume Factor
The oil formation volume factor, Bo, is defined as
the ratio of the volume of oil (plus the gas in
solution) at the prevailing reservoir temperature
and pressure to the volume of oil at standard
conditions.
Bo is always greater than or equal to unity. The oil
formation volume factor can be expressed
mathematically as:
Fall 13 H. AlamiNia
Reservoir Engineering 1 Course: Oil and Water Properties
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18. Oil Formation Volume Factor vs. Pressure
A typical oil formation factor curve,
as a function of pressure for an
undersaturated crude oil (pi > Pb)
Fall 13 H. AlamiNia
Reservoir Engineering 1 Course: Oil and Water Properties
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19. Bo Behavior
As the pressure is reduced below the initial reservoir
pressure pi, the oil volume increases due to the oil
expansion.
This behavior results in an increase in the oil formation
volume factor and will continue until the bubble-point
pressure is reached.
At Pb, the oil reaches its maximum expansion and
consequently attains a maximum value of Bob for the oil
formation volume factor.
As the pressure is reduced below Pb, volume of the oil
and Bo are decreased as the solution gas is liberated.
When the pressure is reduced to atmospheric pressure and
the temperature to 60°F, the value of Bo is equal to one.
Fall 13 H. AlamiNia
Reservoir Engineering 1 Course: Oil and Water Properties
19
20. Bo Correlations
Most of the published empirical Bo correlations
utilize the following generalized relationship: Bo = f
(Rs, γ g, γ o, T)
Standing’s correlation
The Vasquez-Beggs correlation
Glaso’s correlation
Marhoun’s correlation
The Petrosky-Farshad correlation
Other correlations
It should be noted that all the correlations could be
used for any pressure equal to or below the bubblepoint pressure.
Fall 13 H. AlamiNia
Reservoir Engineering 1 Course: Oil and Water Properties
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21. Standing’s Correlation for Bo
Standing (1947) presented a graphical correlation for
estimating the oil formation volume factor with the gas
solubility, gas gravity, oil gravity, and reservoir
temperature as the correlating parameters. This
graphical correlation originated from examining a total
of 105 experimental data points on 22 different
California hydrocarbon systems. An average error of
1.2% was reported for the correlation. Standing (1981)
showed that the oil formation volume factor can be
expressed more conveniently in a mathematical form
by the following equation:
Where T = temperature, °R, γo = specific gravity of the stocktank oil, γg = specific gravity of the solution gas
Fall 13 H. AlamiNia
Reservoir Engineering 1 Course: Oil and Water Properties
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22. Bo Calculation from
Material Balance Equation
Following the definition of Bo as expressed
mathematically,
It can be shown that:
Where ρo = density of the oil at the specified pressure
and temperature, lb/ft3. ,
The error in calculating Bo by using the Equation will
depend only on the accuracy of the input variables (Rs,
γg, and γo) and the method of calculating ρo.
Fall 13 H. AlamiNia
Reservoir Engineering 1 Course: Oil and Water Properties
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23. Isothermal Compressibility Coefficient
of Crude Oil
Isothermal compressibility coefficients are required
in solving many reservoir engineering problems,
including transient fluid flow problems, and they
are also required in the determination of the
physical properties of the undersaturated crude oil.
By definition, the isothermal compressibility of a
substance is defined mathematically by the
following expression:
Fall 13 H. AlamiNia
Reservoir Engineering 1 Course: Oil and Water Properties
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24. Isothermal Compressibility Coefficient
of the Oil
For a crude oil system, the isothermal
compressibility coefficient of the oil phase co is
defined for pressures above the bubble-point by
one of the following equivalent expressions:
Co = − (1/V) (∂V/∂p) T
Co = − (1/Bo) (∂Bo/∂p) T
Co = (1/ρo) (∂ρo/∂p) T
At pressures below the bubble-point pressure, the
oil compressibility is defined as:
Fall 13 H. AlamiNia
Reservoir Engineering 1 Course: Oil and Water Properties
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25. Co Correlations
There are several correlations that are developed
to estimate the oil compressibility at pressures
above the bubble-point pressure, i.e.,
undersaturated crude oil system.
The Vasquez-Beggs correlation
The Petrosky-Farshad correlation
McCain’s correlation
Fall 13 H. AlamiNia
Reservoir Engineering 1 Course: Oil and Water Properties
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26. Oil Formation Volume Factor for
Undersaturated Oils
With increasing pressures above the bubble-point
pressure, the oil formation volume factor decreases
due to the compression of the oil.
To account for the effects of oil compression on Bo, the
oil formation volume factor at the bubble-point pressure
is first calculated by using any of the methods previously
described.
The calculated Bo is then adjusted to account for the
effect if increasing the pressure above the bubble-point
pressure.
Fall 13 H. AlamiNia
Reservoir Engineering 1 Course: Oil and Water Properties
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27. Bo Adjustment for
Undersaturated Oils
This adjustment step is accomplished by using the
isothermal compressibility coefficient as described
below.
The above relationship can be rearranged and integrated
to produce
Evaluating co at the arithmetic average pressure
and concluding the integration procedure to give:
Fall 13 H. AlamiNia
Reservoir Engineering 1 Course: Oil and Water Properties
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28. Crude Oil Density
The crude oil density is defined as the mass of a unit
volume of the crude at a specified pressure and
temperature. It is usually expressed in pounds per cubic
foot.
Several empirical correlations for calculating the
density of liquids of unknown compositional analysis
have been proposed.
The correlations employ limited PVT data such as gas gravity,
oil gravity, and gas solubility as correlating parameters to
estimate liquid density at the prevailing reservoir pressure
and temperature.
The Equation may be used to calculate the density of the oil
at pressure below or equal to the bubble-point pressure.
Fall 13 H. AlamiNia
Reservoir Engineering 1 Course: Oil and Water Properties
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29. Correlation for Estimating the Bo
Standing (1981) proposed an empirical correlation
for estimating the oil formation volume factor as a
function of the gas solubility Rs, the specific gravity
of stock-tank oil γo, the specific gravity of solution
gas γg, and the system temperature T.
By coupling the mathematical definition of the oil
formation volume factor with Standing’s
correlation, the density of a crude oil at a specified
pressure and temperature can be calculated from
the following expression:
Fall 13 H. AlamiNia
Reservoir Engineering 1 Course: Oil and Water Properties
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30.
31.
32. Total Formation Volume Factor
To describe the pressure-volume relationship of
hydrocarbon systems below their bubble-point
pressure, it is convenient to express this
relationship in terms of the total formation volume
factor as a function of pressure.
This property defines the total volume of a system
regardless of the number of phases present.
The total formation volume factor, denoted Bt, 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 stocktank oil.
Fall 13 H. AlamiNia
Reservoir Engineering 1 Course: Oil and Water Properties
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33. Two-Phase Formation Volume Factor
Because naturally occurring hydrocarbon systems
usually exist in either one or two phases, the term
“two-phase formation volume factor” has become
synonymous with the total formation volume.
Mathematically, Bt is defined by the following
relationship:
Notice that above the bubble point pressure; no
free gas exists and the expression is reduced to the
equation that describes the oil formation volume
factor, that is:
Fall 13 H. AlamiNia
Reservoir Engineering 1 Course: Oil and Water Properties
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34. Bt and Bo vs. Pressure
A typical plot of Bt as a function of
pressure for an undersaturated
crude oil. It should also be noted
that at pressures below the bubblepoint pressure, the difference in the
values of the two oil properties
represents the volume of the
evolved solution gas as measured at
system conditions per stock-tank
barrel of oil.
Fall 13 H. AlamiNia
Reservoir Engineering 1 Course: Oil and Water Properties
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35. 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.
Obviously, 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 Engineering 1 Course: Oil and Water Properties
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36. Bt Calculation
The volume of the free gas at the cell conditions is then
(Vg) p, T = (Rsb−Rs) Bg, The volume of the remaining oil
at the cell condition is (V) p, T = Bo and from the
definition of the two-phase formation volume factor
Bt = Bo + (Rsb – Rs) Bg
There are several correlations that can be used to
estimate the two phase formation volume factor when
the experimental data are not available; three of these
methods are:
Standing’s correlations
Glaso’s method
Marhoun’s correlation
Fall 13 H. AlamiNia
Reservoir Engineering 1 Course: Oil and Water Properties
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37.
38. 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 viscosity, in general, is defined as the internal
resistance of the fluid to flow.
The oil viscosity is a strong function of the
temperature, pressure, oil gravity, gas gravity, and
gas solubility.
Whenever possible, oil viscosity should be determined
by laboratory measurements at reservoir temperature
and pressure.
The viscosity is usually reported in standard PVT analyses.
Fall 13 H. AlamiNia
Reservoir Engineering 1 Course: Oil and Water Properties
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39. Crude Oil Viscosity Calculation
If such laboratory data are not available, engineers may
refer to published correlations, which usually vary in
complexity and accuracy depending upon the available
data on the crude oil. According to the pressure, the
viscosity of crude oils can be classified into three
categories:
Dead-Oil Viscosity: The dead-oil viscosity is defined as the
viscosity of crude oil at atmospheric pressure (no gas in
solution) and system temperature.
Saturated-Oil Viscosity: The saturated (bubble-point)-oil
viscosity is defined as the viscosity of the crude oil at the
bubble-point pressure and reservoir temperature.
Undersaturated-Oil Viscosity: The undersaturated-oil viscosity
is defined as the viscosity of the crude oil at a pressure above
the bubble-point and reservoir temperature.
Fall 13 H. AlamiNia
Reservoir Engineering 1 Course: Oil and Water Properties
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40. Estimation of the Oil Viscosity
Estimation of the oil viscosity at pressures equal to
or below the bubble point pressure is a two-step
procedure:
Step 1. Calculate the viscosity of the oil without
dissolved gas (dead oil), μob, at the reservoir
temperature.
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 bubble-point
pressure 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 Engineering 1 Course: Oil and Water Properties
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41. 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
Where μod = viscosity of the dead oil as measured at 14.7 psia
and reservoir temperature, cp and T = temperature, °R
The Beggs-Robinson correlation
Glaso’s correlation
Fall 13 H. AlamiNia
Reservoir Engineering 1 Course: Oil and Water Properties
41
42. 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 Engineering 1 Course: Oil and Water Properties
42
43. Methods 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
bubble-point pressure and adjusting the bubblepoint viscosity to higher pressures.
Vasquez and Beggs proposed a simple mathematical
expression for estimating the viscosity of the oil above
the bubble-point pressure.
Fall 13 H. AlamiNia
Reservoir Engineering 1 Course: Oil and Water Properties
43
44.
45. 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 Engineering 1 Course: Oil and Water Properties
45
46. 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 of the proposed relationship
are molecular weight M of the pure component, the
densities of both phases, and a newly introduced
temperature independent parameter Pch (parachor).
The relationship is expressed mathematically in the
following form:
Fall 13 H. AlamiNia
Reservoir Engineering 1 Course: Oil and Water Properties
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47. Parachor Parameter
The parachor is a dimensionless constant characteristic of a
pure compound and is calculated by imposing
experimentally measured surface tension and density data
on the Equation and solving for Pch.
The Parachor values for a selected number of pure
compounds are given in the Table as reported by Weinaug
and Katz (1943).
Fanchi’s linear equation ((Pch) i = 69.9 + 2.3 Mi) is only valid
for components heavier than methane. (Mi = molecular
weight of component i)
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Reservoir Engineering 1 Course: Oil and Water Properties
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48. 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. The modified
expression has the following form:
Where (Mo and Mg = apparent molecular weight of the
oil and gas phases, xi and yi are mole fraction of
component i in the oil and gas phases)
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49.
50. Water Formation Volume Factor
The water formation volume factor can be
calculated by the following mathematical
expression:
Where the coefficients A1 − A3 are given by the
following expression:
Fall 13 H. AlamiNia
Reservoir Engineering 1 Course: Oil and Water Properties
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51. Water Viscosity
Meehan (1980) proposed a water viscosity correlation
that accounts for both the effects of pressure and
salinity:
With μwD = A + B/T
A = 4.518 × 10−2 + 9.313 × 10−7Y − 3.93 × 10−12Y2
B = 70.634 + 9.576 × 10−10Y2
Where μw = brine viscosity at p and T, cP, μwD = brine
viscosity at p = 14.7, T, cP, T = temperature of interest, T °F, Y =
water salinity, ppm
Brill and Beggs (1978) presented a simpler equation,
which considers only temperature effects:
Where T is in °F and μw is in cP
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52. Gas Solubility in Water
The following correlation can be used to determine
the gas solubility in water:
The temperature T in above equations is expressed in °F
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Reservoir Engineering 1 Course: Oil and Water Properties
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53. Water Isothermal Compressibility
Brill and Beggs (1978) proposed the following
equation for estimating water isothermal
compressibility, ignoring the corrections for
dissolved gas and solids:
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54. 1. Ahmed, T. (2010). Reservoir engineering
handbook (Gulf Professional Publishing).
Chapter 2
55. 1. Laboratory Analysis
2. Laboratory Experiments
3. Rock Properties:
A.
B.
C.
D.
E.
Porosity
Saturation
Wettability
Capillary Pressure
Transition Zone