COPYRIGHTcloud1.activelearner.com/contentcloud/portals/hosted3/PetroAcademy/... · Waterfloods Water Injection Waterflood Pressure Maintenance Tertiary Well Production Curve Enhanced

Introduction

Enhanced Oil Recovery Core

Enhanced Oil Recovery Core═════════════════════════════════════════════════════════════════════════

© PetroSkills, LLC. All rights reserved._____________________________________________________________________________________________

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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


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 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+%




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Secondary

Recovery Schemes


Secondary Recovery

Secondary Recovery



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Tertiary

Recovery Schemes


Recovery Schemes

Thermal Recovery Methods

Heat



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Secondary & TertiaryPrimary

Recovery Efficiencies


• Dissolved Gas Drive 5 – 30%

• Gas-Cap Drive 20 – 40%


Gas (Percent of Original-Gas-In-Place)

• Gas Expansion 90+%



• Waterflood 30 – 40%

• CO2 Miscible Flood 5 – 10%

• Steamflood 70 – 90%

Secondary

Artificial Lift

Recovery Schemes


Artificial Lift

Primary Tertiary



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Secondary TertiarySecondary

Improved Oil Recovery (IOR)

Recovery Schemes


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


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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Primary Recovery

Recovery Schemes


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


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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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


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




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Injecting into an Oil Zone

Mobility Ratio



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Artificial Gas Cap

Gas Cap

Gas Injection




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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


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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Tertiary Recovery

Recovery Schemes


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


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


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


Oil is produced

Condensing Gas Drive

Enhanced Oil Recovery Core ═════════════════════════════════════════════════════════════════════════


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Partially Miscible Recovery


Oil is produced

Oil vaporizes into Solvent

Oil vaporizes into Solvent

Solvent is produced

Vaporizing Gas Drive


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


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




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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


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




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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


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‐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‐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





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






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






Low Salinity Flood



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Chemical Processes

Surfactant

Polymer

Caustic






Low Salinity Flood

Microbial Enhanced Oil Recovery (MEOR)

Chemical Processes

Surfactant

Polymer

Caustic






Low Salinity Flood


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






Low Salinity Flood


Foam Flooding

Chemical Processes

Surfactant

Polymer

Caustic






Low Salinity Flood


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


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




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Depth Limitations for EOR Processes


[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


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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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




Rock Properties



Fluid Properties












GasGas WaterWater

100.

.

. Mscf/d

Equivalent Gas Rate

Conversion from barrels to

cubic feet

kilo



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Gas

Water



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[152.4] [304.8] [157.2] [609.6] [762.0][m]

Oil Production Rate

Gas breaks through

first



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From water flood

From gas flood

Relative Permeability

Case 1 Case 2

Geometry




Rock Properties



Fluid Properties












We’ve made the gas less wettablethan the oil in the last three lines.



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Old water-oilCase 2

New gas-oilCase 1


OldCase 2

NewCase 1



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[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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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


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

∆

∆


∆ |∆

∅∆ ∆

∆

∆

Koval: Fractional Flow Gradient



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1 1

∆∆ 1 1

Koval

∆

∆

∆∆


∆ |∆

∅∆ ∆

∆

∆

∆

∅∆ ∆ ∆ ∆∆

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


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




Rock Properties



Fluid Properties












GasGas WaterWater


Water

Gas



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Raising the Temperature

Hot Gas vs. Water

Case 1 Case 2

Geometry




Rock Properties



Fluid Properties












GasGas WaterWater



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Water

Gas

Hot vs. Cold Water

Case 1 Case 2

Geometry




Rock Properties



Fluid Properties














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Normal Water Flood

Hot Water


[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




Rock Properties



Fluid Properties














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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




Rock Properties



Fluid Properties

Oil Viscosity [cp] 105 5370











Oil Production Rate



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[152.4] [304.8] [157.2] [609.6] [762.0][m]

Cold Water Flood Front

VelocityCase 2

Hot Water Flood Front

VelocityCase 1


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


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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Case 1 Case 2

Geometry




Rock Properties



Fluid Properties



Water Viscosity [cp] 0.7588 0.7588






Water Relative Permeability Endpoint [md/md] 0.700 0.200


Water Relative Permeability Exponent [] 2.000 4.000




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[152.4] [304.8] [157.2] [609.6] [762.0][m]

NewCase 1

OldCase 2



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Oil Production Rate




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Adding Polymer

Viscosity

Case 1 Case 2

Geometry




Rock Properties



Fluid Properties














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[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




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Subtracting Surfactant


Case 1 Case 2

Geometry




Rock Properties



Fluid Properties














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Waterflood curve

Polymer flood


[m]

NewCase 1

OldCase 2



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Oil Production Rate




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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




Rock Properties



Fluid Properties














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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




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[152.4] [304.8] [157.2] [609.6] [762.0][m]

Oil Production Rate



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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




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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.


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.


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


Improved Oil Recovery Fundamentals

Reservoir Simulation Core

Reserves and Resources Core

Reservoir Surveillance Core

Reservoir Surveillance Fundamentals

Reservoir Management Core

Reservoir Management Fundamentals




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