181
2/24/2013 1 Petroleum University of Technology (PUT) Enhanced Oil Recovery (EOR)
2/24/2013 1
Petroleum University of
Technology
(PUT)
Enhanced Oil Recovery
(EOR)
2/24/2013 2
Enhanced Oil Recovery (EOR)
Department of Petroleum Engineering
Dr. R. Kharrat
E-Mail: [email protected]
2006
2/24/2013 EOR Winter 2013
3
References
1)Enhanced Oil Recovery, Green D. and P. Willhite,
SPE Pub., 1998.
2)Basic Concepts in EOR Processes, Bavier M., Elsevier Applied Science, 1991.
3)Enhanced Oil Recovery, Lake L. W., Prentice Hall, 1989.
4)Enhanced Oil Recovery, Lateil, Gulf Pub. Co.,1980.
5)Fundamental of Enhanced Oil Recovery, Poollen H.K.,
Penn Well, Books, 1981.
6)Thermal Recovery of Oil & Bitumen, Butler R. M., Prentice Hall,
1991.
7)Water Flooding, Willhite P., SPE Pub., 1986.
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Course content
Chapter 1: Introduction
- Basic Definitions -EOR Classification -EOR Processes Description -Screening Criteria -Limitation ,Environmental and Economic Aspects of EOR
Processes
Chapter 2: Oil Recovery Efficiency
-Microscopic efficiency -Macroscopic efficiency -Mobility Ratio -Viscous fingering -Effect of Parameters -Method of calculations of , ,
AE AE AE
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- Areal sweep efficiency - Lateral sweep efficiency - Volumetric sweep efficiency - Method of calculations
Chapter 3: Linear displacement
- Frontal theory - Fractional flow - VS. and plots - Saturation profile - Water flooding - Chemical Flooding - Dispersion during miscible displacement - Method of calculations
WDSDtDX
2/24/2013 EOR Spring 2006 6
Chapter 4: Gas flooding
-Phase behavior -Miscible flooding -Immiscible flooding -First contact -Multi contact -Vaporization -MMP Determination
2/24/2013 EOR Spring 2006 7
CHAPTER 1
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Introduction
• Conventional oil
• Heavy Oil
• Reserve
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Distribution of identified petroleum
resources in 2003
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Distribution of OIP & Production
55%
45%
Heavy, extra-heavy oil
& bitumen
Heavy crude produced 1%Conventional Crude
Conventional Crude produced 16%
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Oil Reserves Numbers in parentheses give current reserves in billion barrels
2/24/2013 EOR Spring 2006 12
Comparison Between Different Countries’ Proven
Conventional Oil Reserves
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Comparison Between Different Regions’ Oil
Production
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Geographical distribution of heavy,
extra-heavy oils and bitumen resources
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Geographical distribution of heavy, extra
heavy oils and bitumen production
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Future of Conventional Oil
2001 predictions:
Demand +1.5%/yr
Less replacement
World production
peaks in ~2006-
2008
Middle East now at
30%, 50% by 2011
Heavy oil, bitumen,
& other sources
Campbell and Laherrère
March 1998 Scientific
American, p. 78 ff
~29-31
Q- BB/yr
2006-
1978 2008
20
• Conventional Oil Prediction in Red
• Total Need Prediction in Blue Dots
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Worldwide Conventional Oil
Declining
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The Concept of Peak Oil Comparison between discovery and consumption
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Global EOR production today •World wide EOR
production
is below 4% of total
production.
In a mature area like
USA 48 LS
EOR production is above
10% of total production.
Majority is onshore EOR.
Incremental EOR production global volume by EOR method
Thermal 41%
HC injection 25% N2 Injection 19%
CO2 Injection 7%
Polymer/ Chemical 8%
Total = 2930 kbpd
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EOR Target
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EOR in USA Production
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SPE 93708
• Future challenges for producing Middle
East oil fields during Maturation stage
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Middle East
• 10000 wells
• 20 MM bbl/day
• Reserve 600 Billions bbl
• 2000 bbl/day (Average per well)
• 60 MM bbl/well reserve
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U.S.A
• 580000 wells
• 6 MM bbl/day
• 22 billion reserve
• Reserve 22 billion bbl
• 11 bbl/day (Average per well)
• 37000 bbl reserve per well
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Type of field formation in the
Middle East
• 93 giant oil fields in the Middle east
• 63 field produce from carbonate (63%)
• 8 field produce from sandstone (21%)
• 22 both SS & Carbonate (16%)
• Carbonate are: – Heterogeneous
– Layered
– Faulted
– Fractured
– Chemically active
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• 20% of U.S.A reservoirs are carbonate
• 90% of the carbonate are in the Middle
east
• 5 National Companies
• R&D is in the primary stage
• 2000000 wells are needed
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Definitions
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• Primary Oil
Recovery
• Secondary Oil
Recovery
• Tertiary Oil
Recovery
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Primary Recovery ( around 10%)
Natural flow of energy of reservoir
• The primary recovery depends on the conditions encountered in the fields.
• Water Drive (70 to 80%)
• Solution gas drive (10 to 30%)
• Gas Cap Drive
• Gravity Drainage
• Fluid and Rock Expansion
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Primary Oil Recovery
• Optimum Production Rate
• Maximum Recovery Factor
• Pressure decline under control
• Gas Injection
• Water Injection
• production under stabilized conditions
• Monitoring WOR & GOR
• Reservoir Management
2/24/2013 EOR Spring 2006 32
Secondary Recovery 15 TO 60%
• To produce more oil, the pressure in the reservoir must be maintained by injecting another fluid.
Water injection
Gas injection
• Small oil field:
Water into the aquifer Figure 1
Gas into the gas cap Figure 2
• Large field: Fluid injection must be distributed through the reservoir Figure 3
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Tertiary Recovery
• Producing the oil that remain in the part of the
reservoir already swept by the displacing fluid.
• A) Increasing the displacement efficiency
(Part of the reservoir that was already swept in
secondary recovery)
• B) Increasing the sweep efficiency
(producing oil that remains in the part of the
reservoir not swept by displacing fluid)
• C) Increasing both displacement and sweep
efficiencies
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Methods to Improve Recovery Efficiency
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2/24/2013 EOR Spring 2006 36
Definition of EOR • EOR will make unmovable Oil moveable
(POLLEN).
• EOR refers to all recovery methods other than natural production ( LATIEL ).
• EOR techniques for improving displacement or sweep efficiency at the very beginning of the first injection of a displacing fluid (BAVIER).
• EOR refers to any method used to recover more oil from a reservoir than would be produced by primary recovery ( WILLHITE).
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EOR Processes
• Immiscible Figure 4
• Miscible Figure 5
• Chemical Figure 6
• Thermal Figure 7
• Microbial Figure 8
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Chemical Processes
•Polymer Figure 9
•Surfactant Figure 10
•Alkaline Figure 11
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Immiscible
• Water Injection Figure 12
• Gas Injection Figure 13
• CO2 Figure14
• N2/Air Figure 15
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Miscible Displacement Processes
• First - Contact Miscible
• Dynamic Miscible
High - Pressure Gas (Vaporizing)
Enriched Gas (Condensing)
• Mutual Solvent
Micellar
Alcohol
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Thermal Methods
• Steam Injection
- Continuous Figure 16
- Huff & Puff Figure 17 - SAGD Figure 18
• In Situ Combustion Figure 19
- Forward (Dry – Wet)
- Reverse
- Enriched Air
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Non-Thermal Method
VAPEX
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Microbial EOR Figure 20
•In-situ generation of surfactant
•Profile modification
•In-situ gas generation
•Correction for gas and water coning
Major Difficulty
Nutrient delivery to where
it is needed
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SUMMARY
Naturel flow Aquifer drive
Primary recovery
Artificial lift Pump gas lift etc.
IOR
Water Injection Dry HC Gas injection
Secondary recovery
EOR Thermal Gas miscible/ immiscible Chemical & Other
Combustion Steam soak Steam drive Hot water drive
Hydrocarbon CO2 Nitrogen Flue gas
Alkaline / Surfactants Polymer Microbial
Tertiary recovery
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EOR POTENTIAL
• Prospects
• Projects
• Production
2/24/2013 EOR Spring 2006 46
0
500
1000
1500
2000
2500
3000
3500
4000
4500
0 10 20 30 40 50 60 70 80 90 100 RF (%)
Cumu
lative
Oil I
n Plac
e (bl
n bbl)
Recovery Factor in the current
portfolio
Average RF of 34%
Example: Fahud (Oman)
Examples: Ghawar (Saudi Arabia) and Draugen (Norway)
Characteristics: Large, Homogeneous,
high permeability, light oil
Examples: Al Noor Qarn Alam (Oman)
Characteristics: Complex geology, Low permeability
Heavy oil, fractured
2/24/2013 EOR Spring 2006 47
Targets for IOR/EOR
•Unique opportunity to
make a sizeable
contribution to
additional reserves
0 20 60 80 100 40
0
2000
4000
Field optimisation + Infill Drilling
EOR
Aspiration for EOR
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EOR Technology Landscape
Chemical Flooding
Polymer Flooding
Biological / MEOR
Surfactant Flooding Enhanced Alkaline (ASP)
Thermal Gas Injection (Miscible/Non-Miscible) Conventional
• Cyclic steam
Injection
• Steam drive
Unconventional • Thermal conduction • In-Situ Combustion • Electric Heating (RF)
• Steam foam
Hydro Carbon
CO2
Air/ N2 Hydro Carbon
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Big themes in EOR •Thermal Recovery (mainly for heavy oil)
– Mainly steam injection – prime examples in California
– Offshore and deep heavy oil still a challenge
•Gas flooding (mainly for light oils)
– HC gas injection done frequently
– Sour gas re-injection
– CO2, very successful in West Texas
Big opportunity to link to CO2 sequestration and
contaminated gas issues
2/24/2013 EOR Spring 2006 50
Big themes in EOR •Thermal Recovery (mainly for heavy oil)
– Mainly steam injection – prime examples in California
– Offshore and deep heavy oil still a challenge
•Gas flooding (mainly for light oils)
– HC gas injection done frequently
– Successful Gas Oil Gravity Drainage
– CO2, very successful in West Texas Big opportunity to link to CO2 sequestration
•Chemical flooding
– Polymer flooding is mature but still limited applications
– Surfactant flooding not mature
– Microbial techniques upcoming
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Initial fluids Initial Mobility Field test for geology Detailed Geological model
Collecting essential data Laboratory testing Dedicated field tests on options Keep track of remaining oil
Sweating the asset Executing efficiently Inventive new solutions & test
Primary Secondary Tertiary
Life Cycle Approach –
PREPARE for EOR
Primary
Secondary
Tertiary
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Capability Development
(long term careers with significant
practical experience)
Primary Secondary Tertiary
Primary Secondary Tertiary
Increased staff intensity Attracting young staff
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EOR strategy to enhance
Capability
Tools
Operations Skills
More EOR Developments with long term commitments
Current State
Extend Application Envelope New Gas/Thermal settings Improved tools for fractured reservoirs
Enough staff that knows EOR Proper process / procedures
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Active EOR Projects
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Steam 32 14 8 62
Combustion 6 4 2 50
CO2 Miscible 5 1 1 50
CO2 Immiscible 20 8 12 100
Hydrocarbon 4 1 1 0
Nitrogen 1 0 1 100
Polymer 53 16 29 63
Micellar/Polymer 10 4 4 33
Alkaline 3 0 3 0
Totals 134 48 61
MethodNumber of
Discontinued Projects
Number of Listed as 'Successful' or
Number listed as
'Discourraging'
Percentage reported as
Evaluation of completed or terminated EOR projects in the USA (Most
were discontinued in 1986-1988)
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2/24/2013 EOR Spring 2006 57
CANADA • Total oil production 2,250,000 B/D
• EOR production 350,000 B/D
• 2 Cyclic steam projects~180,000 B/D
• 2 Steam flood ~50,000 B/D
• 2 SAGD (commercial) ~30,000 B/D
• 6 SAGD (pilot) ~20,000 B/D
• 2 CO2 miscible 6,000 B/D
• 29 hydrocarbon miscible 40,000 B/D
• 1 Multiracial cyclic 5,000 B/D
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CHINA
• Total oil production 3,371,000 B/D
• EOR production ~170,000 B/D
• 17 steam injection projects
• 2 steam floods
• 15 cyclic steaming
• 18 polymer floods ~15,000 B/D
• 1 in situ combustion
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COLOMBIA
• Total oil production 518,000 B/D
• EOR production ~10,000 B/D
• 3 major cyclic steaming operations
• Others in planning stage
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INDIA
• Total oil production 664,000 B/D
• EOR production Several 1000 B/D
• 5 in situ combustion
• 2 polymer floods
• Others in planning stage
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INDONESIA
• Total oil production 1,000,000 B/D
• EOR production ~250,000 B/D
• 3 large steam floods
• 1 surfactant flood
• 1 micellar flood
2/24/2013 EOR Spring 2006 63
TRINIDAD
• Total oil production 140,000 B/D
• EOR production ~2,000 B/D
• 8 steam injection projects
• 5 immiscible CO2 floods
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VENEZUELA
• Total oil production 2,230,000 B/D
• EOR production ~450,000 B/D
• 38 cyclic steaming projects ~300,000 B/D
• 8 hydrocarbon miscible ~166,000 B/D
• 2 chemical floods
• 1 nitrogen injection
2/24/2013 EOR Spring 2006 65
OTHER COUNTRIES
• TURKEY (Total oil production 46,000 B/D)
• Immiscible CO2 6,000 B/D
• MEXICO (Total oil production 3,417,000 B/D)
• Miscible nitrogen flood
• FRANCE (Total oil production 23,000 B/D)
• Polymer flood
• AUSTRIA (Total oil production 18,000 B/D)
• Immiscible CO2
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2/24/2013 EOR Spring 2006 67
Estimated Annual Worldwide EOR Produced Oil
MB/D
Country Thermal Miscible Chemical EOR Total %
USA 454 191 11.9 656.9 42
Canada 8 127 17.2 152.2 10
Europe 14 3 17 1
Venezuela 108 11 119 7
Other S.Americ 2 NA NA 17 1
USSR 20 90 50 160 10
Other(estimated) 171 280 1.5 452.5 29
Total 777 702 80.6 1574.6 100
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Process Description
2/24/2013 EOR Spring 2006 69
Objectives
• Describe the three major categories of methods which can be used
to improve reservoir recovery efficiency ,and explain their
differences.
• For each method, state whether it can improve displacement
,vertical or areal sweep efficiency and explain how it works.
• Describe screening criteria for enhanced oil recovery methods.
• Use a systematic decision analysis approach for selecting an
alternative to improve reservoir recovery efficiency.
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Enhanced Oil Recovery (EOR) Processes
Enhanced oil recovery (EOR) processes include all methods that use
external sources of energy and/or materials to recover oil that cannot
be produced, economically by conventional means.
EOR methods include:
• Water flooding
• Thermal methods: steam stimulation, steam flooding, hot water drive, and
in-situ combustion
• Chemical methods:polymer,surfactant,caustic,and miscellar /polymer
flooding.
• Miscible methods: hydrocarbon gas,CO2,and nitrogen (flue gas and partial
miscible/immiscible gas injection may also be considered)
2/24/2013 EOR Spring 2006 71
Waterflood Thermal Chemical Miscible gas
Maintains reservoir
pressure
&physically
displaces oil with
water moving
through the
reservoir from
injector to
producer.
Reduce by
steam distillation
and reduces oil
viscosity.
Reduces by
lowering water-oil
interfacial tension,
and increases
volumetric sweep
efficiency by
reducing the water-
oil mobility ratio.
Reduces by
developing
miscibility with the
oil through a
vaporizing or
condensing gas
drive process.
orwS orwS
orwS
The goal of any enhanced oil recovery process is to mobilize”remaining”oil.
This is achieved by enhancing oil displacement and volumetric sweep efficiencies.
• Oil displacement efficiency is improved by reducing oil viscosity (e.g., thermal
floods) or by reducing capillary forces or interfacial tension (e.g., miscible floods).
• Volumetric sweep efficiency is improved by developing a more favorable mobility
ratio between the injectant and the remaining oil-in-place (e.g., polymer floods, water
alternating-gas processes).
2/24/2013 EOR Spring 2006 72
Water flooding
2/24/2013 EOR Spring 2006 73
Mechanisms That Improve Recovery Efficiency
Water Drive
Increased Pressure
Limitations
High oil viscosities result in higher mobility ratios.
Some heterogeneity is acceptable, but avoid extensive fractures
Description
Waterflooding consist of injecting water into the reservoir .It is the most
post-primary recovery method. water is injected in patterns or along the
periphery of the reservoir
2/24/2013 EOR Spring 2006 74
Challenges
Poor compatibility between the injected water and the
reservoir may cause formation damage.
Screening Parameters
Gravity >25 API Viscosity <30cp
Composition not critical oil saturation >10% mobile oil
Formation type sandstone/carbonate Net thickness not critical
Average permeability not critical Transmissibility not critical
Depth not critical Temperature not critical
Note: Most EOR screening values are approximations
based on successful north American project.
2/24/2013 EOR Spring 2006 75
Surfactant/Polymer Flooding
2/24/2013 EOR Spring 2006 76
Description
Surfactant/polymer flooding consists of injecting a slug that contains
water ,surfactant, electrolyte (salt), usually a co-solvent (alcohol), and
possibly a hydrocarbon (oil), followed by polymer-thickened water.
Mechanisms That Improve Recovery
Interfacial tension reduction (improves displacement sweep efficiency)
Mobility control
Limitations
An areal sweep of more than 50% for waterflood is desired.
Relatively homogeneous formation.
High amounts of anhydrite, gypsum, or clays are undesirable.
Available systems provide optimum behavior within a narrow set of
conditions.
Water chlorides should be <20000 ppm and divalent ions<500ppm
2/24/2013 EOR Spring 2006 77
Challenges
Complex and expensive system.
Possibility of chromatographic separation of chemicals.
High adsorption of surfactant
Interactions between surfactant and polymer.
Screening Parameters
Gravity >25 API Viscosity <20cp
Composition light intermediates Oil saturation >10% pv
Formation type sandstone Net thickness >10 ft
Average permeability >20md Transmissibility not critical
Depth <8000ft Temperature <225
Salinity of formation brine <150000 ppm TDS
Fo
2/24/2013 EOR Spring 2006 78
Polymer Flooding
2/24/2013 EOR Spring 2006 79
Description
waterflooding consists of adding water soluble polymers to the water
before it is injected into the reservoir.
Mechanisms That Improve Polymer augment Recovery Efficiency
Mobility control( improves volumetric sweep efficiency)
Limitations
High oil viscosities require a higher polymer concentration.
Results are normally better if the polymer flood is started before the
water–oil ratio becomes excessively high.
Clays increase polymer adsorption.
Some heterogeneity is acceptable ,but avoid extensive fractures. if
fractures are present, the crosslinked or gelled polymer techniques may
be applicable.
2/24/2013 EOR Spring 2006 80
Challenges
Lower injectivity than with water can adversely affect oil production rates in the early stages of the polymer flood. acrylamide-type polymers loose viscosity due to sheer degradation, or it increases in salinity and divalent ions.
Screening Parameters
Gravity >18 API Viscosity <200cp
Composition Not Critical oil saturation >10% PV mobile oil
Formation type sandstone /carbonate Net thickness not critical
Average permeability >20md Transmissibility not critical Depth <9000ft Temperature <225
2/24/2013 EOR Spring 2006 81
Polymers Commonly used:
Polyacrylamides
Polysaccharides
General Properties:
PA:
Shear thinning
Shear sensitive (degrederble)
High adsorption/retention
Brine Sensitive
Cheap
PS:
Shear thinning
Less shear Sensitive
Less retention/adsorption
Less retention to brine
More expensive
Sensitive to bacteria
2/24/2013 EOR Spring 2006 82
Miscible Gas Flooding(CO2 injection)
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Description
CO2 flooding consists of injecting large quantities of CO2(15% or more
hydrocarbon pore volume) in the reservoir to form a miscible flood.
Mechanisms That Improve Recovery
CO2 extracts the light –to-intermediate components from the oil ,and if
the pressure is high enough, develops miscibility to displace oil from
the reservoir( vaporizing gas drive)
Viscosity reduction/oil swelling.
Limitations
Very low viscosity of CO2 results in poor mobility control
Availability of CO2
2/24/2013 EOR Spring 2006 84
Challenges
Early breakthrough of CO2 causes problems.
Corrosion in producing wells
The necessity of separating CO2 from saleable hydrocarbons.
Repressuring of CO2 for recycling.
A large requirement of CO2 per incremental barrel produced.
Screening Parameters
Gravity >27 API Viscosity <10cp
Composition C5-C20(C5-C12) oil saturation >30% PV
Formation type sandstone/carbonate Net thickness relatively thin
Average permeability not critical Transmissibility not critical
Depth <2300 ft Temperature <250
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Miscible Gas Flooding (Hydrocarbon Injection)
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.9
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Ternary diagrams may approximate phase behavior of multi-component mixtures
by grouping them into 3 pseudo components. A frequent way of grouping
different components of a mixture based on similarities of critical and other
physical properties is,
•light (C1, CO2, N2- C1, CO2-C2, ...)
•heavy (C7+)
•intermediate (C2-C6)
Ternary diagram illustrating single and two phase regions
2/24/2013 EOR Spring 2006 87
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Light
Heavy Intermediate
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S2
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Heavy Intermediate
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A solvent can be injected in the reservoir to displace oil. This injection can
result in a Miscible Displacement (1-phase), or in an Immiscible
Displacement (2-phase).
miscible and immiscible displacement.
2/24/2013 EOR Spring 2006 88
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01
C1
C2-C6C7+
A
O
CP
First Contact Miscible recovery process (FCM).
2/24/2013 EOR Spring 2006 89
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. 3
. 4
. 5
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1 . 1 . 2 . 3 . 4 . 5 . 6 . 7 . 8 . 9 0
0
1
Light
Heavy Intermediate
Oil 2 Oil 1
Solvent 2
Solvent 1
Critical Tie Line
Vaporizing and 2-condensing gas drive processes.
2/24/2013 EOR Spring 2006 90
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M1
M2
M3
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G2
G3
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Injection Gas
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M1
M2
M3
M4
G2
G3
G4
G1
Injection Gas
Vaporizing gas drive miscibility mechanism.
2/24/2013 EOR Spring 2006 91
Vaporizing gas drive process.
2/24/2013 EOR Spring 2006 92
Ternary diagram illustrating gas injection in a condensing gas drive process.
2/24/2013 EOR Spring 2006 93
Description
Hydrocarbon gas flooding consists of injecting light hydrocarbons through
the reservoir to form a miscible flood.
Mechanisms That Improve Recovery
Viscosity reduction /oil swelling/condensing or vaporizing gas drive.
Limitations
Minimum depth is set by the pressure needed to maintain the generated
miscibility. The required pressure ranges from about 1200 psi for the LPG
process to 3000-5000 psi for the high pressure Gas Drive, depending on the
oil.
A steeply dipping formation is very desirable –pen-nits gravity stabilization of
the displacement that normally has an unfavorable mobility ratio.
2/24/2013 EOR Spring 2006 94
Challenges
Viscous fingering results in poor vertical and horizontal sweep efficiency.
Large quantities of expensive products are required
Solvent may be trapped and not recovered.
Screening Parameters
Gravity >27 API Viscosity <10cp
Composition C2-C7 oil saturation >30% PV
Formation type sandstone/carbonate Net thickness relatively thin
Average permeability not critical Transmissibility not critical
Depth >2000ft (LPG) and >5000ft(lean gas) Temperature <250
2/24/2013 EOR Spring 2006 95
Nitrogen/Flue Gas Flooding
2/24/2013 EOR Spring 2006 96
Description
Nitrogen or flue gas injection consists of injecting large quantities of gas that may
be miscible or immiscible depending on the pressure and oil composition.
Large volumes may be injected, because of the low cost.
Nitrogen or flue gas are also considered for use as chase gases in hydrocarbon-
miscible and CO2 floods.
Mechanisms That Improve Recovery Vaporizes the lighter components of the crude oil and generates miscibility if the
pressure is high enough.
Provides a gas drive where a significant portion of the reservoir volume is filled with
low cost gases
Limitations Miscibility can only be achieved with light oils at high pressures; therefore, deep
reservoirs are needed.
Asteeply dipping reservoir is desired to permit gravity stabilization of the
displacement, which has a very unfavorable mobility ratio.
2/24/2013 EOR Spring 2006 97
Challenges
Viscous fingering results in poor vertical and horizontal sweep efficiency.
gas injection can cause corrosion.
Nonhydrocarbon gases must be separated from saleable gas.
Screening Parameters
Gravity >24 API(35 for N2) Viscosity <10cp
Composition C1-C7 oil saturation >30% pv
Formation type sandstone/carbonate Net thickness relatively thin
Average permeability not critical Transmissibility not critical
Depth <4500ft Temperature not critical
2/24/2013 EOR Spring 2006 98
What is Miscibility
• Under normal conditions, oil & gas reservoir fluids form
distinct, immiscible phases
• Immiscible phases are separated by an interface
– associated with inter-facial tension (IFT)
– when IFT=0, fluids mix => MISCIBILITY
• residual oil saturation to gas (and water) directly
proportional to IFT
• miscible displacement characterized by low/zero residual
oil saturations
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Miscible Processes
• Three basic types of miscible process
– first-contact miscibility
– condensing-gas drive
– vaporizing-gas drive
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Miscible Conditions
• Establishment of miscibility depends on
– pressure (MMP)
– fluid system compositions
• Miscibility normally determined by
laboratory measurement
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Compositional Processes
• First Contact Miscible
• LPG slugs - designed to achieve first -
contact miscibility with oil at leading edge
of slug and with driving gas at trailing edge
2/24/2013 EOR Spring 2006 102
Compositional Processes
0 0
50 100
4000
Pressure
Psia
Dew pts
Plait point
Bubble Pts
Cricondenbar (3250 psig)
Volume % Methane
Rule: For 1st Contact Miscible - Pressure of Displacement
must be above Cricondenbar
2/24/2013 EOR Spring 2006 103
Compositional Processes
Example Oil: C1 - 31% Injection gas: C1
nC4 - 55% C10 - 14%
0 0
50 100
4000
Pressure
Psia
Dew pts
Plait point
Bubble Pts
Cricondenbar (3250 psig)
Volume % Methane
Pressure/Composition Diagram
for Mixtures of C1 with C1/nC4/C10 Oil.
2/24/2013 EOR Spring 2006 104
First Contact Miscibility
• Pressure > MMP
• All points between solvent and reservoir oil
lie in single phase region
• Need high concentrations of solvent -
expensive
EOR Spring 2006 105
Multiple Contact Miscibility
The minimum pressure at which after many contacts
the gas and liquid (oil) become one phase.
Called MCMP - Multiple Contact Miscibility Pressure
EOR Spring 2006 106
Multiple Contact Experiment
Injection Gas
oil
Equilibrium Oil Transferred to Next Cell
Condensing Gas Drive
Injection Gas Injection Gas Injection Gas
2/24/2013 EOR Spring 2006 107
Condensing - Gas Drive
Process
• Injection gas is enriched with intermediate components such as:
• C2, C3, C4 etc
• Mechanism:
– Phase transfer of intermediate MW hydrocarbons from the injected gas into the oil. Some of the gas “Condenses” into the oil.
– The reservoir oil becomes so enriched with these materials that miscibility results between the injection gas and the enriched oil.
2/24/2013 EOR Spring 2006 108
injection gas
o
G
reservoir oil
M1
L1 L2 L3
V2
V3
V1
M2
M3
V4
M4
L4
Plait Point
extension of critical tie line
Mixing 1: Injection gas with Reservoir Oil
Mixture M1 splits into L1 and V1
(liquid and Vapor)
Mixing 2: Injection gas with Liquid L1
Mixture M2 splits into L2 and V2
Mixing 3: Injection gas with Liquid L2
Mixture M3 splits into L3 and V3
Mixing 4: Injection gas with Liquid L3
Mixture M4 splits into L4 and V4
The enriched Liquid Li position moves toward
the Plait Point until a line connecting the
injection gas and the enriched liquid lies
only in the single phase region.
Condensing Gas Drive Miscibility
2/24/2013 EOR Spring 2006 109
Condensing Gas Drive
Miscibility
extension of critical tie line
O
reservoir oil
line from reservoir oil tangent
to 2 phase envelope
gas compositions with NO
multiple contact miscibility
gas compositions with
multiple contact miscibility
gas compositions with
first contact miscibility
Miscibility developed at the
trailing edge of the injection
gas
2/24/2013 EOR Spring 2006 110
Condensing - Gas Drive
• Pressure < MMP
• Solvent and oil not miscible initially
• Solvent components transfer to liquid oil
phase
• Repeated contact between oil and solvent
moves system towards plait (critical) point
(dynamic miscibility)
2/24/2013 EOR Spring 2006 111
Condensing - Gas Drive
• For systems with oil composition to left of
tie line, solvent composition must lie to
right
• Field behaviour is more complicated
– continuous, not batch, contact
– both phases flow
– actual phase behaviour more complicated,
especially near plait point
EOR Spring 2006
Condensing - Gas Drive
Process
As P increases the two phase region becomes smaller. At some pressure the injected gas is to the right of the limiting tie line and MCM develops.
What happens in the simulation when miscibility is achieved?
2/24/2013 EOR Spring 2006 113
Results from slim tube displacements at various pressures
Condensing - Gas Drive
Process
X X X X X
X
X
X
X
X
miscible
Minimum Miscibility Pressure
(MMP)
Oil Recovery
%
P
95-98%
2/24/2013 EOR Spring 2006 114
Slim Tube Recovery of a North Sea Oil
at 100o C
2/24/2013 EOR Spring 2006 115
Procedure to Find Minimum Enrichment
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Vaporizing Gas Drive Process
• Injection Gas - Lean Gas, C1, CO2, N2
• For vaporizing gas drive - multiple contact
miscibility
• Mechanism: Intermediate hydrocarbon
components in the oil vaporize to enrich the gas.
• As the leading edge of the gas slug becomes
sufficiently enriched, it becomes miscible with
the reservoir oil.
EOR Spring 2006 117
Multiple Contact Experiment
Injection Gas
oil
Equilibrium Gas Transferred to Next Cell
oil oil oil oil oil
Vaporizing Gas Drive
2/24/2013 EOR Spring 2006 118
Vaporizing Gas Drive Miscibility
reservoir oil o
injection gas
G
L1
M1
V1
V2
V3
V4
L2
L3 L4
L5
M2
M3
M4
M5
V5
o
o
o
o o
Mixing 1: Injection gas with Reservoir Oil
Mixture M1 splits into L1 and V1
(liquid and Vapor)
Mixing 2: Gas Mix V1 with reservoir oil
Mixture M2 splits into L2 and V2
Mixing 3: Gas Mix V2 with reservoir oil
Mixture M3 splits into L3 and V3
Mixing 4: Gas Mix V3 with reservoir oil
Mixture M4 splits into L4 and V4
Mixing 5: Gas Mix V4 with reservoir oil
Mixture M5 splits into L5 and V5
The enriched Gas Vi position
moves toward the Plait Point
until a line connecting the
enriched gas and the
reservoir oil lies
only in the single
phase region.
2/24/2013 EOR Spring 2006 119
Vaporizing Gas Drive Miscibility injection gas
G
For MCM in a Vaporizing Gas Drive
The Reservoir Oil composition MUST
lie to the right of the limiting tie line
Miscibility developed at the
leading edge of the injection
gas
2/24/2013 EOR Spring 2006 120
Vaporizing Gas Drive Process
• To experimentally determine the MMP for
given [oil, injection gas] combination in a
slim tube, the process and results are
similar to the condensing gas drive
discussion
2/24/2013 EOR Spring 2006 121
Vaporizing and Condensing
Drive
• Where does the miscibility occur?
– Leading Edge or trailing edge?
• Which recovers most reservoir oil?
– Why is not used more often?
2/24/2013 EOR Spring 2006 122
Thermal (Steam flooding)
2/24/2013 EOR Spring 2006 123
Description
Steamflooding consists of injecting %quality steam to displace oil.
Normal practice is to precede and accompany the steam drive by a cyclic steam stimulation of
the producing wells (called huff and puff).
Mechanisms That Improve Recovery Efficiency
Viscosity reduction/steam distillation
Supplies pressure to drive oil to the producing well.
Limitations
Applicable to viscous oils in massive, high permeability sandstones or unconsolidated sands.
Oil saturations must be high, and pay zones should be>20 ft thick to minimize heat losses to
adjacent formations.
Less viscous crude oils can be steam flooded if they don’t respond to water.
Steam flooded reservoirs should be as shallow as possible, because of excessive wellbore
heat losses.
Steam flooding is not normally done in carbonate reservoirs.
Since about 1/3 of the additional oil recovered in consumed to generate the required steam,
the cost per incremental barrel of oil is high.
A low percentage of water –sensitive clays is desired for good injectivity
80
2/24/2013 EOR Spring 2006 124
Challenges
Adverse mobility ratio and channeling of steam.
Screening Parameters
Gravity >35 API(10-35) Viscosity <20cp(10-5000)
Composition not critical Oil saturation >40-50%PV Formation type sandstone Net thickness >20 ft
Average permeability >200md Transmissibility >100 md ft/cp
Depth >200-5000 ft Temperature not critical
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THERMAL RECOVERY
2/24/2013 EOR Spring 2006 126
Constraints for EOR technologies
The following list summarizes the constrains to some of the advanced
recovery technologies identified in this study.
Gas EOR
1)Reservoir heterogeneity
2) Mobility control and reservoir conformance
3) Incomplete mixing
4) Lack of predictive capability
5) Poor injectivity
6) Corrosion problems with C02
2/24/2013 EOR Spring 2006 127
Surfactant Flooding
1) Reservoir heterogeneity
(2) Excessive chemical loss
(3) Coherence, stability and cost-effectiveness of surfactant slugs
(4) Limited to reservoir salinity <20% NaCI
(5) Limited to reservoir temperature <200
(6) Limited to permeability> 100 md
(7) Polymer propagation
Alkaline Flooding
(1) Limited range of applicable salinity
(2) High chemical consumption
(3) Brine incompatibility - precipitation
FO
2/24/2013 EOR Spring 2006 128
Microbial Enhanced Oil Recovery
1) Nutrients for field application
2) Lack of well documented field tests
3) Limited to reservoir temperature < 170
4) Limited to reservoir salinity < 10% NaCl
5) Insufficient basic understanding of the mechanisms of microbial technologies
Reservoir Characterization
1) The complexity of the rock and fluid distributions even in the "simplest
"reservoirs
2) The inadequate amount of detailed information from even the most ambitiously
sampled reservoir
3) Scaling of properties from core or smaller scale to interwell scale
4) Difficulties in interpreting seismic data in terms of rock and fluid properties
FO
2/24/2013 EOR Spring 2006 129
Thermal EOR
1) Lower crude oil prices due to gravity, sulfur and heavy metal
content
2) Large front end investments and delayed responses
3) Absence of cost-effective technology to upgrade low-quality, low-
gravity crude into salable products
4) Absence of cost effective technology that permits the use of low-
grade fuel such as coal, petroleum coke, high sulfur crude oil and
brackish water to generate steam without violating the environmental
regulations.
2/24/2013 EOR Spring 2006 130
CLASSIFICATION OF EOR CONSTRAINTS
CLASSIFICATION EXPLANATION
Chemical Loss Loss of injected fluid due to chemical
mechanical, or microbial degradation;
chemical loss due to adsorption, ion
exchange, or entrapment.
Downhole Completion Completion techniques; equipment;
production problems unrelated to
corrosion, scale, or artificial lift.
Facility Design Surface injection or production facilities.
Gravity Segregation Gravity override in Steam; potential may
exist for override in Situ or gas injection
projects.
2/24/2013 EOR Spring 2006 131
Injectivity Process specific to gas injection projects.
Low polymer injectivity in chemical
Projects was considered inherent to the
polymer process.
Injectivity Process specific to gas injection
projects.Low polymer injectivity in
chemical projects was considered
inherent to the polymer process.
Injection Control Formation pressure parting; injected fluid
flow out of Intended zone;inadequate
monitoring of injection.
2/24/2013 EOR Spring 2006 132
Injectant Quality Steam quality at sand face; injection well
plugging related to poor mixing (polymer)
or injection system contaminants (rust,
lubricants).
Mobility Control Gas channeling related to mobility rather
than heterogeneity; breakdown of polymer
bank due to bacterial degradation.
Operations Problems with oil treating, corrosion, scale,
artificial lift,compression, formation plugging
unrelated to injectant quality
Reservoir Conditions Refers to reservoir fluid conditions such as
oil saturation,thickness of oil column,
reservoir drive mechanism, etc. As
defined, reservoir conditions are a subset of
reservoir description
2/24/2013 EOR Spring 2006 133
Reservoir Description Refers to rock related description such
as depositional environment, rock
composition, faulting, heterogeneity,
continuity, etc
Reservoir Heterogeneity Areal or vertical permeability variations,
faults, directional flow trends,depositional
environments, etc
Process Design Inadequate or incomplete investigation
of different areas known to be important
in the EOR processes
2/24/2013 EOR Spring 2006 134
Limitations
• Depth
• Oil Viscosity
• Permeability
2/24/2013 EOR Spring 2006 135
EOR Method 0
Hydrocarbon-Miscible
Nitrogen,Flue Gas
CO2 flooding
Sufactant/polymer
Polymer
Alkaline
Fire Flood
SteamDrive
Prefered Zone
2000 4000 6000
Normal range (possible)
Deep enough for required pressure
Deep enough for required pressure
Very Good Deep enough for required pressure
Very Good Deep enough for required pressure
8000 10000
High cost
Limited by temprature
Very Good
Limited by temprature
Depth Limitation for Enhanced Oil Recovery Methods
This table illustrates the influence of reservoir depth on the technical feasibility
of various enhanced oil recovery methods.
Depth limitations for EOR methods.
Depth(ft)
2/24/2013 EOR Spring 2006 136
Preferred Oil Viscosity Ranges for Enhanced Oil Recovery Methods
This table illustrates the influence of oil viscosity on the technical feasibility of various enhanced oil
recovery methods.
Oil viscosity incidence for different EOR methods.
Oil Viscosity –Centipoise at Reservoir Conditions
2/24/2013 EOR Spring 2006 137
Permeability Guides for Enhanced Oil Recovery Methods
This table illustrates the influence of rock permeability on the technical feasibility of
various enhanced oil recovery methods.
EOR Method 0.1
Hydrocarbon-Miscible
Nitrogen,Flue Gas
CO2 flooding
Sufactant/polymer
Polymer
Alkaline
Fire Flood
100001 10 100 1000
Possible Preferred Zone
Not Critical If Uniform
Not Critical If Uniform
High Enough For Good Injection Rates
Preferred Zone
High cost Preferred Zone
Preferred Zone
Permeability (millidarcy)
Reservoir Permeability for different EOR methods.
2/24/2013 EOR Spring 2006 138
Kind of processes to be applied Candidate IOR Processes Under Various Reservoir Conditions
0
2000
4000
6000
8000
10000
12000
1 10 100 1000 10000 100000
Oil Viscosity (cp) Re
servoi
r Dept
h (ft)
Steam Injection
Pattern Water Injection Chemical Flooding Miscible
CO2 or HC Gas Injection
Miscible Nitrogen Injection
Immiscible Gas Injection
Polymer Injection
2/24/2013 EOR Spring 2006 139
Summery of Screening for
Enhanced Oil Recover Methods
2/24/2013 EOR Spring 2006 140
2/24/2013 EOR Spring 2006 141
Environmental and Economic Aspects of EOR Processes
Learning Objective
Examine the relationships among oil and gas prices,EOR production
and environmental considerations in some EOR operations.
Challenges
•Tougher environmental restrains,
•Uncertainty in the prediction of oil/gas prices,
•Technological difficulties,
•Reservoir description and characterization.
2/24/2013 EOR Spring 2006 142
Facts
•The number of new EOR processes will go down as the oil price goes down
• EOR environmental record has been good.Most of EOR injection are not very toxic.
• Cogeneration of steam and electricity improves the economics.
• Gas fried boilers reduce emissions and improve the efficiency.
1982 1988 1990
Steam 86 95 96
Combustion 65 78 88
Hot Water ____________ 89 78
CO2 21 66 81
Hydrocarbon 50 100 100
Nitrogen 100 100 100
Flue Gas 100 100 100
Polymer 72 92 86
Micellar/Polymer 0 0 0
Alkaline 40 100 Successful
Surfactant ___________ _________ 100(1 project)
MethodPercentage reported as profitable in
Profitability of EOR projects in USA.
2/24/2013 EOR Spring 2006 143
0 10 20 30 40
1
3
5
7
9
11
Air
Hot Water
Water
Surfactant Slugs
Liquid Hydrocarbon
Alkaline Chemicals
Methane
CO2
Polymers
N2 and Flue Gas
Steam
Estimated cost of a barrel of EOR injectant at reservoir conditions.The range of costs (shown by the
lighter crosshatching)can result from different prices of concentrations of the materials used for the
injection fluid.
Cost,$’s/barrel of injected fluid(2000psi)
2/24/2013 EOR Spring 2006 144
Planning Successful EOR Projects
• Identifying the appropriate EOR Process
• Characterizing the reservoir
• Determining the engineering design
parameters
• Conducting pilots or field tests as needed
• Finishing with a plan to manage the project to
meet or exceed expectations
2/24/2013 EOR Spring 2006 145
Planning Successful EOR Projects
2/24/2013 EOR Spring 2006 146
Figures
2/24/2013 EOR Spring 2006 147 Back
CO2 Gas Flooding
2/24/2013 EOR Spring 2006 148
Back
2/24/2013 EOR Spring 2006 149
Back Figure 3: Cyclic Carbon Dioxide Stimulation
2/24/2013 EOR Spring 2006 150
Back
2/24/2013 EOR Spring 2006 151
Back
2/24/2013 EOR Spring 2006 152 Back
2/24/2013 EOR Spring 2006 153
Back Figure7: Microbial Polymer Flooding
2/24/2013 EOR Spring 2006 154
Back
2/24/2013 EOR Spring 2006 155
Polymer Flooding
Back
2/24/2013 EOR Spring 2006 156 Back
2/24/2013 EOR Spring 2006 157
Figure12: Vertical Miscible Flood
2/24/2013 EOR Spring 2006 158 Back
2/24/2013 EOR Spring 2006 159
Back Water injection into the aquifer
2/24/2013 EOR Spring 2006 160 Back
Gas injection into the gas cap
2/24/2013 EOR Spring 2006 161 Back
2/24/2013 EOR Spring 2006 162 Back
Figure.17 Gas injection into the gas cap
2/24/2013 EOR Spring 2006 163 Back
Figure 3: Distributed water injection in a large field
2/24/2013 EOR Spring 2006 164
Back
Figure19: Gas injection into the gas cap
2/24/2013 EOR Spring 2006 165
Water injection into the aquifer
Injection well
Production Wells
Injection well
Back Figure20: Water injection into the aquifer
2/24/2013 EOR Spring 2006 166 Back
Gas injection into the gas cap
2/24/2013 EOR Spring 2006 167
Miscible flooding
Back
2/24/2013 EOR Spring 2006 169
Temperature and Saturations:
Dry Forward Combustion
800 600 400 200 0
Tem
pera
ture
(C)
Direction of Frontal Advance
100 80 60 40 20 0 S
atu
ration (
%)
Back
2/24/2013 EOR Spring 2006 170
Temperature and Saturations:
Normal Wet Combustion
800 600 400 200 0
Tem
pera
ture
(C)
100 80 60 40 20 0
Satu
ration (
%)
Back
2/24/2013 EOR Spring 2006 171 Back
2/24/2013 EOR Spring 2006 172
Thermal (Steam flooding)
Back
2/24/2013 EOR Spring 2006 174
Water flooding
2/24/2013 EOR Spring 2006 176
SAGD
Back
2/24/2013 EOR Spring 2006 181
Nitrogen/Flue Gas Flooding
Back
