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 reservoir engineering course focused on fundamental rock properties. It discusses key topics like porosity, saturation, wettability, capillary pressure, and how they are determined through laboratory core analysis. Porosity refers to the pore space available to hold fluids and is classified as absolute or effective porosity. Saturation represents the fraction of pore space occupied by a fluid. Capillary pressure describes the pressure differential between immiscible fluids based on interface curvature. Laboratory tests on core samples are used to characterize these important rock properties.
Water alternating gas (WAG) - A Enhanced Oil Recovery techniqueIbrahim Muhammad
This document discusses water alternating gas (WAG) enhanced oil recovery. WAG involves alternating injections of gas and water to improve displacement and sweep efficiency. There are different classifications of WAG including miscible, immiscible, and hybrid WAG. The success of WAG depends on reservoir characteristics, fluid properties, well arrangement, and WAG parameters like slug size and ratio. Types of WAG include miscible, immiscible, hybrid, simultaneous, and selective simultaneous WAG. The document concludes that each reservoir is unique and laboratory experiments can help determine the most suitable WAG technique.
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 provides an overview of fundamental reservoir fluid properties and concepts. It discusses sampling and analyzing reservoir fluids, classifying hydrocarbons and their phase behaviors. Key fluid properties like gas, liquid, and formation water characteristics are examined. Common hydrocarbon types and compositions in crude oil and natural gas are also outlined. Fundamental reservoir engineering concepts involving hydrocarbon reserves calculations and fluid flow are reviewed.
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.
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 enhanced oil recovery (EOR) methods using gas injection. It discusses the main gas injection methods including miscible and immiscible processes. Key injection gases are carbon dioxide (CO2), nitrogen (N2), and natural gas. CO2 flooding has been widely used in the US and offers potential for combining EOR with CO2 storage. Economics of CO2-EOR and carbon capture and storage (CCS) are also reviewed. While gas injection is common, the number of N2 flood projects has declined with most current EOR relying on natural gas or CO2 if it is available. Offshore, EOR potential exists but is currently limited to gas and water-alternating-
This document discusses wellbore performance and flow modeling. It covers:
1) Single phase liquid, gas, and two phase flow models based on mechanical energy balance equations. Pressure drops are calculated considering elevation change, kinetic energy, and friction.
2) Methods for calculating friction factors including Fanning, Darcy, and Moody charts. Correlations for gas properties like viscosity and deviation factor are also presented.
3) Examples of calculating pressure drops in single phase liquid and gas flows. Numerical methods for solving gas flow equations are described.
4) Multiphase flow is more complex due to different flow regimes affecting pressure gradients. Models include homogeneous and separated flow approaches.
This document provides an overview of a reservoir engineering course focused on fundamental rock properties. It discusses key topics like porosity, saturation, wettability, capillary pressure, and how they are determined through laboratory core analysis. Porosity refers to the pore space available to hold fluids and is classified as absolute or effective porosity. Saturation represents the fraction of pore space occupied by a fluid. Capillary pressure describes the pressure differential between immiscible fluids based on interface curvature. Laboratory tests on core samples are used to characterize these important rock properties.
Water alternating gas (WAG) - A Enhanced Oil Recovery techniqueIbrahim Muhammad
This document discusses water alternating gas (WAG) enhanced oil recovery. WAG involves alternating injections of gas and water to improve displacement and sweep efficiency. There are different classifications of WAG including miscible, immiscible, and hybrid WAG. The success of WAG depends on reservoir characteristics, fluid properties, well arrangement, and WAG parameters like slug size and ratio. Types of WAG include miscible, immiscible, hybrid, simultaneous, and selective simultaneous WAG. The document concludes that each reservoir is unique and laboratory experiments can help determine the most suitable WAG technique.
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 provides an overview of fundamental reservoir fluid properties and concepts. It discusses sampling and analyzing reservoir fluids, classifying hydrocarbons and their phase behaviors. Key fluid properties like gas, liquid, and formation water characteristics are examined. Common hydrocarbon types and compositions in crude oil and natural gas are also outlined. Fundamental reservoir engineering concepts involving hydrocarbon reserves calculations and fluid flow are reviewed.
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.
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 enhanced oil recovery (EOR) methods using gas injection. It discusses the main gas injection methods including miscible and immiscible processes. Key injection gases are carbon dioxide (CO2), nitrogen (N2), and natural gas. CO2 flooding has been widely used in the US and offers potential for combining EOR with CO2 storage. Economics of CO2-EOR and carbon capture and storage (CCS) are also reviewed. While gas injection is common, the number of N2 flood projects has declined with most current EOR relying on natural gas or CO2 if it is available. Offshore, EOR potential exists but is currently limited to gas and water-alternating-
This document discusses wellbore performance and flow modeling. It covers:
1) Single phase liquid, gas, and two phase flow models based on mechanical energy balance equations. Pressure drops are calculated considering elevation change, kinetic energy, and friction.
2) Methods for calculating friction factors including Fanning, Darcy, and Moody charts. Correlations for gas properties like viscosity and deviation factor are also presented.
3) Examples of calculating pressure drops in single phase liquid and gas flows. Numerical methods for solving gas flow equations are described.
4) Multiphase flow is more complex due to different flow regimes affecting pressure gradients. Models include homogeneous and separated flow approaches.
- 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.
1) Three types of fluid flow can occur in a reservoir: steady-state, semi-steady state, and unsteady-state flow.
2) Steady-state flow very rarely occurs and requires a strong pressure maintenance mechanism like an aquifer to replenish pressure changes from production.
3) Semi-steady state is the dominant type, where pressure declines uniformly throughout the reservoir as the boundaries have been encountered.
4) Unsteady-state flow occurs early in a well's life before boundaries are felt, and the reservoir acts infinitely. The correct flow equations depend on identifying the type of flow.
The document provides an overview of various chemical enhanced oil recovery (EOR) methods including polymer flooding, colloidal dispersion gels, alkaline flooding, alkaline-polymer flooding, surfactant-polymer flooding, and alkaline-surfactant-polymer flooding. It discusses the basics of each method, how they work to increase oil recovery, examples of their application, and screening criteria for determining applicability to different reservoirs. Key topics covered include the use of polymers to increase water viscosity and improve sweep efficiency, using alkalis and surfactants to lower oil-water interfacial tension, and combining methods such as polymer gels followed by chemical EOR to control conformance.
- 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.
The document discusses various natural reservoir drive mechanisms that provide energy for hydrocarbon production including:
1) Solution gas drive where dissolved gas expands due to pressure drop, providing 5-25% oil recovery.
2) Gas cap drive where free gas expansion drives production, providing 20-40% oil recovery.
3) Water drive where aquifer water influx provides pressure to displace oil, providing 35-75% oil recovery.
4) Gravity drainage where gas migrates updip and oil downdip in high dip reservoirs.
Le 03 Natural Gas (NG) Transportation and DistributionNsulangi Paul
This module describes means of transportation and distribution of natural gas from production area to the end user or consumers. The module analyzes various methods such as pipeline, liquefied natural gas (LNG), compressed natural gas (CNG), gas to liquid fuel (GtL), gas to wire (GtW) as well as gas to hydrate (GtH).
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
Reservoir development plans require dynamic strategies to optimize production. Recovery methods can be initiated at any stage to improve efficiency. It is common for development plans to change over time due to new understanding, performance, constraints, economics or technologies. Screening studies for improved or enhanced oil recovery methods should consider technical feasibility as well as availability of resources and include decision analysis to define robust project options early. Preliminary performance predictions using simple models can help evaluate recovery process potential in a reservoir.
Reservoir rocks experience compaction when fluid is produced, causing a change in pore volume and effective stress. There are three types of compressibility - rock matrix (grain) compressibility measures change in grain volume, rock bulk compressibility measures change in total formation volume, and pore volume compressibility measures change in pore space. Accurately measuring and modeling compressibility is important for predicting changes in porosity and formation properties during production.
Elements of Reservoir Rocks & Fluid PropertiesM.T.H Group
This document outlines a course on petroleum reservoir rock and fluid properties. It lists the course instructor, grading breakdown which is 50% final exams, and course aims which are to introduce critical reservoir properties of oil, gas, and water, and their PVT relationships. Upon completing the course, students should understand definitions of porosity and saturation, reservoir fluid behavior, and be able to calculate single and multiphase flow rates using Darcy's law. Recommended textbooks are listed.
This document provides an overview of a reservoir fluid properties course for petroleum engineering students. The 2-credit, weekly course aims to describe how oil and gas behave under different conditions. Lectures will be divided into two 50-slide sections with a short break. Students will be assessed based on class activities, a midterm exam, and a final exam. The 16-lecture course will cover topics like phase behavior of hydrocarbons, PVT experiments, equations of state, fluid properties, and relevant software. The course is designed to help students understand how reservoir fluids are modeled and their importance in petroleum engineering.
Petroleum reservoirs are classified as either oil or gas reservoirs based on reservoir temperature relative to critical temperature. Within these broad classifications, reservoirs can be further classified. Oil reservoirs have temperature below critical temperature, while gas reservoirs have temperature above critical. Specific gas reservoir classifications include retrograde, near-critical, wet and dry based on phase behavior and GOR. Retrograde reservoirs have unique condensation behavior on pressure depletion. Classification is important for understanding reservoir fluid properties, production behavior, and development approach.
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
This document provides an overview of petroleum reservoir performance terms and concepts. It begins with definitions of key reservoir fluid terms like fluid, density, solution gas, critical saturation, bubble point pressure, gas cap, associated and non-associated gas, viscosity, condensate, and formation volume factor. It then describes hydrocarbon classifications and recovery methods. The document outlines natural driving forces in reservoirs including solution gas, water drive, and gravity drainage. It also discusses enhanced oil recovery methods such as water flooding, thermal recovery, and microbial flooding. Suggestions are made to improve future editions covering the petroleum industry overview.
This document discusses primary recovery drive mechanisms for oil and gas fields. It describes the main types of primary drives including solution gas drive, gas cap drive, water drive, and gravity drainage. It provides details on how each drive works and its production trends. The document also discusses combination or mixed drive reservoirs that involve more than one drive mechanism. It emphasizes the importance of identifying the dominant drive when designing production wells in fields with mixed drives. Worked examples are provided at the end to illustrate calculations related to reservoir recovery factors and production timelines.
Production decline analysis is a traditional means of identifying well production problems and predicting well performance and life based on real production data. It uses empirical decline models that have little fundamental justifications. These models include
•
Exponential decline (constant fractional decline)
•
Harmonic decline, and
•
Hyperbolic decline.
This document discusses concepts in applied reservoir engineering. It defines key reservoir terms like reservoir rock, cap rock, and reservoir fluids. It also covers rock and fluid properties important for reservoir characterization like porosity, permeability, and PVT properties. Methods for calculating original hydrocarbon in place are presented, including volumetric and material balance approaches. Determining reservoir drive mechanisms and predicting future performance through primary and secondary recovery methods are also summarized.
The document discusses various artificial lift technologies used in oil production, including reciprocating rod lift systems, progressing cavity pumps, gas lift systems, plunger lift systems, hydraulic lift systems, and electric submersible pumps. It provides details on the advantages and limitations of each system, as well as parameters for determining appropriate applications, such as operating depth, volume, temperature, and wellbore characteristics. Selection of the optimal artificial lift method involves a systematic evaluation process to maximize return on investment.
This document discusses key concepts related to waterflooding for oil recovery, including:
1. Waterflooding involves injecting water into an oil reservoir to displace oil towards production wells. It is a commonly used secondary recovery method to substantially increase oil recovery.
2. Basic concepts discussed include rock wettability, capillary pressure, relative permeability, and their influence on displacement efficiency. Water-wet reservoirs typically yield higher recovery than oil-wet reservoirs.
3. Proper characterization of the reservoir, including initial fluid saturations, capillary pressure curves, and relative permeability are important for reservoir modeling and simulation of waterflood recovery processes.
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 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.
- 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.
1) Three types of fluid flow can occur in a reservoir: steady-state, semi-steady state, and unsteady-state flow.
2) Steady-state flow very rarely occurs and requires a strong pressure maintenance mechanism like an aquifer to replenish pressure changes from production.
3) Semi-steady state is the dominant type, where pressure declines uniformly throughout the reservoir as the boundaries have been encountered.
4) Unsteady-state flow occurs early in a well's life before boundaries are felt, and the reservoir acts infinitely. The correct flow equations depend on identifying the type of flow.
The document provides an overview of various chemical enhanced oil recovery (EOR) methods including polymer flooding, colloidal dispersion gels, alkaline flooding, alkaline-polymer flooding, surfactant-polymer flooding, and alkaline-surfactant-polymer flooding. It discusses the basics of each method, how they work to increase oil recovery, examples of their application, and screening criteria for determining applicability to different reservoirs. Key topics covered include the use of polymers to increase water viscosity and improve sweep efficiency, using alkalis and surfactants to lower oil-water interfacial tension, and combining methods such as polymer gels followed by chemical EOR to control conformance.
- 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.
The document discusses various natural reservoir drive mechanisms that provide energy for hydrocarbon production including:
1) Solution gas drive where dissolved gas expands due to pressure drop, providing 5-25% oil recovery.
2) Gas cap drive where free gas expansion drives production, providing 20-40% oil recovery.
3) Water drive where aquifer water influx provides pressure to displace oil, providing 35-75% oil recovery.
4) Gravity drainage where gas migrates updip and oil downdip in high dip reservoirs.
Le 03 Natural Gas (NG) Transportation and DistributionNsulangi Paul
This module describes means of transportation and distribution of natural gas from production area to the end user or consumers. The module analyzes various methods such as pipeline, liquefied natural gas (LNG), compressed natural gas (CNG), gas to liquid fuel (GtL), gas to wire (GtW) as well as gas to hydrate (GtH).
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
Reservoir development plans require dynamic strategies to optimize production. Recovery methods can be initiated at any stage to improve efficiency. It is common for development plans to change over time due to new understanding, performance, constraints, economics or technologies. Screening studies for improved or enhanced oil recovery methods should consider technical feasibility as well as availability of resources and include decision analysis to define robust project options early. Preliminary performance predictions using simple models can help evaluate recovery process potential in a reservoir.
Reservoir rocks experience compaction when fluid is produced, causing a change in pore volume and effective stress. There are three types of compressibility - rock matrix (grain) compressibility measures change in grain volume, rock bulk compressibility measures change in total formation volume, and pore volume compressibility measures change in pore space. Accurately measuring and modeling compressibility is important for predicting changes in porosity and formation properties during production.
Elements of Reservoir Rocks & Fluid PropertiesM.T.H Group
This document outlines a course on petroleum reservoir rock and fluid properties. It lists the course instructor, grading breakdown which is 50% final exams, and course aims which are to introduce critical reservoir properties of oil, gas, and water, and their PVT relationships. Upon completing the course, students should understand definitions of porosity and saturation, reservoir fluid behavior, and be able to calculate single and multiphase flow rates using Darcy's law. Recommended textbooks are listed.
This document provides an overview of a reservoir fluid properties course for petroleum engineering students. The 2-credit, weekly course aims to describe how oil and gas behave under different conditions. Lectures will be divided into two 50-slide sections with a short break. Students will be assessed based on class activities, a midterm exam, and a final exam. The 16-lecture course will cover topics like phase behavior of hydrocarbons, PVT experiments, equations of state, fluid properties, and relevant software. The course is designed to help students understand how reservoir fluids are modeled and their importance in petroleum engineering.
Petroleum reservoirs are classified as either oil or gas reservoirs based on reservoir temperature relative to critical temperature. Within these broad classifications, reservoirs can be further classified. Oil reservoirs have temperature below critical temperature, while gas reservoirs have temperature above critical. Specific gas reservoir classifications include retrograde, near-critical, wet and dry based on phase behavior and GOR. Retrograde reservoirs have unique condensation behavior on pressure depletion. Classification is important for understanding reservoir fluid properties, production behavior, and development approach.
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
This document provides an overview of petroleum reservoir performance terms and concepts. It begins with definitions of key reservoir fluid terms like fluid, density, solution gas, critical saturation, bubble point pressure, gas cap, associated and non-associated gas, viscosity, condensate, and formation volume factor. It then describes hydrocarbon classifications and recovery methods. The document outlines natural driving forces in reservoirs including solution gas, water drive, and gravity drainage. It also discusses enhanced oil recovery methods such as water flooding, thermal recovery, and microbial flooding. Suggestions are made to improve future editions covering the petroleum industry overview.
This document discusses primary recovery drive mechanisms for oil and gas fields. It describes the main types of primary drives including solution gas drive, gas cap drive, water drive, and gravity drainage. It provides details on how each drive works and its production trends. The document also discusses combination or mixed drive reservoirs that involve more than one drive mechanism. It emphasizes the importance of identifying the dominant drive when designing production wells in fields with mixed drives. Worked examples are provided at the end to illustrate calculations related to reservoir recovery factors and production timelines.
Production decline analysis is a traditional means of identifying well production problems and predicting well performance and life based on real production data. It uses empirical decline models that have little fundamental justifications. These models include
•
Exponential decline (constant fractional decline)
•
Harmonic decline, and
•
Hyperbolic decline.
This document discusses concepts in applied reservoir engineering. It defines key reservoir terms like reservoir rock, cap rock, and reservoir fluids. It also covers rock and fluid properties important for reservoir characterization like porosity, permeability, and PVT properties. Methods for calculating original hydrocarbon in place are presented, including volumetric and material balance approaches. Determining reservoir drive mechanisms and predicting future performance through primary and secondary recovery methods are also summarized.
The document discusses various artificial lift technologies used in oil production, including reciprocating rod lift systems, progressing cavity pumps, gas lift systems, plunger lift systems, hydraulic lift systems, and electric submersible pumps. It provides details on the advantages and limitations of each system, as well as parameters for determining appropriate applications, such as operating depth, volume, temperature, and wellbore characteristics. Selection of the optimal artificial lift method involves a systematic evaluation process to maximize return on investment.
This document discusses key concepts related to waterflooding for oil recovery, including:
1. Waterflooding involves injecting water into an oil reservoir to displace oil towards production wells. It is a commonly used secondary recovery method to substantially increase oil recovery.
2. Basic concepts discussed include rock wettability, capillary pressure, relative permeability, and their influence on displacement efficiency. Water-wet reservoirs typically yield higher recovery than oil-wet reservoirs.
3. Proper characterization of the reservoir, including initial fluid saturations, capillary pressure curves, and relative permeability are important for reservoir modeling and simulation of waterflood recovery processes.
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 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 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.
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.
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 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 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.
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.
Fluid properties like density, viscosity, and specific gravity are important to characterize different fluids. Density is defined as mass per unit volume and determines whether a flow is compressible or incompressible. Viscosity measures a fluid's resistance to flow and internal friction. It is proportional to shear stress and inversely proportional to velocity gradient. Water has a viscosity of 1x10-3 N-s/m2 while air is less viscous at 1.8x10-5 N-s/m2. Specific gravity is the ratio of a fluid's density to that of water and is a dimensionless property.
The document summarizes key properties of fluids. It discusses specific gravity, viscosity, surface tension, capillarity, and compressibility. Specific gravity is the ratio of a fluid's density to water's density. Viscosity is a measure of a fluid's resistance to flow, while surface tension is the tendency of liquid molecules to stick together. Capillarity describes how liquids behave in narrow tubes based on adhesion and cohesion. Compressibility refers to how easily a fluid's volume can be reduced by an applied pressure. Liquids are generally incompressible compared to gases.
This document discusses hydrocarbon phase behavior and provides several key points:
1. Hydrocarbons can exist in liquid, gas, and solid phases depending on pressure and temperature conditions. Phase changes occur as these conditions vary.
2. Understanding phase behavior is important for predicting subsurface fluid conditions and planning surface facilities as pressure and temperature change during production.
3. During production, liquid may condense from gas or gas may evolve from liquid as pressure and temperature decrease at the surface and within reservoirs.
4. Phase diagrams are used to represent phase relationships under various pressure and temperature conditions for pure components and mixtures.
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 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 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 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
The document provides an overview of a course on reservoir fluid properties. It covers the following topics:
1. An introduction to petroleum engineering and the importance of understanding reservoir fluids.
2. The formation and extraction of petroleum, including drilling and production.
3. The constituents of reservoir fluids including hydrocarbon components like methane, paraffins, naphthenes and aromatics. It also discusses non-hydrocarbon components like water, nitrogen and carbon dioxide.
4. The phase behavior of pure components and mixtures, including phase envelopes and using pressure-temperature and pressure-volume diagrams to illustrate behavior.
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.
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 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 discusses several key properties of fluids: viscosity, surface tension, and capillary action. Viscosity is a fluid's resistance to flow and depends on internal friction. Surface tension is a contractive tendency that allows fluids to resist external forces. Capillary action describes a fluid's ability to flow in narrow spaces without external assistance and against gravity, such as liquid rising in a thin tube. The document provides examples of applications for each property, like lubrication using viscosity and water striders walking on water using surface tension. Formulas for calculating these properties are also presented.
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 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
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.
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 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 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.
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 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 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.
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.
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 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 advanced well testing concepts and objectives. It aims to upgrade engineers' knowledge to prepare them for professional well testing positions. Key topics covered include: linking measurement data to customer decisions; understanding well testing equipment; preparing for different well conditions; and qualifying engineers to discuss business plans with customers. The course outlines topics such as reservoir properties, well testing purposes and equipment, testing various well types, and meeting customer needs for each test.
This document provides an overview of advanced well testing concepts and objectives. It aims to upgrade engineers' knowledge to prepare them for professional well testing positions. Key topics covered include: linking measurement data to customer decisions; understanding well testing equipment; preparing for different well conditions; and qualifying engineers to discuss business plans with customers. The course outlines topics such as reservoir properties, well testing purposes and equipment, testing various well types, and meeting customer needs for each test.
This document provides an overview of advanced well testing concepts and objectives. It aims to upgrade engineers' knowledge to prepare them for professional well testing positions. Key topics covered include: linking measurement data to customer decisions; understanding well testing equipment; preparing for different well conditions; and qualifying engineers to discuss business plans with customers. The course outlines topics such as reservoir properties, well testing purposes and equipment, testing various well types, and meeting customer needs for each test.
Five Reservoir Fluids in petroleum engineeringossamafarghly
This document provides an overview of a petroleum fluids properties course including the course contents, grading system, and summaries of lectures on reservoir fluid classification and pressure-temperature phase diagrams. The course covers components and behavior of petroleum fluids, properties of dry gases, wet gases, black oils, and uses pressure-temperature diagrams to classify reservoirs as gas, gas condensate, undersaturated solution-gas, or volatile oil based on initial reservoir conditions and production paths. Typical fluid compositions and criteria for classification based on production data like GOR, API gravity, and compositions are also presented.
types of resserddugddhdvoir fluids..pptxZaidAqeel4
This document describes different types of reservoir fluids. It discusses the composition and properties of natural gas, which mainly contains low molecular weight alkanes, and crude oil, which contains higher molecular weight aromatic and naphthenic hydrocarbons. The document then covers single and multi-component phase behavior, including vapor-liquid equilibrium, phase diagrams, and the effects of temperature and pressure on phase changes. It also describes concepts like retrograde condensation. Finally, it classifies different reservoir fluid systems as dry gas, wet gas, gas condensate, volatile oil or black oil based on their composition and pressure-temperature conditions.
4 modeling and control of distillation column in a petroleum processnazir1988
This document describes the modeling and simulation of a condensate distillation column in a petroleum process. It presents a calculation procedure to model the column based on an energy balance structure using reflux rate and boilup rate as inputs to control distillate purity and bottom product impurity. A nonlinear dynamic model of the column is developed and simulated in MATLAB. The simulation shows the column can maintain product quality under normal operations but quality decreases with disturbances like changes in feed rate. A reduced-order linear model is then developed for use in model-reference adaptive control to improve disturbance rejection.
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.
Reimagining Your Library Space: How to Increase the Vibes in Your Library No ...Diana Rendina
Librarians are leading the way in creating future-ready citizens – now we need to update our spaces to match. In this session, attendees will get inspiration for transforming their library spaces. You’ll learn how to survey students and patrons, create a focus group, and use design thinking to brainstorm ideas for your space. We’ll discuss budget friendly ways to change your space as well as how to find funding. No matter where you’re at, you’ll find ideas for reimagining your space in this session.
Walmart Business+ and Spark Good for Nonprofits.pdfTechSoup
"Learn about all the ways Walmart supports nonprofit organizations.
You will hear from Liz Willett, the Head of Nonprofits, and hear about what Walmart is doing to help nonprofits, including Walmart Business and Spark Good. Walmart Business+ is a new offer for nonprofits that offers discounts and also streamlines nonprofits order and expense tracking, saving time and money.
The webinar may also give some examples on how nonprofits can best leverage Walmart Business+.
The event will cover the following::
Walmart Business + (https://business.walmart.com/plus) is a new shopping experience for nonprofits, schools, and local business customers that connects an exclusive online shopping experience to stores. Benefits include free delivery and shipping, a 'Spend Analytics” feature, special discounts, deals and tax-exempt shopping.
Special TechSoup offer for a free 180 days membership, and up to $150 in discounts on eligible orders.
Spark Good (walmart.com/sparkgood) is a charitable platform that enables nonprofits to receive donations directly from customers and associates.
Answers about how you can do more with Walmart!"
This presentation includes basic of PCOS their pathology and treatment and also Ayurveda correlation of PCOS and Ayurvedic line of treatment mentioned in classics.
Chapter wise All Notes of First year Basic Civil Engineering.pptxDenish Jangid
Chapter wise All Notes of First year Basic Civil Engineering
Syllabus
Chapter-1
Introduction to objective, scope and outcome the subject
Chapter 2
Introduction: Scope and Specialization of Civil Engineering, Role of civil Engineer in Society, Impact of infrastructural development on economy of country.
Chapter 3
Surveying: Object Principles & Types of Surveying; Site Plans, Plans & Maps; Scales & Unit of different Measurements.
Linear Measurements: Instruments used. Linear Measurement by Tape, Ranging out Survey Lines and overcoming Obstructions; Measurements on sloping ground; Tape corrections, conventional symbols. Angular Measurements: Instruments used; Introduction to Compass Surveying, Bearings and Longitude & Latitude of a Line, Introduction to total station.
Levelling: Instrument used Object of levelling, Methods of levelling in brief, and Contour maps.
Chapter 4
Buildings: Selection of site for Buildings, Layout of Building Plan, Types of buildings, Plinth area, carpet area, floor space index, Introduction to building byelaws, concept of sun light & ventilation. Components of Buildings & their functions, Basic concept of R.C.C., Introduction to types of foundation
Chapter 5
Transportation: Introduction to Transportation Engineering; Traffic and Road Safety: Types and Characteristics of Various Modes of Transportation; Various Road Traffic Signs, Causes of Accidents and Road Safety Measures.
Chapter 6
Environmental Engineering: Environmental Pollution, Environmental Acts and Regulations, Functional Concepts of Ecology, Basics of Species, Biodiversity, Ecosystem, Hydrological Cycle; Chemical Cycles: Carbon, Nitrogen & Phosphorus; Energy Flow in Ecosystems.
Water Pollution: Water Quality standards, Introduction to Treatment & Disposal of Waste Water. Reuse and Saving of Water, Rain Water Harvesting. Solid Waste Management: Classification of Solid Waste, Collection, Transportation and Disposal of Solid. Recycling of Solid Waste: Energy Recovery, Sanitary Landfill, On-Site Sanitation. Air & Noise Pollution: Primary and Secondary air pollutants, Harmful effects of Air Pollution, Control of Air Pollution. . Noise Pollution Harmful Effects of noise pollution, control of noise pollution, Global warming & Climate Change, Ozone depletion, Greenhouse effect
Text Books:
1. Palancharmy, Basic Civil Engineering, McGraw Hill publishers.
2. Satheesh Gopi, Basic Civil Engineering, Pearson Publishers.
3. Ketki Rangwala Dalal, Essentials of Civil Engineering, Charotar Publishing House.
4. BCP, Surveying volume 1
How to Setup Warehouse & Location in Odoo 17 InventoryCeline George
In this slide, we'll explore how to set up warehouses and locations in Odoo 17 Inventory. This will help us manage our stock effectively, track inventory levels, and streamline warehouse operations.
How to Manage Your Lost Opportunities in Odoo 17 CRMCeline George
Odoo 17 CRM allows us to track why we lose sales opportunities with "Lost Reasons." This helps analyze our sales process and identify areas for improvement. Here's how to configure lost reasons in Odoo 17 CRM
LAND USE LAND COVER AND NDVI OF MIRZAPUR DISTRICT, UPRAHUL
This Dissertation explores the particular circumstances of Mirzapur, a region located in the
core of India. Mirzapur, with its varied terrains and abundant biodiversity, offers an optimal
environment for investigating the changes in vegetation cover dynamics. Our study utilizes
advanced technologies such as GIS (Geographic Information Systems) and Remote sensing to
analyze the transformations that have taken place over the course of a decade.
The complex relationship between human activities and the environment has been the focus
of extensive research and worry. As the global community grapples with swift urbanization,
population expansion, and economic progress, the effects on natural ecosystems are becoming
more evident. A crucial element of this impact is the alteration of vegetation cover, which plays a
significant role in maintaining the ecological equilibrium of our planet.Land serves as the foundation for all human activities and provides the necessary materials for
these activities. As the most crucial natural resource, its utilization by humans results in different
'Land uses,' which are determined by both human activities and the physical characteristics of the
land.
The utilization of land is impacted by human needs and environmental factors. In countries
like India, rapid population growth and the emphasis on extensive resource exploitation can lead
to significant land degradation, adversely affecting the region's land cover.
Therefore, human intervention has significantly influenced land use patterns over many
centuries, evolving its structure over time and space. In the present era, these changes have
accelerated due to factors such as agriculture and urbanization. Information regarding land use and
cover is essential for various planning and management tasks related to the Earth's surface,
providing crucial environmental data for scientific, resource management, policy purposes, and
diverse human activities.
Accurate understanding of land use and cover is imperative for the development planning
of any area. Consequently, a wide range of professionals, including earth system scientists, land
and water managers, and urban planners, are interested in obtaining data on land use and cover
changes, conversion trends, and other related patterns. The spatial dimensions of land use and
cover support policymakers and scientists in making well-informed decisions, as alterations in
these patterns indicate shifts in economic and social conditions. Monitoring such changes with the
help of Advanced technologies like Remote Sensing and Geographic Information Systems is
crucial for coordinated efforts across different administrative levels. Advanced technologies like
Remote Sensing and Geographic Information Systems
9
Changes in vegetation cover refer to variations in the distribution, composition, and overall
structure of plant communities across different temporal and spatial scales. These changes can
occur natural.
Main Java[All of the Base Concepts}.docxadhitya5119
This is part 1 of my Java Learning Journey. This Contains Custom methods, classes, constructors, packages, multithreading , try- catch block, finally block and more.
3. 1. Reservoir Fluid Behaviors
2. Petroleum Reservoirs
A. Oil
B. Gas
3. Introduction to Physical Properties
A. heavy fractions
4.
5. Multiphase Behavior
Naturally occurring hydrocarbon systems found in
petroleum reservoirs are mixtures of organic
compounds that exhibit multiphase behavior over
wide ranges of pressures and temperatures.
These hydrocarbon accumulations may occur in the
gaseous state, the liquid state, the solid state, or in
various combinations of gas, liquid, and solid.
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
5
6. Petroleum Engineers Task
These differences in phase behavior, coupled with
the physical properties of reservoir rock that
determine the relative ease with which gas and
liquid are transmitted or retained, result in many
diverse types of hydrocarbon reservoirs with
complex behaviors.
Frequently, petroleum engineers have the task to
study the behavior and characteristics of a
petroleum reservoir and to determine the course of
future development and production that would
maximize the profit.
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
6
7. Classification of Reservoirs and
Reservoir Fluids
Petroleum reservoirs are broadly classified as oil or gas
reservoirs. These broad classifications are further
subdivided depending on:
The composition of the reservoir hydrocarbon mixture
Initial reservoir pressure and temperature
Pressure and temperature of the surface production
The conditions under which these phases exist are a
matter of considerable practical importance.
The experimental or the mathematical determinations
of these conditions are conveniently expressed in
different types of diagrams commonly called phase
diagrams. One such diagram is called the pressuretemperature diagram.
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
7
8. Pressure-Temperature Diagram
Although a different hydrocarbon system would
have a different phase diagram, the general
configuration is similar.
These multicomponent pressure-temperature
diagrams are essentially used to:
Classify reservoirs
Classify the naturally occurring hydrocarbon systems
Describe the phase behavior of the reservoir fluid
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
8
9. Typical P-T Diagram
for a Multicomponent System
Binary Component
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
9
10. key points on P-T diagrams
To fully understand the
significance of the pressuretemperature diagrams,
it is necessary to identify and
define the following key
points on these diagrams:
Cricondentherm (Tct)
The Cricondentherm is defined
as the maximum temperature
above which liquid cannot be
formed regardless of pressure.
The corresponding pressure is
termed the Cricondentherm
pressure pct.
Cricondenbar (pcb)
which no gas can be formed
regardless of temperature. The
corresponding temperature is
called the Cricondenbar
temperature Tcb.
Critical point
The critical point for a
multicomponent mixture is
referred to as the state of
pressure and temperature at
which all intensive properties
of the gas and liquid phases
are equal. At the critical point,
the corresponding pressure
and temperature are called the
critical pressure pc and critical
temperature Tc of the mixture.
The Cricondenbar is the
maximum pressure above
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
10
11. key points on P-T diagrams (Cont.)
Phase envelope
(two-phase region)
The region enclosed by
the bubble- point curve
and the dew-point curve,
wherein gas and liquid
coexist in equilibrium, is
identified as the phase
envelope of the
hydrocarbon system.
Quality lines
The dashed lines within
the phase diagram are
called quality lines. They
describe the pressure and
temperature conditions
Spring14 H. AlamiNia
for equal volumes of
liquids. Note that the
quality lines converge at
the critical point.
Bubble-point curve
The bubble-point curve is
defined as the line
separating the liquidphase region from the
two-phase region.
Dew-point curve
The dew-point curve is
defined as the line
separating the vaporphase region from the
two-phase region.
Reservoir Fluid Properties Course (3rd Ed.)
11
12.
13. Oil vs. Gas Reservoirs
In general, reservoirs are conveniently classified on
the basis of the location of the point representing
the initial reservoir pressure pi and temperature T
with respect to the pressure-temperature diagram
of the reservoir fluid. Accordingly, reservoirs can be
classified into basically two types. These are:
Oil reservoirs
If the Tr is less than the Tc of the reservoir fluid
Gas reservoirs
If the Tr is greater than the Tc of the hydrocarbon fluid
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
13
14. Oil Reservoirs
Depending upon initial reservoir pressure pi, oil
reservoirs can be subclassified into the following
categories:
Undersaturated oil reservoir.
If the initial reservoir pressure pi, is greater than the bubblepoint pressure Pb of the reservoir fluid
Saturated oil reservoir.
When pi is equal to the bubble-point pressure of the reservoir
fluid
Gas-cap reservoir or two-phase reservoir.
If pi is below the bubble point pressure of the reservoir fluid
The appropriate quality line gives the ratio of the gas-cap
volume to reservoir oil volume.
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
14
15. Crude Oils
Crude oils cover a wide range in physical properties and
chemical compositions, and it is often important to be
able to group them into broad categories of related oils.
In general, crude oils are commonly classified into the
following types:
Ordinary black oil
Low-shrinkage crude oil
High-shrinkage (volatile) crude oil
Near-critical crude oil
The above classifications are essentially based upon the
properties exhibited by the crude oil, including physical
properties, composition, gas-oil ratio, appearance, and
pressure-temperature phase diagrams.
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
15
16. Ordinary black oil
quality lines, which are approximately equally spaced,
characterize this black oil phase diagram.
Following the pressure reduction path as indicated by
the vertical line EF on next figure, the liquid shrinkage
curve, is prepared by plotting the liquid volume percent
as a function of pressure.
The liquid shrinkage curve approximates a straight line except
at very low pressures.
When produced, ordinary black oils usually yield gas-oil
ratios between 200 and 700 scf/STB and
oil gravities of 15° to 40° API
The stock tank oil is usually brown to dark green
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
16
17. Ordinary Black Oil
A typical p-T diagram for an ordinary black
Liquid-shrinkage curve for black oil
oil
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
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18. Low-shrinkage oil
The diagram is characterized by quality lines that
are closely spaced near the dew-point curve.
The other associated properties of this type of
crude oil are:
Oil formation volume factor less than 1.2 bbl/STB
Gas-oil ratio less than 200 scf/STB
Oil gravity less than 35° API
Black or deeply colored
Substantial liquid recovery at separator conditions as
indicated by point G on the 85% quality line of next slide
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
18
19. Low-Shrinkage Oil
A typical phase diagram for a low-shrinkage
Oil-shrinkage curve for low-shrinkage oil
oil
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
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20. Volatile (high-shrinkage) crude oil
Note that the quality lines are close together near the
bubble-point and are more widely spaced at lower
pressures.
This type of crude oil is commonly characterized by a
high liquid shrinkage immediately below the bubblepoint as shown in next Figure.
The other characteristic properties of this oil include:
Oil formation volume factor less than 2 bbl/STB
Gas-oil ratios between 2,000 and 3,200 scf/STB
Oil gravities between 45° and 55° API
Lower liquid recovery of separator conditions (10% next slide)
Greenish to orange in color
the API gravity of the stock-tank liquid will increase in the
later life of the reservoirs
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
20
21. Volatile Crude Oil
A typical p-T diagram for a volatile crude oil
Spring14 H. AlamiNia
A typical liquid-shrinkage curve for a volatile
crude oil
Reservoir Fluid Properties Course (3rd Ed.)
21
22. Near-critical crude oil
If the Tr is near the Tc of the hydrocarbon system, the
hydrocarbon mixture is identified as a near-critical
crude oil.
Because all the quality lines converge at the critical
point,
an isothermal pressure drop may shrink the crude oil from
100% of the hydrocarbon pore volume at the bubble-point to
55% or less at a pressure 10 to 50 psi below the bubble point.
a high GOR in excess of 3,000 scf/STB
an oil formation volume factor of 2.0 bbl/STB or higher
The compositions of near-critical oils are usually
characterized by 12.5 to 20 mol% heptanes-plus, 35% or
more of ethane through hexanes, and the remainder
methane.
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
22
23. Near-Critical Crude Oil
A schematic phase diagram for the nearA typical liquid-shrinkage curve for the nearcritical crude Reservoir Fluid Properties Course (3rdcrude oil
critical Ed.)
Spring14 H. AlamiNia oil
23
24. Liquid Shrinkage for Crude Oil Systems
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
24
25.
26.
27. Gas Reservoirs
In general, if the reservoir temperature is above the
critical temperature of the hydrocarbon system, the
reservoir is classified as a natural gas reservoir.
On the basis of their phase diagrams and the
prevailing reservoir conditions, natural gases can be
classified into four categories:
Retrograde gas-condensate
Near-critical gas-condensate
Wet gas
Dry gas
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
27
28. Retrograde gas-condensate reservoir
If the Tr lies between the Tc and Tct of the reservoir
fluid, the reservoir is classified as a retrograde gas
condensate reservoir.
This category of gas reservoir is a unique type of
hydrocarbon accumulation in that the special
thermodynamic behavior of the reservoir fluid is the
controlling factor in the development and the depletion
process of the reservoir.
When the pressure is decreased on these mixtures,
instead of expanding (if a gas) or vaporizing (if a
liquid) as might be expected, they vaporize instead
of condensing.
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
28
29. Retrograde Gas-Condensate
A typical phase
diagram of a
retrograde
system
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
29
30. Retrograde Gas-Condensate reservoirs
In most gas-condensate
reservoirs, the condensed liquid
volume seldom exceeds more
than 15% to 19% of the pore
volume.
This liquid saturation is not large
enough to allow any liquid flow.
It should be recognized, however,
that around the wellbore where
the pressure drop is high, enough
A typical liquid dropout curve
liquid dropout might accumulate
(liquid shrinkage volume curve to give two-phase flow of gas and
for a condensate system)
retrograde liquid.
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
30
31. Retrograde Gas-Condensate
The associated physical characteristics of this category
are:
Gas-oil ratios between 8,000 and 70,000 scf/STB.
Generally, the GOR for a condensate system increases with time
due to the liquid dropout and the loss of heavy components in the
liquid.
Condensate gravity above 50° API
• Stock-tank liquid is usually water-white or slightly colored
There is a fairly sharp dividing line between oils and
condensates from a compositional standpoint.
Reservoir fluids that contain heptanes and are heavier
in concentrations of more than 12.5 mol% are almost
always in the liquid phase in the reservoir.
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
31
32. Near-critical gas-condensate reservoir
If the Tr is near the Tc, the hydrocarbon mixture is
classified as a near-critical gas-condensate.
Because all the quality lines converge at the critical
point, a rapid liquid buildup will immediately occur
below the dew point.
This behavior can be justified by the fact that several
quality lines are crossed very rapidly by the isothermal
reduction in pressure.
At the point where the liquid ceases to build up and
begins to shrink again, the reservoir goes from the
retrograde region to a normal vaporization region.
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Reservoir Fluid Properties Course (3rd Ed.)
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33. Near-Critical Gas-Condensate
A typical phase diagram for a near-critical
Liquid-shrinkage curve for a near-critical gascondensate system
Spring14 gas AlamiNia reservoir
H. condensate Reservoir Fluid Properties Course (3rd Ed.)
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34. Wet-gas reservoir
In a wet gas reservoir temperature is above the
cricondentherm of the hydrocarbon mixture.
Because the reservoir temperature exceeds the
cricondentherm of the hydrocarbon system, the reservoir
fluid will always remain in the vapor phase region as the
reservoir is depleted isothermally, along the vertical line A-B.
As the produced gas flows to the surface, however, the
pressure and temperature of the gas will decline.
If the gas enters the two-phase region, a liquid phase will
condense out of the gas and be produced from the surface
separators.
This is caused by a sufficient decrease in the kinetic energy of
heavy molecules with temperature drop and their subsequent
change to liquid through the attractive forces between
molecules.
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
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35. Wet-gas reservoirs characterization
Wet-gas reservoirs are characterized by the
following properties:
Gas oil ratios between 60,000 and 100,000 scf/STB
Stock-tank oil gravity above 60° API
Liquid is water-white in color
Separator conditions, i.e., separator pressure and
temperature, lie within the two-phase region
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
35
36. Wet Gas
Phase diagram
for a wet gas
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
36
37. Dry-gas reservoir
The hydrocarbon mixture exists as a gas both in the
reservoir and in the surface facilities.
The only liquid associated with the gas from a drygas reservoir is water.
Usually a system having a gas-oil ratio greater than
100,000 scf/STB is considered to be a dry gas.
Kinetic energy of the mixture is so high and
attraction between molecules so small that none of
them coalesces to a liquid at stock-tank conditions
of temperature and pressure.
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
37
38. Dry Gas
Phase diagram
for a dry gas
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
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39.
40. Other hydrocarbon classifications
The classification of hydrocarbon fluids might also
be characterized by the initial composition of the
system.
McCain (1994) suggested that the heavy components in
the hydrocarbon mixtures have the strongest effect on
fluid characteristics.
The ternary diagram, with equilateral triangles can be
conveniently used to roughly define the compositional
boundaries that separate different types of hydrocarbon
systems.
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
40
42. Qualitative concepts vs. quantitative
analyses
it can be observed that hydrocarbon mixtures may
exist in either the gaseous or liquid state,
depending on the reservoir and
operating conditions to which they are subjected.
The qualitative concepts presented may be of aid in
developing quantitative analyses.
Empirical equations of state are commonly used as
a quantitative tool in describing and classifying the
hydrocarbon system.
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
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43. Empirical equations of state
Equations of state require:
Detailed compositional analyses of the hydrocarbon
system
Complete descriptions of the physical and critical
properties of the mixture individual components
Many characteristic properties of these individual components
(in other words, pure substances) have been measured and
compiled over the years.
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
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44. Characteristic properties
Characteristic properties provide vital information for
calculating the thermodynamic properties of pure
components, as well as their mixtures.
The most important of these properties are:
Critical pressure, pc
Critical temperature, Tc
Critical volume, Vc
Critical compressibility factor, zc
Acentric factor, T
Molecular weight, M
Next slide documents some of the above-listed
properties for a number of hydrocarbon and
nonhydrocarbon components.
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
44
45. Physical Properties for Pure
Components
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
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46.
47. Undefined Petroleum Fractions
Nearly all naturally occurring hydrocarbon systems
contain a quantity of heavy fractions that are not
well defined and are not mixtures of discretely
identified components.
These heavy fractions are often lumped together and
identified as the plus fraction, e.g., C7+ fraction.
A proper description of the physical properties of
the plus fractions and other undefined petroleum
fractions in hydrocarbon mixtures is essential in
performing reliable phase behavior calculations and
compositional modeling studies.
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
47
48. Undefined Petroleum Fractions
Analysis
Frequently, a distillation analysis or a
chromatographic analysis is available for this
undefined fraction.
Other physical properties, such as
molecular weight and specific gravity,
may also be measured
for the entire fraction or
for various cuts of it.
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
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49. Using the thermodynamic propertyprediction models
To use any of
the thermodynamic property-prediction models,
e.g., equation of state,
to predict the phase and volumetric behavior
of complex hydrocarbon mixtures,
one must be able to provide
the acentric factor, along with
the critical temperature and critical pressure,
for both the defined and
undefined (heavy) fractions in the mixture.
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
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50. physical property prediction
Riazi and Daubert (1987) developed a simple twoparameter equation for predicting the physical
properties of pure compounds and undefined
hydrocarbon mixtures.
θ = a (M)^b γ^c EXP [d (M) + e γ + f (M) γ]
based on the use of the M and γ of the undefined petroleum
fraction as the correlating parameters.
Where
θ = any physical property
•
•
•
•
Tc = critical temperature, °R
Pc = critical pressure, psia
Tb = boiling point temperature, °R
Vc = critical volume, ft3/lb
a–f = constants for each property
γ = specific gravity of the fraction
M = molecular weight
Spring14 H. AlamiNia
Reservoir Fluid Properties Course (3rd Ed.)
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51. 1. Ahmed, T. (2010). Reservoir engineering
handbook (Gulf Professional Publishing).
Chapter 1
52. 1. Gas Behavior
2. Gas Properties:
A. Z Factor:
a. Calculation for pure components
b. Calculation for mixture components
I. Mixing rules for calculating pseudocritical properties
II. Correlations for calculating pseudocritical properties
c. Nonhydrocarbon adjustment
d. High molecular weight gases adjustment