Oil Recovery Methods

1

Explain and distinguish among Primary Recovery, Secondary Recovery, Tertiary Recovery, Enhanced Oil Recovery (EOR) and Improved Oil Recovery (IOR).

Textbooks Ahmed, Tarek H. “Reservoir Engineering Handbook.” ;

Gulf Professional Publishing, 2006 Chaps. 11 (Pgs. 733-752) & 14

Craft, B. C.; “Applied Petroleum Reservoir Engineering.”; Prentice-Hall, 1959 Chap. 9

Dake, L. P.; “Fundamentals of Reservoir Engineering.”; Elsevier Science & Technology, 1983 Chaps. 3 &10

Satter, Abdus; “Practical Enhanced Reservoir Engineering” Chaps. 8, 16 & 17

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Hydrocarbon Recovery Mechanisms

The recovery of hydrocarbons is basically a volume displacement process. When a volume of hydrocarbon is removed from the reservoir by production, it will be replaced by a volume of some fluid. Energy is expended in this process.

Hydrocarbon recovery mechanisms may be divided into two categories:

Primary Recovery Enhanced Recovery

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Primary Recovery

Primary recovery is “utilization of the natural

energy of the reservoir to cause the hydrocarbon to flow into the wellbore.”

There are many sources of primary recovery energy of which the 1st three are dominant:

1. Dissolved Gas Drive ( Solution Gas Drive )

2. Gas-Cap Drive

3. Water Drive

4. Rock and Liquid Expansion Drive

5. Gravity Drainage Drive

6. Combination Drive4

The Dissolved Gas Drive is such that when the

reservoir is produced so that gas is permitted to escape

from the hydrocarbon liquid in the reservoir, so that two-

phase flow (gas and liquid) occurs from the reservoir into

the wellbore, the expanding gas will force the oil ahead

of the gas into the wellbore.

Note: In order to maximize oil recovery, however, for

most reservoirs it is desirable to prevent dissolved gas

drive, at least until late in the productive life of the

reservoir.

Dissolved Gas Drive

5

Dissolved Gas Drive

6Solution gas drive reservoir. (After Clark, N. J., Elements of Petroleum Reservoirs, SPE, 1969.)

Gas-Cap Drive

If a Gas Cap exists above the oil zone, and wells are

drilled and perforated in the oil zone and the bottomhole

pressures are sufficiently reduced, the expanding gas cap

will force the oil into the wells as the gas interface

encroaches into the oil zone.

Note: In order for gas-cap drive to exist as a primary

recovery mechanism, however, the gas cap must exist

naturally. 7

Gas-Cap Drive

8Gas-cap-drive reservoir. (After Clark, N. J., Elements of Petroleum Reservoirs, SPE, 1969.)

Gas-Cap Drive

9

Production data for a gas-cap-drive reservoir. (After Clark, N. J. Elementsof Petroleum Reservoirs, SPE, 1969. Courtesy of API.)

Water Drive

Most hydrocarbon reservoirs will have a water zone

beneath the hydrocarbon. When water is tending to encroach into the oil zone it is referred to as a Water Drive.

If wells are drilled and perforated in the oil zone, when

the wellbore pressure is reduced, oil flow will be initiated into the well as water encroaches into the oil zone

forcing the oil towards the producing wells.

If this natural encroachment tendency is to exist,

natural energy must be present. 10

Water Drive

There are several possible sources of this natural energy for Water Drives:

1. Expansion of the water as a compressible fluid, as reservoir pressures are reduced. As the reservoir pressure is reduced, the expanding water will push the oil in front of it into the producing wells.

2. When the reservoir rock dips upward to the surface where it outcrops, if permeability continuity exists through this rock, as oil is produced from the reservoir, water flows down dip from the surface to replace the oil volume removed. Surface water replenished that water, maintaining a constant hydrostatic pressure on the reservoir fluids.

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Water Drive

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Reservoir having artesian water drive. (After Clark, N. J., Elements of Petroleum Reservoirs, SPE, 1969.)

Aquifer geometries

Water Drive

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Pressure-production history for a water-drive reservoir.

Production data for a water-drive reservoir. (After Clark, N. J., Elementsof Petroleum Reservoirs, SPE, 1969. Courtesy of API.)

Rock and Liquid Expansion Drive When an oil reservoir initially exists at a pressure higher than

its bubble-point pressure, the reservoir is called an undersaturated oil reservoir.

At pressures above the bubble-point pressure, crude oil, connate water, and rock are the only materials present.

As the reservoir pressure declines, the rock and fluids expand due to their individual compressibilities.

The reservoir rock compressibility is the result of two factors: Expansion of the individual rock grains Formation compaction

Both of the above two factors are the results of a decrease of fluid pressure within the pore spaces, and both tend to reduce the pore volume through the reduction of the porosity.

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Rock and Liquid Expansion Drive As the expansion of the fluids and reduction in the pore

volume occur with decreasing reservoir pressure, the crude oil and water will be forced out of the pore space to the wellbore.

Because liquids and rocks are only slightly compressible, the reservoir will experience a rapid pressure decline.

The oil reservoir under this driving mechanism is characterized by a constant gas-oil ratio that is equal to the gas solubility at the bubble point pressure.

This driving mechanism is considered the least efficient driving force and usually results in the recovery of only a small percentage of the total oil in place.

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The Gravity-Drainage-Drive Mechanism The fluids in petroleum reservoirs have all been subjected to the forces of gravity, as evidenced by the relative positions of the fluids, i.e., gas on top, oil underlying the gas, and water underlying oil.

Due to the long periods of time involved in the petroleum accumulation-and-migration process, it is generally assumed that the reservoir fluids are in equilibrium.

If the reservoir fluids are in equilibrium, then the gas-oil and oil-water contacts should be essentially horizontal.

Although it is difficult to determine precisely the reservoir fluid contacts, best available data indicate that, in most reservoirs, the fluid contacts actually are essentially horizontal.

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The Gravity-Drainage-Drive Mechanism

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Gravity-drainage reservoir. (After Cole, F., Reservoir Engineering Manual, Gulf Publishing Company, 1969.)

The Combination-Drive Mechanism The driving mechanism most commonly encountered is

one in which both water and free gas are available in some degree to displace the oil toward the producing wells.

Two combinations of driving forces can be present in combination drive reservoirs. These are: Solution gas drive and a weak water drive Solution gas drive with a small gas cap and a weak water drive.

Then, of course, gravity segregation can play an important role in any of the aforementioned drives.

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The Combination-Drive Mechanism

19Combination-drive reservoir. (After Clark, N. J., Elements of Petroleum Reservoirs, SPE, 1969.)

Enhanced Oil Recovery

Enhanced Oil Recovery [EOR] occurs when energy is injected into the reservoir from external sources.

There are many mechanics of EOR are available

which are grouped into two categories: Secondary Recovery Tertiary Recovery

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Secondary Recovery

Secondary Recovery is a broad term encompassing any method of extracting oil from a reservoir after a well or field has exhausted its primary production. 

There are two common techniques of

Secondary Recovery:

Water Flooding

Gas Drive [Gas Flood] or [Gas Cap Injection]

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Water Flooding

In a Water Flood, water is injected down injection wells

into the oil zone. Ideally, this creates a vertical flood front, pushing the oil in front of the water toward the producing wells.

In a water flood, the water injection wells are placed

relative to the oil producing wells in some predetermined

pattern based on reservoir characteristics and production

history.

A common pattern for water flooding for large reservoirs

which arc basically horizontal reservoirs is the five spot

pattern. This five spot pattern is repeated over the

reservoir.

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Waterflooding

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Waterflooding – 5 spot pattern

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Gas Drive [Gas-Cap Injection]

Gas –Cap Injection is a secondary recovery technique

where gas is injected into the gas cap above the oil zone,

to pressurize the gas cap.

In reservoirs where reservoir fluid pressure is higher than

the bubble point pressure, a gas cap may be created by

gas injection so that the expending gas cap with further

gas injection will displace the oil into the producing wells.

Gas Cap Drive or Gas Cap Drive Enhancement is

often used as a reservoir pressure maintenance

technique.25

Tertiary Oil Recovery

Tertiary Oil Recovery is a method of oil recovery in

which the oil is heated by burning it underground, adding

steam, or adding a detergent to scrub it out. Typically

recovers only an additional 10% of the oil in the well after

primary and secondary recovery.

Current Tertiary Oil Recovery or EOR processes may be divided into three categories:

Thermal Miscible Chemical

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Thermal Oil Recovery Thermal Recovery techniques are generally employed

when the hydrocarbons are too viscous to flow.

Viscosity is a measure of a liquid’s ability to flow, varies widely among crude oils. High viscosity makes oil difficult to recover with primary or secondary production methods.

The viscosity of most oils dramatically decreases as

temperature increases, and the purpose of all thermal oil-recovery processes is therefore to heat the oil to make it flow or make it easier to drive with injected fluids. An injected fluid may be steam or hot water (steam injection), or air (combustion processes).

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Three common Thermal Oil Recovery Techniques are:

Steam Cycle

Steam Drive [Steam Flood]

Fireflood [Insitu Combustion]

Note: Hydrocarbons produced by thermal

techniques is normally hydrocarbons which could

not otherwise have been recovered.

Thermal Oil Recovery

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In the steam cycle, steam is injected down the injection well into the

reservoir, usually for several weeks.

3 stages: Injection, Soaking (not > a few days) and Production (out of

the same well). As oil cools, prod’n will dec. 1st by natural flow and then

by artificial lift. Steps may be repeated again.

As the steam flows into the reservoir, it will condense and give up its

heat of vaporization, releasing a significant amount of energy, raising the

temperature of the reservoir, and lowering the viscosity of the

hydrocarbons in place, allowing the oil to be produced into the well and

back to the surface.

Steam Cycle (Huff and Puff Method)

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Steam Cycle (Huff and Puff Method)

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Steam Drive [Steam Flood] is a continuous injection process.

Steam is injected into the reservoir under pressure.

As it moves into the reservoir, the steam condenses, releasing its

heat of vaporization, thereby raising the temperature of the

reservoir and reducing the viscosity of the hydrocarbons.

This permits flow to occur as the steam front, under pressure,

drives the less viscous hydrocarbons into producing wells.

Steam Drive [Steam Flood]

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Steam Drive [Steam Flood]

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Steam Drive [Steam Flood]

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Fireflood [Insitu Combustion] is sometimes referred to as

“burning in place”.

The process involves an oxygen source which is injected down

the injection well into the reservoir, and the resultant

hydrocarbon-oxygen combination is ignited by a spark or some

ignition source, basically “setting the reservoir on fire”.

Fireflood [Insitu Combustion]

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As a result, the temperature of the reservoir and therefore of the

remaining hydrocarbons ahead of the fire front will increase,

resulting in lower viscosity.

The encroaching gases under pressure resulting from the

combustion will force the less viscous hydrocarbons in front of

the flame front, toward the producing well.

Fireflood [Insitu Combustion]

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Fireflood [Insitu Combustion]

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Miscible Processes The word “miscible” means “mixing” .

Miscible Processes are those in which fluids are

injected into the reservoir which will mix with the

hydrocarbons, forming a single oil-like liquid that can flow

through the reservoir more easily than the original crude.

The miscible fluid is recirculated through the injection

well, again sweeping or flushing the reservoir. This is

intended for each cycle the miscible fluid will mix with

additional hydrocarbon and carry it into the producing

well. 37

A variety of fluids are used for Miscible Processes including:

Alcohols Carbon Dioxide Petroleum Hydrocarbons:

Propane Propane-Butane Mixtures

Petroleum Gases rich in: Ethane Propane Butane Pentane

Miscible Processes

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CO2 Injection – Miscible Process

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Chemical Process

Three Enhanced Oil Recovery (EOR) processes involve the use of chemicals:

Surfactant/Polymer Flooding

Polymer Flooding

Alkaline Flooding

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Surfactant [or Polymer] Flooding Surfactant/Polymer Flooding is also known as

“Microemulsion Flooding” or “Micellar Flooding” .

Surfactants are wetting agents that lower the surface

tension of a liquid, allowing easier spreading, and lower

the interfacial tension between two liquids.

Residual oil saturation is reduced and the volumetric

sweep efficiency is increased.

Note: In the reservoir, surfactants are used to change

the wettability of the formation rock if necessary and to

reduce the interfacial tension.

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Surfactant/polymer flooding is a process in which

detergent-like materials are injected as a slug of fluid to

modify the chemical interaction of oil with its surroundings.

These processes emulsify or otherwise dissolve or partly

dissolve the oil within the formation. To preserve the integrity

of the slug as it moves through the reservoir, it is pushed by

water to which a polymer has been added.

Note: If the Interfacial Tension can be reduced between the oil and

the driving fluid, then the hydrocarbon resistance to flow is reduced.

Surfactant [or Polymer] Flooding

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Polymer Flooding

Polymer Flooding is a chemically augmented

waterflood in which small concentrations of

chemicals, such as polyacrylamides or

polysaccharides, are added to injected water to

increase the effectiveness of the water in displacing

oil.

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Polymer flooding

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Alkaline Flooding

Strongly alkaline substances which are used in Alkaline Flooding includes:

Water solutions of certain chemicals such as: Sodium Hydroxide Sodium Silicate Sodium Carbonate

Note: These solutions will react with constituents

present in some crude oils or present at the

rock/crude oil interface to form detergent-like

materials which reduce the ability of the formation

to retain the oil.46

EOR Flooding Methods

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EOR Injection Methods

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Recovery Efficiencies

PRIMARY RECOVERY EFFICIENCIES

Oil (Percent of Original Oil- in- Place)

Dissolved Gas Drive 5% to 30%

Gas-Cap Drive 20% to 40%

Water Drive 35% to 75%

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

Gas Expansion and Water Drive 90% +

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ENHANCED RECOVERY EFFICIENCIES

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

Water flood (Secondary Recovery) 30% to

40%

CO2 Miscible Flood (Tertiary Recovery) 5% to

10%

Steam Drive (Heavy Oil) 50% to

80%

Recovery Efficiencies

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SUMMARY AND CASE STUDIES

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Recovery Mechanisms

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EOR Concepts

Ideal goal of EOR is to mobilize the “residual” oil throughout the entire reservoir by enhancing:

1. Microscopic oil displacement – 1. Oil displacement efficiency can be by oil viscosity using

thermal floods or by capillary forces or interfacial tension with chemical floods.

2. Oil displacement efficiency can be by the Mobility Ratio or

the Capillary No. or both.

2. Volumetric sweep efficiencies – volumetric sweep efficiency can be by the drive water viscosity using polymer compounds.

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EOR Concepts: Overall Recovery

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dv EEE Where:

E = Overall recovery efficiency of any fluid displacement process, fractionEv = Volumetric displacement, fractionEd = Microscopic displacement efficiency, fractionEs = Areal sweep efficiency, fractionEi = Vertical Sweep efficiency, fraction

Microscopic displacement efficiency, Ed is a measure of how well the displacing fluid mobilizes the residual oil once the fluid has contacted the oil.Ed is affected by: interfacial and surface tension forces, wettability, capillary pressure, and relative permeability.

Es x Ei

EOR Concepts: Mobility Ratio, M The mobility of the displacing fluid over the

displaced fluid.

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oro

wrw

K

KM

Where:krw = relative k to water, fractionkro = relative k to oilw = viscosity of water, cpo = viscosity of oil, cp

M can be made favourable by:Lowering the viscosity of the oil (thermal methods) or increasing the viscosity of the displacing fluid (water) (addition of polymer in water).

EOR Concepts: Mobility Ratio, M M=1: The mobility ahead of and behind the front are

equal. The water displaces the oil efficiently and the flood front tends to advance fairly uniformly and effectively sweeps the oil from most of the volume of the reservoir under flood

M<1: Water displaces the oil efficiently. Favorable mobility ratio. Results in an efficient waterflood. Low o

M>1: Water displaces the oil less efficiently. Fingering and instabilities. Unfavorable mobility ratio. Results in an inefficient waterflood. High o

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EOR Concepts: Capillary No.

As the capillary no. in an EOR process is increased by lowering the interfacial tension (as it approaches zero) and oil viscosity, the residual oil saturation decreases.

Nca typically vary from 10-8 to 10-2

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L

pkCN

ow

wca

Where:Nca = capillary number, dimensionless C = a coefficient, depending on the units to be usedkw = effective permeability to water, fractionf = porosity of reservoir, fractionow = interfacial tension between oil and water, dynes/cm

Steam Flooding

Steam flooding recovers crude by: Heating the crude and reducing the viscosity Steam distillation Solvent/ extraction effects Supplying pressure to drive oil to the producing

well

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Limitations of Steam Flooding Oil saturations must be quite high, and the pay zone should be >

20ft thick to min. heat losses to adjacent formations. Lighter, less viscous crude oils can be steam flooded, but normally it

will not be acceptable if the reservoir will respond to an ordinary waterflood operation.

Steam flooding is primarily applicable to viscous oils in massive, high permeability sandstones or unconsolidated sands.

Because of excessive heat losses in the wellbore, steam-flooded reservoirs should be as shallow as possible, as long as pressure for sufficient injection rates can be maintained.

Steam flooding is not normally used in carbonate reservoirs. Both bottom water and gas caps are undesirable.

Since about 1/3 of the additional oil recovered is consumed in the generation of the required steam, the cost per incremental barrel of oil is high.

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In-Situ Combustion

Application of heat, which is transferred downstream by conduction and convection, thus lowering the viscosity of the crude.

Products of steam distillation and thermal cracking, which are carried forward to mix with and upgrade the crude.

Burning coke that is produced from the heavy ends of the crude oil.

Pressure supplied to the reservoir by the injected air.

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In-Situ Combustion - Limitations If sufficient coke is not deposited from the oil being

burned, the combustion process will not be sustained. If excessive coke is deposited, the rate of advance of the

combustion zone will be slow, and the quantity of air required to sustain combustion will be high.

Oil saturation and porosity must be high to minimize heat loss to the rock.

The process tends to sweep through upper part of reservoir, and thus sweep efficiency is poor in thick formations.

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In-Situ Combustion - Problems The mobility ratio can be adverse. The process is complex, difficult to control, and

requires large capital investments. Produced flue gases can present environmental

problems. Operational problems can occur:

Severe corrosion caused by low pH hot water Serious oil-water emulsions Increased sand production Deposition of carbon or wax Pipe failures in producing wells as a result of very high

temps.

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Polymer Flooding

Increasing viscosity of water. Decreasing mobility of water. Contacting a larger vol. of reservoir. Reducing the injected fluid mobility to

improve areal and vertical sweep efficiencies.

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Polymer Flooding - Limitations If oil viscosities are high, a higher polymer concentration

is needed to achieve the desired mobility control. Results are normally better if the polymer flood is started

before the water-oil ratio becomes excessively high. Clays increase polymer adsorption. Some heterogeneities are acceptable, but for the

conventional polymer flooding, reservoirs with extensive fractures should be avoided. If fractures are present, the cross-linked or gelled polymer techniques may be applicable.

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Polymer Flooding - Problems

The injectivity is lower than with water alone, and can adversely affect the oil production rate in the early stages of the polymer flood.

Acrylamide-type polymers lose viscosity die to shear degradation or increases in salinity and divalent ions.

Xanthan gum polymers cost more, are subject to microbial degradation, and have a greater potential for wellbore plugging.

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Surfactant/polymer flooding

Lowering the interfacial tension between the oil and the water.

Solubilization of oil. Emulsification of oil and water. Mobility enhancement.

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Surfactant/polymer flooding - Limitations

An areal sweep of >50% on a waterflooding is desired. A relatively homogeneous formation is preferred. High amounts of anhydride, gypsum, or clays are

undesirable. Available systems provide optimum behaviour over a

very narrow set of conditions. With commercially available surfactants, formation

chlorides should be <20,000 ppm, and divalent ions (Ca2+ and Mg2+) < 500ppm.

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Surfactant/polymer flooding – Problems Complexity and expense of the system. Possibility of chromatographic separation of

chemicals. High adsorption of surfactant. Interaction between surfactant and polymer. Degradation of chemicals at high temps.

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Alkaline Flooding – Limitations/Problems Sandstone reservoirs are preferred for this

process. In carbonate formations, alkali is consumed

by clays, minerals or gypsum. Consumption is high at elevated

temperatures. Scale formation in producing wells.

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HC Miscible Flooding

Generating miscibility (in condensing and vaporizing gas drive).

Increasing the oil volume (swelling). Decreasing the viscosity of the oil.

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HC Miscible Flooding - Limitations The minimum depth is set by the pressure

needed to maintain the generated miscibility. Pressure ranges from 1200 psi for the LPG process to 3000-5000 psi for the high pressure gas drive, depending on the oil composition.

A steeply dipping formation is very desirable to permit some gravity stabilization of the displacement that normally has an unfavourable mobility ratio.

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HC Miscible Flooding - Problems Viscous fingering results in poor vertical and

horizontal sweep efficiency. Large quantities of expensive products are

required. The solvent may be trapped and not

recovered.

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CO2 Flooding

Generation of miscibility between in-situ oil and injected gas.

Swelling the crude oil. Lowering the viscosity of the oil. Lowering the interfacial tension between the

oil and the CO2-oil phase in the near miscible-regions.

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CO2 Flooding - Limitations

The very low viscosity of the CO2 results in poor mobility control.

The process can be limited by availability of CO2.

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CO2 Flooding - Problems

Resultant problems from early breakthrough of CO2.

Corrosion in the producing wells. The necessity of separating CO2 from

saleable hydrocarbons. Re-pressurizing of CO2 for recycling.

A high requirement of CO2 per incremental barrel produced.

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WATERFLOODING

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Factors to Consider in Waterflooding In determining the suitability of a candidate

reservoir for waterflooding, the following reservoir characteristics must be considered: Reservoir geometry Fluid properties Reservoir depth Lithology and rock properties Fluid saturations Reservoir uniformity and pay continuity Primary reservoir driving mechanisms

Reasons for the success of waterflooding Water is:

An efficient agent for displacing oil of light to medium gravity

Easy to inject into oil-bearing formations Available Inexpensive Involves lower capital investment and operating

costs, leading to favorable economics

Flooding patterns

Irregular five-spot pattern layout

Buckley-Leverett Fractional Flow Theory Provides an expression for the fraction of the

individual phases i.e. oil and water, during displacement.

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ow

ww qq

qf

Where:fw = fractional volume of water or water cut, bbl/bblqw = flow rate of water, bbl/dqo = flow rate of oil, bbl/d

wrworoww kkSf

/1

1

Fractional Flow Theory

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Displacement Efficiency at Breakthrough, EDBT

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wi

wiwbtDBT S

SSE

1

= displacement efficiency at breakthrough, EDBT

= Average water saturation of water behind the floodfront Swi = Initial water saturation

wbtS

DBTE

Fractional Flow Graph

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Inlet

Ahead of front

Important Points from the Fractional Flow Curve

1. There are 4 key values of water saturation shown in the figure:

1. The water saturation at the inlet or the maximum achievable water saturation, Swm (usually Swm = 1- Sor)

2. The average water saturation behind the flood front,

3. The water saturation at the flood front, Swf

4. The water saturation ahead of the front, Swc

2. Three key values of fractional flow to water can also be read from the figure:

1. The fractional flow of water at the inlet; i.e. fwm = 1

2. The fractional flow of water at the flood front; i.e. fwf

3. The fractional flow of water ahead of the front; i.e. fwf = 0

wbtS

1

below:

2

Example 3 The following graph was

obtained from an EOR method done on a field in California.

Discuss in detail, the different types of this EOR method that can be used to achieve this outcome, explaining the aims hoped to accomplish.

Discuss the advantages and disadvantages of this method, if any.

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Example 4 The graph shows the variation

of oil production with oil-water viscosity ratio for 5-spot waterflood.

Explain the graph, while discussing how the waterflood project was implemented and what factors would have been considered in determination the feasibility of the project.

What would be the reasons for success for any waterflood project, as well as what drawbacks that can occur?

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