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Introduction
Enhanced Oil Recovery Core
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Learning Objectives
By the end of this lesson, you will be able to:
Discuss the differences between Secondary and Tertiary Recovery
Compare Pattern Floods to Peripheral Floods
Describe the Life Stages of a Waterflood
Compare different types of Tertiary Recovery Processes
Discuss Screening Criteria for selecting floods
Introduce Rules of Thumb for predicting flood performance
Describe Simplified Models for predicting flood performance
Topic Agenda
Injection of water and gas into an oil reservoir for secondary recovery.
Secondary Recovery
Injection of water and gas into both oil and gas reservoirs for tertiary recovery.
Tertiary Recovery
Simplified modeling of secondary and tertiary processes.
Modeling
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Recovery Schemes
Learning Objectives
By the end of this lesson, you will be able to:
Explain the differences between primary, secondary and tertiary recovery
Outline the differences between secondary recovery and artificial lift
Recite the most common definitions of the terms ‘IOR’ and ‘EOR’
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Recovery Schemes
Primary Secondary Tertiary
Recovery Schemes
Primary
Recovery Schemes
Primary Secondary Tertiary
Primary Recovery
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Primary Recovery
Recovery Efficiencies
Oil (Percent of Original-Oil-in-Place)
• Dissolved Gas Drive 5 – 30%
• Gas-Cap Drive 20 – 40%
• Water Drive 35 – 75%
Gas (Percent of Original-Gas-In-Place)
• Gas Expansion 90+%
• Water Drive 50 – 80%
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Secondary
Recovery Schemes
Primary Secondary Tertiary
Secondary Recovery
Secondary Recovery
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Tertiary
Recovery Schemes
Primary Secondary Tertiary
Recovery Schemes
Thermal Recovery Methods
Heat
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Secondary & TertiaryPrimary
Recovery Efficiencies
Oil (Percent of Original-Oil-in-Place)
• Dissolved Gas Drive 5 – 30%
• Gas-Cap Drive 20 – 40%
• Water Drive 35 – 75%
Gas (Percent of Original-Gas-In-Place)
• Gas Expansion 90+%
• Water Drive 50 – 80%
Oil (Percent of Original-Oil-in-Place)
• Waterflood 30 – 40%
• CO2 Miscible Flood 5 – 10%
• Steamflood 70 – 90%
Secondary
Artificial Lift
Recovery Schemes
Primary Secondary Tertiary
Artificial Lift
Primary Tertiary
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Secondary TertiarySecondary
Improved Oil Recovery (IOR)
Recovery Schemes
Primary Secondary Tertiary
Artificial Lift
Tertiary
Improved Oil
Recovery
TertiarySecondary
Recovery Schemes
Primary Tertiary
Artificial Lift
Tertiary
Enhanced Oil
Recovery
Enhanced Oil Recovery (EOR)
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Learning Objectives
Explain the differences between primary, secondary and tertiary recovery
Outline the differences between secondary recovery and artificial lift
Recite the most common definitions of the terms ‘IOR’ and ‘EOR’
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Water Injection for Secondary Recovery
Enhanced Oil Recovery Core
Learning Objectives
By the end of this lesson, you will be able to:
Explain the differences between a waterflood scheme and a pressure maintenance scheme
Identify pattern floods and peripheral floods
Describe how patterns are defined
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Primary Recovery
Recovery Schemes
Primary Secondary Tertiary
Recovery Schemes
Primary Secondary
Gasflood
Waterflood
Tertiary
Secondary Recovery
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Water Injection
Water Injection
Waterflood Pressure Maintenance Tertiary
Water Injection
Improve Recovery
Maintain Pressure
Uses Water
Maintain Pressure
Improve Recovery
Uses Any Fluid
Waterflood Pressure Maintenance
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Waterfloods
Water Injection
Waterflood Pressure Maintenance Tertiary
Waterflooding
See Reservoir Fluid Displacement Modules for more information.
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Peripheral Drive
Waterflood
Peripheral Pattern
Peripheral Drive
Peripheral FloodFault
Oil-water contact
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Pattern Drive
Waterflood
Peripheral Pattern
Pattern Drive
Pattern Flood
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Defining a Pattern
Staggered Line Drive
Alternate Definition
5-Spot
A “staggered line drive” pattern and a “5-Spot pattern” are equivalent.
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Different Pattern
Direct Line Drive
Water Injection
Shorter Life
Viscous Dominated Front
Longer Life
Gravity Stabilized Front
InjectedWater
NativeOil
FrontFront
Pattern Floods Peripheral Floods
InjectedWater
NativeOil
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Learning Objectives
Explain the differences between a waterflood scheme and a pressure maintenance scheme
Identify pattern floods and peripheral floods
Describe how patterns are defined
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Bubble Points
Learning Objectives
By the end of this lesson, you will be able to:
List the pros and cons of starting a waterflood above and below the bubble point pressure
Describe the life stages of a waterflood
Explain the rules of thumb for forecasting waterflood performance
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Waterfloods
Water Injection
WaterfloodPressure
MaintenanceTertiary
Well Production Curve
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Well Production Curve
Well Production Curve
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Waterflood Start
Waterflood Start
Above Bubble Point
Below Bubble Point
Waterflood Start
Quicker Response Slower Response
Above Bubble Point Below Bubble Point
Above Bubble Point
Below Bubble Point
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Waterflood Start
Greater Risk Lesser Risk
Above Bubble Point
Quicker Response
Higher Recovery
Less Wells
Below Bubble Point
Slower Response
Lower Recovery
More Wells
Above Bubble Point
Waterflood Start
Above Bubble Point
Below Bubble Point
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Above Bubble Point
Plateau
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Decline
Below Bubble Point
Waterflood Start
Above Bubble Point
Below Bubble Point
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Below Bubble Point
Fill Up
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Incline
Plateau
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Decline
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Gas Injection
Learning Objectives
By the end of this lesson, you will be able to:
Identify two modes of gas injection for secondary recovery
Outline the roles of gravity segregation and mobility ratio on the effectiveness of each mode
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Secondary Recovery
Water Injection Gas Injection
Secondary Recovery
Gas Injection
Secondary Recovery
Water Injection Gas Injection
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Gas Injection
Oil Zone Gas Cap Tertiary
Gas Injection
Oil Zone
Gas Injection
Oil Zone Gas Cap Tertiary
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Injecting into an Oil Zone
Mobility Ratio
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Artificial Gas Cap
Gas Cap
Gas Injection
Oil Zone Gas Cap Tertiary
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Injecting into a Gas Cap
tan1tan
Dimensionless Gravity Number
∆ ∆
For more information on these equations, see the modules for
Reservoir Fluid Displacement.
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Learning Objectives
Identify two modes of gas injection for secondary recovery
Outline the roles of gravity segregation and mobility ratio on the effectiveness of each mode
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Gas Reservoirs for Tertiary Recovery
Enhanced Oil Recovery Core
Learning Objectives
By the end of this lesson, you will be able to:
Recite various definitions of tertiary recovery
Recall that tertiary processes apply to both oil and gas reservoirs
Explain how gas cycling works in both volumetric and water drive reservoirs
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Tertiary Recovery
Recovery Schemes
Primary Secondary Tertiary
Definitions
Reducing Residual Oil
Injecting Exotic Materials
Changing Rocks and Fluids
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Tertiary Recovery
Gas Reservoirs Oil Reservoirs
Tertiary Recovery
Phase Diagram
See the Reservoir Fluid Propertiesmodules for more information.
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Gas Cycling vs. Gas Depletion
Phase Diagram (P-T Diagram) for Wet Gas
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Gas Cycling vs. Water Drive Gas Production
Learning Objectives
Recite various definitions of tertiary recovery
Recall that tertiary processes apply to both oil and gas reservoirs
Explain how gas cycling works in both volumetric and water drive reservoirs
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Miscible Flooding
Learning Objectives
By the end of this lesson, you will be able to:
List the various types of solvents used and the two common chasers
Identify Water Alternating Gas, or WAG
Describe the effects of miscibility on the recovery process
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Oil Reservoirs
Tertiary Recovery
Gas Reservoirs Oil Reservoirs
Tertiary Oil
Chemical Thermal Miscible Others
Tertiary Oil
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Miscible Oil
Tertiary Oil
Chemical Thermal Miscible Others
Miscible Flooding
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LPG Miscible Gas Flood Process
Carbon Dioxide Miscible Flooding
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Carbon Dioxide Miscible Flooding
Water-Alternating Gas Flood Process
WAG
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Water-Alternating Gas Flood Process
WAG
Secondary Gas Injection
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Partially Miscible Recovery
Solvent dissolves into Oil
Solvent dissolves into Oil
Oil is produced
Condensing Gas Drive
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Partially Miscible Recovery
Solvent dissolves into Oil
Oil is produced
Oil vaporizes into Solvent
Oil vaporizes into Solvent
Solvent is produced
Vaporizing Gas Drive
Solvent dissolves into Oil
Oil is produced
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Other Solvents
Other Solvents: Nitrogen
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Other Solvents: Flue Gas
Other Solvents: NOT Air
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Other Solvents: Alcohols
Learning Objectives
List the various types of solvents used and the two common chasers
Identify Water Alternating Gas, or WAG
Describe the effects of miscibility on the recovery process
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Thermal Processes
Learning Objectives
By the end of this lesson, you will be able to:
Identify the two major types of thermal recovery
Describe thermal stimulation
List some of the newer applications of thermal technology
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Tertiary Recovery
Tertiary Recovery
Gas Reservoirs
Oil Reservoirs
Tertiary Recovery
Oil Reservoirs
Tertiary Oil
Tertiary Oil
Chemical Thermal Miscible OthersMiscible
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Thermal Processes
Tertiary Oil
Chemical Thermal Miscible OthersThermal
Effect of Heat on Viscosity
Heat
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Kern River Viscosities
[38] [93] [149]
[C]
Viscosity (cp)
Steamflood
Thermal Processes
Steamflood Fireflood Huff & Puff OthersSteamflood
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Steam Drive (Steamflood)
Steam Chest Formation
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Heat Loss to Overburden and Underburden
Steam-Assisted Gravity Drainage (SAGD)
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Fireflood
Thermal Processes
Steamflood Fireflood Huff & Puff OthersFireflood
Air Injection
When we inject air under pressure into an oil reservoir, usually the oil will spontaneously start to burn
If it does not, then we heat up the injected air first for a while until the oil starts to burn
If that does not work either, then we heat up the air and the wellbore with a downhole heater
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Dry Forward In-Situ Combustion
Huff & Puff
Thermal Processes
Steamflood Fireflood Huff & Puff OthersHuff & Puff
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Cyclic Steam Stimulation
Cyclic Steam Stimulation
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Cyclic Steam Stimulation
Others
Thermal Processes
Steamflood Fireflood Huff & Puff OthersOthers
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Thermal Processes
Huff & Puff
Fireflood
Steamflood
Thermal Processes
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Learning Objectives
Identify the two major types of thermal recovery
Describe thermal stimulation
List some of the newer applications of thermal technology
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Chemical Processes
Learning Objectives
By the end of this lesson, you will be able to:
List the similarities and differences between the two major groups
Explain how combining chemical methods to make new floods has been popular for years
Describe how some of these methods may work in the field
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Oil Reservoirs
Tertiary Recovery
Gas Reservoirs
Oil Reservoirs
Oil Reservoirs
Tertiary Recovery
Tertiary Oil
Tertiary Oil
Chemical Thermal Miscible Others
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Chemical Processes
Tertiary Oil
Chemical Thermal Miscible OthersChemical
Chemical Processes
Surfactant Polymer Caustic Other
Chemical Processes
Other
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Chemical Processes
Surfactant Polymer Caustic Other
Surfactant Flooding
Surfactant
Surfactant Flooding
The chemicals used to lower the surface tension between the injected water and the oil allow a large fraction of the trapped residual oil to flow towards the wellbore
This is analogous to the way soap reduces the surface tension between the natural oil on your hands and water from the tap
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Surfactant Flooding
The earliest surfactants used for flooding were sulphonated crude oil fractions; the cost of the chemical was the cost of the oil + distillation + sulphonation
Newer, synthetic surfactants can be even more expensive
Many surfactants become less effective when the injection water or the connate water is ‘hard’
This can be fixed by either softening the injection water, increasing the concentration of surfactant, or changing the type of surfactant used
In the early days of surfactant flooding, a preflush of fresh water would be injected before the slug, if connate water hardness was expected to be a problem, but this is no longer a popular choice
Polymer Flooding
Chemical Processes
Surfactant Polymer Caustic OtherPolymer
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Polymer Flooding
Polymer Flooding
Water thickeners and detergents share several weaknesses:
• High cost, oil based material
• High salinity and hard water challenges
A sensitivity to temperature; the viscosity of a polymer solution that is too hot can be only slightly larger than water at the same temperature
A tendency to drop out of solution and hang out with rock surfaces; decreases the viscosity of the water
A need to be very carefully mixed at the surface
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Caustic Flooding
Chemical Processes
Surfactant Polymer Caustic OtherCaustic
Caustic Soda
Adding caustic soda to injection water makes the rock more water wet, and reduces the surface tension between the water and the oil
Caustic flooding has lower chemical costs
It does not work on all reservoirs; the generation of in-situ surfactants is more likely to be successful if the oil is acidic
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Other Processes
Chemical Processes
Surfactant Polymer Caustic OtherOther
Chemical Processes
Surfactant
Polymer
Caustic
Alkali‐Surfactant (AS)
The caustic soda is called a ‘co-surfactant’
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Chemical Processes
Surfactant
Polymer
Caustic
Alkali‐Surfactant (AS)
Surfactant‐Polymer (SP)
The most common form of surfactant flooding
A polymer slug is inserted between the surfactant slug and the chase water
Fixing the water hardness to protect the surfactant also protects the polymer
Chemical Processes
Surfactant
Polymer
Caustic
Alkali‐Surfactant (AS)
Surfactant‐Polymer (SP)
Alkali‐Polymer (AP)
A cheaper alternative to a ‘Surfactant Polymer’ flood
Caustic soda conditions the water for the polymer slug, which means that an acidic oil may not be necessary for success
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Chemical Processes
Surfactant
Polymer
Caustic
Alkali‐Surfactant (AS)
Surfactant‐Polymer (SP)
Alkali‐Polymer (AP)
Alkali‐Surfactant‐Polymer (ASP)
This type of flood is very popular right now
The success of the flood depends on tuning the chemical concentrations, slug sizes and slug orders to optimize the displacement of oil from each reservoir
Chemical Processes
Surfactant
Polymer
Caustic
Alkali‐Surfactant (AS)
Surfactant‐Polymer (SP)
Alkali‐Polymer (AP)
Alkali‐Surfactant‐Polymer (ASP)
Carbonated Waterflood
Very similar to the CO2
WAG discussed earlier, except CO2 is injected into the reservoir simultaneously with the water
Once the pressure is high enough, there is only one injected phase
The CO2 partitions from the liquid water phase directly into the liquid oil phase without going through a gas phase
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Chemical Processes
Surfactant
Polymer
Caustic
Alkali‐Surfactant (AS)
Surfactant‐Polymer (SP)
Alkali‐Polymer (AP)
Alkali‐Surfactant‐Polymer (ASP)
Carbonated Waterflood
Low Salinity Flood
Works by removing instead of adding material to the injection water
By injecting water that has a lower salinity than the connate water, you can reduce the residual oil saturation to water and therefore improve recovery
A couple of theories:• Changing salinity of brine
upsets electrochemical balance at interface
• Weakening of the surface tension between the oil and the water
Chemical Processes
Surfactant
Polymer
Caustic
Alkali‐Surfactant (AS)
Surfactant‐Polymer (SP)
Alkali‐Polymer (AP)
Alkali‐Surfactant‐Polymer (ASP)
Carbonated Waterflood
Low Salinity Flood
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Chemical Processes
Surfactant
Polymer
Caustic
Alkali‐Surfactant (AS)
Surfactant‐Polymer (SP)
Alkali‐Polymer (AP)
Alkali‐Surfactant‐Polymer (ASP)
Carbonated Waterflood
Low Salinity Flood
Microbial Enhanced Oil Recovery (MEOR)
Chemical Processes
Surfactant
Polymer
Caustic
Alkali‐Surfactant (AS)
Surfactant‐Polymer (SP)
Alkali‐Polymer (AP)
Alkali‐Surfactant‐Polymer (ASP)
Carbonated Waterflood
Low Salinity Flood
Microbial Enhanced Oil Recovery (MEOR)
The next step was to get the microbes to use crude oil as the biomass, as this would reduce the manufacturing costs to near zero
The follow-up step was to figure out how to stimulate the in-situ microbes to make surfactants
The fraction of tertiary recovery projects worldwide that are Microbial Enhanced Oil Recovery (MEOR) based continues to be very small
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Chemical Processes
Surfactant
Polymer
Caustic
Alkali‐Surfactant (AS)
Surfactant‐Polymer (SP)
Alkali‐Polymer (AP)
Alkali‐Surfactant‐Polymer (ASP)
Carbonated Waterflood
Low Salinity Flood
Microbial Enhanced Oil Recovery (MEOR)
Foam Flooding
Chemical Processes
Surfactant
Polymer
Caustic
Alkali‐Surfactant (AS)
Surfactant‐Polymer (SP)
Alkali‐Polymer (AP)
Alkali‐Surfactant‐Polymer (ASP)
Carbonated Waterflood
Low Salinity Flood
Microbial Enhanced Oil Recovery (MEOR)
Foam Flooding
In order to move through the rock, the gas in a particular bubble has to push a thin film of liquid bridging the pore in front of it and pull a similar film of liquid behind it
The extra energy required to do this work shows up on a macro scale as a greater resistance to flow
The easiest way to make a foam in-situ is to inject surfactants simultaneously with gas
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Learning Objectives
List the similarities and differences between the two major groups
Explain how combining chemical methods to make new floods has been popular for years
Describe how some of these methods may work in the field
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Tertiary Processes
Learning Objectives
By the end of this lesson, you will be able to:
Explain the ways an engineer can decide which tertiary process to use for his or her reservoir
Describe examples of ‘rules of thumb’
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Recovery Processes
Recovery Processes
How do you choose the
for your reservoir?
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Reservoir Life Cycle
The traditional answer is...
AbandonmentPrimary Secondary
Common Workflow
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Primary Secondary Abandonment
Common Workflow
Primary Tertiary Abandonment
Less Common Workflow
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Primary Tertiary Abandonment
Less Common Workflow
Primary Abandonment
Most Common Workflow
Most Common Workflow:
Skip both secondary and
tertiary
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Primary Abandonment
Most Common Workflow
A good idea when the reservoir is too small to justify further development
Secondary Abandonment
Workflow
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Secondary Abandonment
Workflow
Tertiary Abandonment
Workflow
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Choosing Recovery Process
The Reservoir Management modules address decision-making.
Choosing Recovery Process
Modeling
Analogy
Rules of Thumb
Analogy
Modeling
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Optimum Viscosity Ranges for EOR Processes
Surfactant / Polymer
Permeability Guidelines for EOR Processes
Surfactant / Polymer
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Depth Limitations for EOR Processes
Surfactant / Polymer
[m]
[.31] [610] [1219] [1829] [2438] [3048]
Learning Objectives
Explain the ways an engineer can decide which tertiary process to use for his or her reservoir
Describe examples of ‘rules of thumb’
Choosing Processes
Modeling Analogy Rules of Thumb
Historical Precedent
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Modeling Secondary Processes: Water vs. Gas Injection
Enhanced Oil Recovery Core
Learning Objectives
By the end of this lesson, you will be able to:
Explain how to model immobile fluid phases as rock, so that you can compare different types of floods against each other and draw preliminary conclusions on what processes work best in your reservoir
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Fudging Tertiary
Start Simple
Fudge Tertiary
Add Complexity
1
11
∆ |∆
∅∆ ∆∆∆
Buckley-Leverett
See Fluid Displacement Core for more about Buckley-Leverett.
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Spreadsheet
New Tab
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Water Injection
Changing Basis
Case 1 Case 2
Geometry
Injector-Producer Distance [ft] 2,000.0 2,000.0
Injector-Injector Distance [ft] 500.0 500.0
Net Thickness [ft] 20.0 20.0
Rock Properties
Effective Porosity [vol/vol] 0.175 0.250
Absolute Permeability [md] 100.0 100.0
Fluid Properties
Oil Viscosity [cp] 4.9998 4.9998
Oil Formation Volume Factor [bbl/stb] 1.2454 1.2454
Gas or Water Viscosity [cp] 0.7588 0.7588
Water Formation Volume Factor [bbl/stb] 1.0059 1.0059
Rock-Fluid Properties
Critical Water Saturation [vol/vol] 0.0 0.300
Residual Oil Saturation [vol/vol] 0.214 0.150
Oil Relative Permeability Endpoint [md/md] 0.900 0.900
Gas or Water Relative Permeability Endpoint [md/md] 0.200 0.200
Oil Relative Permeability Exponent [] 4.000 2.000
Gas or Water Relative Permeability Exponent [] 2.000 4.000
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Relative Permeability Curves
OldCase 2
NewCase 1
Fractional Flow Curve
NewCase 1
OldCase 2
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Saturation-Distance Plot
[152.4] [304.8] [157.2] [609.6] [762.0][m]
NewCase 1
OldCase 2
Oil Production Rate
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Water Production Rate
Cumulative Oil Production
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Gas Injection
Gas vs. Water
Viscosity• 0.028233 [cP]
Viscosity• 0.7588 [cP]
GAS WATER
Formation Volume Factor
• 0.003183 [cuft/scf]
Formation Volume Factor
• 1.0059 [bbl/stb]
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Gas vs. Water
Case 1 Case 2
Geometry
Injector-Producer Distance [ft] 2,000.0 2,000.0
Injector-Injector Distance [ft] 500.0 500.0
Net Thickness [ft] 20.0 20.0
Rock Properties
Effective Porosity [vol/vol] 0.175 0.175
Absolute Permeability [md] 100.0 100.0
Fluid Properties
Oil Viscosity [cp] 4.9998 4.9998
Oil Formation Volume Factor [bbl/stb] 1.2454 1.2454
Gas or Water Viscosity [cp] 0.0282 0.7588
Water Formation Volume Factor [bbl/stb] 1.0059 1.0059
Rock-Fluid Properties
Critical Water Saturation [vol/vol] 0.000 0.000
Residual Oil Saturation [vol/vol] 0.214 0.214
Oil Relative Permeability Endpoint [md/md] 0.900 0.900
Gas or Water Relative Permeability Endpoint [md/md] 0.200 0.200
Oil Relative Permeability Exponent [] 4.000 2.000
Gas or Water Relative Permeability Exponent [] 2.000 4.000
GasGas WaterWater
100.
.
. Mscf/d
Equivalent Gas Rate
Conversion from barrels to
cubic feet
kilo
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Relative Permeability Curves
Fractional Flow Curve
Gas
Water
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Saturation-Distance Plot
[152.4] [304.8] [157.2] [609.6] [762.0][m]
Oil Production Rate
Gas breaks through
first
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Cumulative Oil Production
From water flood
From gas flood
Relative Permeability
Case 1 Case 2
Geometry
Injector-Producer Distance [ft] 2,000.0 2,000.0
Injector-Injector Distance [ft] 500.0 500.0
Net Thickness [ft] 20.0 20.0
Rock Properties
Effective Porosity [vol/vol] 0.175 0.175
Absolute Permeability [md] 100.0 100.0
Fluid Properties
Oil Viscosity [cp] 4.9998 4.9998
Oil Formation Volume Factor [bbl/stb] 1.2454 1.2454
Gas or Water Viscosity [cp] 0.0282 0.7588
Water Formation Volume Factor [bbl/stb] 1.0059 1.0059
Rock-Fluid Properties
Critical Water Saturation [vol/vol] 0.000 0.000
Residual Oil Saturation [vol/vol] 0.214 0.214
Oil Relative Permeability Endpoint [md/md] 0.900 0.900
Gas or Water Relative Permeability Endpoint [md/md] 0.950 0.200
Oil Relative Permeability Exponent [] 2.000 2.000
Gas or Water Relative Permeability Exponent [] 4.000 4.000
We’ve made the gas less wettablethan the oil in the last three lines.
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Relative Permeability Curves
Old water-oilCase 2
New gas-oilCase 1
Fractional Flow Curve
OldCase 2
NewCase 1
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Saturation-Distance Plot
[152.4] [304.8] [157.2] [609.6] [762.0] [914.4] [1066.8][m]
Oil Production Rate
Sharp fall-off in production rate indicates when
the injected fluid broke through in the producer
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Cumulative Oil Production
From gas flood
From water flood
Conclusions
Higher pressure?
Higher rate?
Steeper Dip?
Oil Wet Rock?
Oil-Water Transition Zone?
Initial Gas Cap?
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Summary
Immobile phases as pseudorock
Gas floods vs. water floods
Learning Objectives
Explain how to model immobile fluid phases as rock, so that you can compare different types of floods against each other and draw preliminary conclusions on what processes work best in your reservoir
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Modeling Tertiary Recovery:Miscible Processes
Learning Objectives
By the end of this lesson, you will be able to:
Describe the Koval modification to the Buckley-Leverett method for predicting the performance of a fully miscible flood
Recall that the key to the whole thing is knowing the viscosity of the solvent and the viscosity of the oil at average reservoir pressure and temperature
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1
11
∆ |∆
∅∆ ∆∆∆
Buckley-Leverett
Miscible Buckley-Leverett
∆ |∆
∅∆ ∆
∆
∆
∆ |∆
∅∆ ∆
∆
∆
Solventconcentrations
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Miscible Buckley-Leverett
∆ |∆
∅∆ ∆
∆
∆
?
∆ |∆
∅∆ ∆
∆
∆
SPE Paper
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SPE Paper
Koval Buckley-Leverett
Koval
∆ |∆
∅∆ ∆
∆
∆
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Buckley-LeverettKoval
Koval: Fractional Flow
∆ |∆
∅∆ ∆
∆
∆
Koval
1 1
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1 1
fs = Solvent fractional flow
Ss = Solvent ‘saturation’
E = Relative viscosity function
Koval: Definitions
∆
∆
Buckley-LeverettKoval
∆ |∆
∅∆ ∆
∆
∆
Koval: Fractional Flow Gradient
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1 1
∆∆ 1 1
Koval
∆
∆
∆∆
Buckley-LeverettKoval
∆ |∆
∅∆ ∆
∆
∆
∆
∅∆ ∆ ∆ ∆∆
Koval: Pore Volumes Injected (Vpi)
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1 1
∆∆ 1 1
1∆∆
Koval
1 1
∆∆ 1 1
1∆∆
Koval: Definitions
Vpi = Volume of solvent injected, as a fraction of pore volume
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1 1
∆∆ 1 1
1∆∆
2 · 11
Koval: Cumulative Oil Production
Koval
1 1
∆∆ 1 1
1∆∆
2 · 11
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1 1
∆∆ 1 1
1∆∆
2 · 11
Koval: Definitions
Npv = Volume of oil produced, as a fraction of pore volume
1 1
∆∆ 1 1
1∆∆
2 · 11
1
Koval Breakthrough
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1 1
∆∆ 1 1
1∆∆
2 · 11
1
Koval Pre-Breakthrough
1 1
∆∆ 1 1
1∆∆
2 · 11
1
Koval Relative Viscosity
0.78 0.22
Where:
E = Relative viscosity function
μo = In-situ, solvent-free oil viscosity
μs = In-situ solvent viscosity
(Vpi)BT = Injected solvent volume at breakthrough, as a fraction of pore volume
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Summary
E.J. Koval vs. Buckley-Leverett
Solvent ‘Saturation’
Relative Viscosity Function
Pore Volumes Injected
Pore Volumes Produced
Breakthrough Time
Learning Objectives
Describe the Koval modification to the Buckley-Leverett method for predicting the performance of a fully miscible flood
Recall that the key to the whole thing is knowing the viscosity of the solvent and the viscosity of the oil at average reservoir pressure and temperature
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Thermal Processes
Learning Objectives
By the end of this lesson, you will be able to:
Adjust the Buckley-Leverett model to predict the approximate performance of a steam flood
Describe the effects of viscosity reduction, in-situ oil distillation, the hot water bank, and the heaviness of the oil
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1
11
∆ |∆
∅∆ ∆∆∆
Buckley-Leverett
Gas Injection
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Gas vs. Water
Case 1 Case 2
Geometry
Injector-Producer Distance [ft] 2,000.0 2,000.0
Injector-Injector Distance [ft] 500.0 500.0
Net Thickness [ft] 20.0 20.0
Rock Properties
Effective Porosity [vol/vol] 0.175 0.175
Absolute Permeability [md] 100.0 100.0
Fluid Properties
Oil Viscosity [cp] 4.9998 4.9998
Oil Formation Volume Factor [bbl/stb] 1.2454 1.2454
Gas or Water Viscosity [cp] 0.0282 0.7588
Water Formation Volume Factor [bbl/stb] 1.0059 1.0059
Rock-Fluid Properties
Critical Water Saturation [vol/vol] 0.0 0.0
Residual Oil Saturation [vol/vol] 0.214 0.214
Oil Relative Permeability Endpoint [md/md] 0.900 0.900
Gas or Water Relative Permeability Endpoint [md/md] 0.950 0.200
Oil Relative Permeability Exponent [] 4.000 2.000
Gas or Water Relative Permeability Exponent [] 2.000 4.000
GasGas WaterWater
Cumulative Oil Production
Water
Gas
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Raising the Temperature
Hot Gas vs. Water
Case 1 Case 2
Geometry
Injector-Producer Distance [ft] 2,000.0 2,000.0
Injector-Injector Distance [ft] 500.0 500.0
Net Thickness [ft] 20.0 20.0
Rock Properties
Effective Porosity [vol/vol] 0.175 0.175
Absolute Permeability [md] 100.0 100.0
Fluid Properties
Oil Viscosity [cp] 1.1238 4.9998
Oil Formation Volume Factor [bbl/stb] 1.2687 1.2454
Gas or Water Viscosity [cp] 0.0041 0.7588
Water Formation Volume Factor [bbl/stb] 1.0462 1.0059
Rock-Fluid Properties
Critical Water Saturation [vol/vol] 0.0 0.0
Residual Oil Saturation [vol/vol] 0.214 0.214
Oil Relative Permeability Endpoint [md/md] 0.900 0.900
Gas or Water Relative Permeability Endpoint [md/md] 0.950 0.200
Oil Relative Permeability Exponent [] 4.000 2.000
Gas or Water Relative Permeability Exponent [] 2.000 4.000
GasGas WaterWater
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Cumulative Oil Production
Water
Gas
Hot vs. Cold Water
Case 1 Case 2
Geometry
Injector-Producer Distance [ft] 2,000.0 2,000.0
Injector-Injector Distance [ft] 500.0 500.0
Net Thickness [ft] 20.0 20.0
Rock Properties
Effective Porosity [vol/vol] 0.175 0.175
Absolute Permeability [md] 100.0 100.0
Fluid Properties
Oil Viscosity [cp] 1.1238 4.9998
Oil Formation Volume Factor [bbl/stb] 1.2687 1.2454
Gas or Water Viscosity [cp] 0.3833 0.7588
Water Formation Volume Factor [bbl/stb] 1.0462 1.0059
Rock-Fluid Properties
Critical Water Saturation [vol/vol] 0.0 0.0
Residual Oil Saturation [vol/vol] 0.214 0.214
Oil Relative Permeability Endpoint [md/md] 0.900 0.900
Gas or Water Relative Permeability Endpoint [md/md] 0.200 0.200
Oil Relative Permeability Exponent [] 2.000 2.000
Gas or Water Relative Permeability Exponent [] 4.000 4.000
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Fractional Flow Curve
Normal Water Flood
Hot Water
Saturation-Distance Plot
[152.4] [304.8] [157.2] [609.6] [762.0][m]
Hot Water
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Oil Production Rate
Distillation
Case 1 Case 2
Geometry
Injector-Producer Distance [ft] 2,000.0 2,000.0
Injector-Injector Distance [ft] 500.0 500.0
Net Thickness [ft] 20.0 20.0
Rock Properties
Effective Porosity [vol/vol] 0.175 0.175
Absolute Permeability [md] 100.0 100.0
Fluid Properties
Oil Viscosity [cp] 1.1238 4.9998
Oil Formation Volume Factor [bbl/stb] 1.2687 1.2454
Gas or Water Viscosity [cp] 0.3833 0.7588
Water Formation Volume Factor [bbl/stb] 1.0462 1.0059
Rock-Fluid Properties
Critical Water Saturation [vol/vol] 0.0 0.0
Residual Oil Saturation [vol/vol] 0.05 0.214
Oil Relative Permeability Endpoint [md/md] 0.900 0.900
Gas or Water Relative Permeability Endpoint [md/md] 0.200 0.200
Oil Relative Permeability Exponent [] 2.000 2.000
Gas or Water Relative Permeability Exponent [] 4.000 4.000
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Relative Permeability Curves
Lower Temp. Case 2
Oil Production Rate
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Heavy Oil
Kern River Viscosities
[38] [93] [149]
[C]
Viscosity (cp)
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Viscosity
Case 1 Case 2
Geometry
Injector-Producer Distance [ft] 2,000.0 2,000.0
Injector-Injector Distance [ft] 500.0 500.0
Net Thickness [ft] 20.0 20.0
Rock Properties
Effective Porosity [vol/vol] 0.175 0.175
Absolute Permeability [md] 100.0 100.0
Fluid Properties
Oil Viscosity [cp] 105 5370
Oil Formation Volume Factor [bbl/stb] 1.2642 1.2396
Gas or Water Viscosity [cp] 0.4776 0.9454
Water Formation Volume Factor [bbl/stb] 1.0281 0.9999
Rock-Fluid Properties
Critical Water Saturation [vol/vol] 0.0 0.0
Residual Oil Saturation [vol/vol] 0.05 0.214
Oil Relative Permeability Endpoint [md/md] 0.900 0.900
Gas or Water Relative Permeability Endpoint [md/md] 0.200 0.200
Oil Relative Permeability Exponent [] 2.000 2.000
Gas or Water Relative Permeability Exponent [] 4.000 4.000
Oil Production Rate
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Relative Permeability Curves
Fractional Flow Curve
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Saturation-Distance Plot
[152.4] [304.8] [157.2] [609.6] [762.0][m]
Cold Water Flood Front
VelocityCase 2
Hot Water Flood Front
VelocityCase 1
Cumulative Oil Production
From steam flood
Cold water flood
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Summary
Viscosity
Distillation
Hot Water Bank
Heavy Oil
Learning Objectives
Adjust the Buckley-Leverett model to predict the approximate performance of a steam flood
Describe the effects of viscosity reduction, in-situ oil distillation, the hot water bank, and the heaviness of the oil
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Chemical Processes
Learning Objectives
By the end of this lesson, you will be able to:
Describe the modeling of three chemical floods: the polymer flood, the surfactant flood and the surfactant-polymer flood
Explain the synergy between polymers and surfactants, the non-linear model responses to changes in water viscosity
Describe the importance of calculating the pressure drop between the injector and the producer
Explain the value of incorporating sweep efficiencies into our calculations
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1
11
∆ |∆
∅∆ ∆∆∆
Buckley-Leverett
Adding Surfactant
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Relative Permeability
Case 1 Case 2
Geometry
Injector-Producer Distance [ft] 2,000.0 2,000.0
Injector-Injector Distance [ft] 500.0 500.0
Net Thickness [ft] 20.0 20.0
Rock Properties
Effective Porosity [vol/vol] 0.175 0.175
Absolute Permeability [md] 100.0 100.0
Fluid Properties
Oil Viscosity [cp] 4.9998 4.9998
Oil Formation Volume Factor [bbl/stb] 1.2454 1.2454
Water Viscosity [cp] 0.7588 0.7588
Water Formation Volume Factor [bbl/stb] 1.0059 1.0059
Rock-Fluid Properties
Critical Water Saturation [vol/vol] 0.0 0.0
Residual Oil Saturation [vol/vol] 0.050 0.214
Oil Relative Permeability Endpoint [md/md] 0.900 0.900
Water Relative Permeability Endpoint [md/md] 0.700 0.200
Oil Relative Permeability Exponent [] 1.500 2.000
Water Relative Permeability Exponent [] 2.000 4.000
Relative Permeability Curves
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Fractional Flow Curve
Saturation-Distance Plot
[152.4] [304.8] [157.2] [609.6] [762.0][m]
NewCase 1
OldCase 2
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Oil Production Rate
Cumulative Oil Production
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Adding Polymer
Viscosity
Case 1 Case 2
Geometry
Injector-Producer Distance [ft] 2,000.0 2,000.0
Injector-Injector Distance [ft] 500.0 500.0
Net Thickness [ft] 20.0 20.0
Rock Properties
Effective Porosity [vol/vol] 0.175 0.175
Absolute Permeability [md] 100.0 100.0
Fluid Properties
Oil Viscosity [cp] 4.9998 4.9998
Oil Formation Volume Factor [bbl/stb] 1.2454 1.2454
Water Viscosity [cp] 7.500 0.7588
Water Formation Volume Factor [bbl/stb] 1.0059 1.0059
Rock-Fluid Properties
Critical Water Saturation [vol/vol] 0.0 0.0
Residual Oil Saturation [vol/vol] 0.050 0.214
Oil Relative Permeability Endpoint [md/md] 0.900 0.900
Water Relative Permeability Endpoint [md/md] 0.700 0.200
Oil Relative Permeability Exponent [] 1.500 2.000
Water Relative Permeability Exponent [] 2.000 4.000
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Fractional Flow Curve
Saturation-Distance Plot
[152.4] [304.8] [157.2] [609.6] [762.0][m]
NewCase 1
OldCase 2
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Oil Production Rate
Much later
breakthrough
Cumulative Oil Production
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Subtracting Surfactant
Relative Permeability
Case 1 Case 2
Geometry
Injector-Producer Distance [ft] 2,000.0 2,000.0
Injector-Injector Distance [ft] 500.0 500.0
Net Thickness [ft] 20.0 20.0
Rock Properties
Effective Porosity [vol/vol] 0.175 0.175
Absolute Permeability [md] 100.0 100.0
Fluid Properties
Oil Viscosity [cp] 4.9998 4.9998
Oil Formation Volume Factor [bbl/stb] 1.2454 1.2454
Water Viscosity [cp] 7.500 0.7588
Water Formation Volume Factor [bbl/stb] 1.0059 1.0059
Rock-Fluid Properties
Critical Water Saturation [vol/vol] 0.0 0.0
Residual Oil Saturation [vol/vol] 0.214 0.214
Oil Relative Permeability Endpoint [md/md] 0.900 0.900
Water Relative Permeability Endpoint [md/md] 0.200 0.200
Oil Relative Permeability Exponent [] 2.000 2.000
Water Relative Permeability Exponent [] 4.000 4.000
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Fractional Flow Curve
Waterflood curve
Polymer flood
Saturation-Distance Plot
[m]
NewCase 1
OldCase 2
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Oil Production Rate
Cumulative Oil Production
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Comparison
Polymer Only
Polymer + Surfactant
Non Physical
Case 1 Case 2
GeometryInjector-Producer Distance [ft] 2,000.0 2,000.0 Injector-Injector Distance [ft] 500.0 500.0 Net Thickness [ft] 20.0 20.0
Rock PropertiesEffective Porosity [vol/vol] 0.175 0.175 Absolute Permeability [md] 100.0 100.0
Fluid PropertiesOil Viscosity [cp] 4.9998 4.9998 Oil Formation Volume Factor [bbl/stb] 1.2454 1.2454 Water Viscosity [cp] 7.5000 0.7588 Water Formation Volume Factor [bbl/stb] 1.0059 1.0059
Rock-Fluid PropertiesCritical Water Saturation [vol/vol] - - Residual Oil Saturation [vol/vol] 0.214 0.214 Oil Relative Permeability Endpoint [md/md] 0.900 0.900 Water Relative Permeability Endpoint [md/md] 0.200 0.200 Oil Relative Permeability Exponent [] 2.000 2.000 Water Relative Permeability Exponent [] 4.000 4.000
Operations DataProducing Pressure [psia] (43.7) 1,318.1 Injection Pressure [psia] 2,500.0 2,500.0 Injection Rate [stb/d] 100.0 100.0 Injection Time [day] 1,000.0 1,000.0
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Reducing Polymer
Viscosity
Case 1 Case 2
Geometry
Injector-Producer Distance [ft] 2,000.0 2,000.0
Injector-Injector Distance [ft] 500.0 500.0
Net Thickness [ft] 20.0 20.0
Rock Properties
Effective Porosity [vol/vol] 0.175 0.175
Absolute Permeability [md] 100.0 100.0
Fluid Properties
Oil Viscosity [cp] 4.9998 4.9998
Oil Formation Volume Factor [bbl/stb] 1.2454 1.2454
Water Viscosity [cp] 3.750 0.7588
Water Formation Volume Factor [bbl/stb] 1.0059 1.0059
Rock-Fluid Properties
Critical Water Saturation [vol/vol] 0.0 0.0
Residual Oil Saturation [vol/vol] 0.214 0.214
Oil Relative Permeability Endpoint [md/md] 0.900 0.900
Water Relative Permeability Endpoint [md/md] 0.200 0.200
Oil Relative Permeability Exponent [] 2.000 2.000
Water Relative Permeability Exponent [] 4.000 4.000
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Physical!
Case 1 Case 2
GeometryInjector-Producer Distance [ft] 2,000.0 2,000.0 Injector-Injector Distance [ft] 500.0 500.0 Net Thickness [ft] 20.0 20.0
Rock PropertiesEffective Porosity [vol/vol] 0.175 0.175 Absolute Permeability [md] 100.0 100.0
Fluid PropertiesOil Viscosity [cp] 4.9998 4.9998 Oil Formation Volume Factor [bbl/stb] 1.2454 1.2454 Water Viscosity [cp] 3.7500 0.7588 Water Formation Volume Factor [bbl/stb] 1.0059 1.0059
Rock-Fluid PropertiesCritical Water Saturation [vol/vol] - - Residual Oil Saturation [vol/vol] 0.214 0.214 Oil Relative Permeability Endpoint [md/md] 0.900 0.900 Water Relative Permeability Endpoint [md/md] 0.200 0.200 Oil Relative Permeability Exponent [] 2.000 2.000 Water Relative Permeability Exponent [] 4.000 4.000
Operations DataProducing Pressure [psia] 676.2 1,318.1 Injection Pressure [psia] 2,500.0 2,500.0 Injection Rate [stb/d] 100.0 100.0 Injection Time [day] 1,000.0 1,000.0
Fractional Flow Curve
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Saturation-Distance Plot
[152.4] [304.8] [157.2] [609.6] [762.0][m]
Oil Production Rate
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Cumulative Oil Production
Comparison
3.75 cP 7.5 cP
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Sweep Efficiency
Sweep Efficiency
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Summary
Polymer vs. Surfactant
Polymer + Surfactant
Viscosity Response
Pressure Checks
Sweep Efficiency Corrections
Learning Objectives
Describe the modeling of three chemical floods: the polymer flood, the surfactant flood and the surfactant-polymer flood
Explain the synergy between polymers and surfactants, the non-linear model responses to changes in water viscosity
Describe the importance of calculating the pressure drop between the injector and the producer
Explain the value of incorporating sweep efficiencies into our calculations
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Summary
Enhanced Oil Recovery Core
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Learning Objectives
Discuss the differences between Secondary and Tertiary Recovery
Compare Pattern Floods to Peripheral Floods
Describe the Life Stages of a Waterflood
Compare different types of Tertiary Recovery Processes
Discuss Screening Criteria for selecting floods
Introduce Rules of Thumb for predicting flood performance
Describe Simplified Models for predicting flood performance
Back to Work Suggestions
Leverage the skills you’ve learned by discussing the skill module objectives with your supervisor to develop a personalized plan to implement on the job. Some suggestions are provided.
Enhanced Oil Recovery Core
Find out how many secondary or tertiary recovery processes have been (or are currently being) carried out on the field that you are responsible for?
How do your reservoir characteristics line up with the screening criteria for that process?
Is it a good fit?
Do there appear to be better processes available?
Find out how many secondary or tertiary recovery processes have been (or are currently being) carried out on the field that you are responsible for?
How do your reservoir characteristics line up with the screening criteria for that process?
Is it a good fit?
Do there appear to be better processes available?
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Back to Work Suggestions
Leverage the skills you’ve learned by discussing the skill module objectives with your supervisor to develop a personalized plan to implement on the job. Some suggestions are provided.
Enhanced Oil Recovery Core
Take a look at the models being used to predict the performance of the secondary and tertiary recovery processes in your field.
Are they physics‐based or empirical?
How do they compare with the simplified models shown here?
PetroAcademyTM Applied Reservoir Engineering Skill Modules
This is Reservoir Engineering Core
Reservoir Rock Properties Core
Reservoir Rock Properties Fundamentals
Reservoir Fluid Core
Reservoir Fluid Fundamentals
Reservoir Flow Properties Core
Reservoir Flow Properties Fundamentals
Reservoir Fluid Displacement Core
Reservoir Fluid Displacement Fundamentals
Properties Analysis Management
Reservoir Material Balance Core
Reservoir Material Balance Fundamentals
Decline Curve Analysis and Empirical Approaches Core
Decline Curve Analysis and Empirical Approaches Fundamentals
Pressure Transient Analysis Core
Rate Transient Analysis Core
Enhanced Oil Recovery Core
Improved Oil Recovery Fundamentals
Reservoir Simulation Core
Reserves and Resources Core
Reservoir Surveillance Core
Reservoir Surveillance Fundamentals
Reservoir Management Core
Reservoir Management Fundamentals
Enhanced Oil Recovery Core
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