EOR Overviwe

7/27/2019 EOR Overviwe

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2. Enhanced Oil Recovery Overview

2.1 Introduction:

The life of an oil well goes through three distinct phases where various

techniques are employed to maintain crude oil production at maximum levels.

The primary importance of these techniques is to force oil into the wellhead

where it can be pumped to the surface. Techniques employed at the third phase,

commonly known as Enhanced Oil Recovery (EOR), can substantially improve

extraction efficiency; (1) figure (1.1) summaries oil recovery mechanisms through

the life of well and/or reservoir.

1.2 Factors Common to All Enhanced Oil Recovery Methods:

The efficiency of an enhanced recovery method depends on:

a- The reservoir characteristics: Average depth.


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Structure, in particular the dip of the bed. Degree of homogeneity. Petrophysical properties (permeability, capillary pressure,

wettability).

b- The nature of the displacing and displaced fluids: Fluid viscosity.

c- The arrangement of production and injection well: Injection to production wells location. (6)

1.1

Enhanced Oil Recovery (EOR) Methods:

Enhanced oil recovery processes include all methods that use external sources of

energy or materials to recover oil that cannot be produced economically by

conventional means. Enhanced oil recovery processes include the following:

Miscible methods: hydrocarbon gas, carbon dioxide and nitrogen. Inaddition, flue gas and partial miscible/immiscible gas flood may be also

considered.

Thermal methods: steam stimulation, steam flooding and in-situcombustion.

Chemical methods: surfactants, polymer, micellar-polymer and caustic(alkaline).

Other methods: microbial ... etcEnhanced oil recovery processes are utilized to mobilize the residual oilthroughout the entire reservoir after primary and secondary recovery processes.

This can be achieved by enhancing microscopic oil displacement and volumetric

sweep efficiencies. Oil displacement efficiency can be increased by decreasing

oil viscosity using thermal floods or by reducing capillary forces or interfacial

tension with chemical floods. Volumetric sweep efficiency can be improved by

increasing the drive water viscosity using a polymer flood.


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Many reservoirs contain viscous crude oil. Attempts to produce such oils with

water flooding will yield very poor recoveries. Application of heat is often the

only feasible solution to recovery from such reservoirs. Thermal methods,

particularly steam floods, are effectively used for heavy viscous oils (10-20

API). Steam floods are used commercially in Californias heavy oil reservoirs.

Chemical flood processes, which are applicable to lighter oils, require conditions

favorable to water injection, as they are modifications of waterflooding. Even

though they showed promise earlier as a viable enhanced oil recovery process,

chemical floods were not really successful. They are no longer utilized.

Among the miscible floods, CO2 miscible floods applicable to lighter oils have

been commercially successful. They are utilized widely in West Texas.

Enhanced oil recovery processes require heavy financial investments initially and

have high operating costs. Response and returns of capital investments come

several years down the road. Statistics show that active U.S. enhanced oil

recovery projects and productions are declining.

Offshore enhanced oil recovery operations require consideration of certain

issues. These include detailed reservoir description, cost and space requirements

for injected material, unique technical risks, and high capital expenditure.

Screening of enhanced oil recovery processes for potential application in the

field is a necessary step. The screening criteria are based upon rock and fluid

properties of the reservoirs. There is no cure-all process for recovering residual

oil after primary and secondary recovery processes. After screening, the

subsequent steps would be further theoretical and experimental evaluation of the

candidate processes, and possibly a pilot test in the field. Also, pilot test

evaluation/scale-up of forecast and commercial venture are necessary.

1.2 Enhanced Oil Recovery Screening Criteria:All of the processes described in this search have limitations in application.

These limitations have been derived partly from theory, partly from laboratory

experiments, and partly from field experiences. Prospect screening consists of thefollowing:


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1. Evaluating available information about the reservoir, oil, rock, water,geology, and previous performance.

2. Supplementing available information with certain brief laboratoryscreening tests.

3. Selecting those processes that are potentially applicable and eliminatingthose that definitely are not.

A candidate reservoir for one or more enhanced oil recovery processes should

not be discarded because it does not satisfy one or two criteria. Each prospect

should be evaluated on its own merits by analyzing the many reservoir

operational and economic variables.

Screening is the first step in the enhanced oil recovery implementation sequence.

The next step would be a further evaluation of candidate processes if more than

one satisfies the screening criteria. Subsequent steps could include a pilot test

design, pilot test implementation, pilot test evaluation/scale-up forecast, and a

commercial venture.

Table (1.1): presents screening criteria based upon oil properties for application

of various enhanced oil recovery processes. The criteria include the gravity,

viscosity, and saturation of the oil.

Table (1.1): Screening Criteria for Enhanced Oil Recovery Methods Based on Oil

Properties


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ProcessGravity

(API)

Viscosity

(cp)Composition Oil Saturation

Water flooding > 25 < 30 N.C.>10% PV

mobile oil

Hydrocarbon > 35 < 10High % of

C2C7> 30% PV

Nitrogen and

Flue gas

> 24 Nitrogen

> 35 Flue gas< 10

High % of

C1C7> 30% PV

Carbon dioxide > 26 < 15High % of

C5C12> 20% PV

Surfactant/

Polymer> 25 < 30

Light to

intermediate

desired

> 30% PV

Polymer > 25 < 150 N.C.> 10% PV

mobile oil

Alkaline 1335 < 200Some organic

acids

Above

waterflood

residual

Combustion< 40

(1025)

normally

< 1,000Some asphaltic

components

> 40%50%

PV

Steam flooding < 25 < 20 N.C.> 40%50%

PV

Note: PV = Pore Volume; N.C. = Not Critical.

Steam flooding is primarily applicable to viscous oils in massive, high

permeability sandstones or unconsolidated sands. It is limited to shallow

formations due to heat losses from the wellbore. Heat is also lost to the adjacent

formations once steam contacts the oil-bearing formation. Hence, sufficiently

high steam injection rates are needed to compensate for heat losses.

The minimum miscibility pressure for effective CO2 flooding ranges widely. The

required pressure can be 1,200 psi for high gravity oil (more than 30 API) at

lower temperatures to more than 4,500 psi for heavy crudes at higher

temperatures. To satisfy this requirement, the reservoir has to be deep enough to


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achieve the minimum miscibility pressure. For an example, the minimum

miscibility pressure for West Texas CO2 floods is around 1,500 psi at depths of

more than 2,000 ft. On of the other hand, more than 4,500 ft deep reservoirs are

needed for effective NO, and high pressure hydrocarbon miscible floods.

Table (1.2): presents screening criteria based upon reservoir characteristics for

application of the various enhanced oil recovery processes. The criteria include

formation type, net thickness, average permeability, depth, and temperature.

Table (1.2): Screening Criteria for Enhanced Oil Recovery Methods Based on Reservoir

Characteristics.(3)

Process FormationType

Net Thick.(ft)

AveragePerm. (mD)

Depth(ft)

Temp.(F)

Waterflooding

Sandstone

or

carbonate

N.C. N.C. N.C. N.C.

Hydrocarbon

Sandstone

or

carbonate

Thin

unless

dipping

N.C. >2,000 () N.C.

Nitrogen and

Flue gas

Sandstone

or

carbonate

Thin

unless

dipping

N.C. > 4,500 N.C.

Carbon

dioxide

Sandstone

or

carbonate

Thin

unless

dipping

N.C. > 2,000 N.C.

Surfactant/

polymer

Sandstone

preferred> 10 > 20 < 8,000 < 175

Polymer

Sandstone

preferred;

carbonate

possible

N.C.> 10

(normally)< 9,000 < 200

AlkalineSandstone

preferredN.C. > 20 < 9,000 < 200

Combustion

Sand or

sandstone

with high

porosity

> 10 > 100 > 500> 150

preferred

Steam flooding

Sand or

sandstone

with highporosity

> 20 > 200 3005,000 N.C.


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Note: N.C. = Not Critical.

Thermal floods are primarily applicable to heavy viscous oils. Steam floods are

used for oil with gravity less than 25 API, viscosity more than 20 cp, and oil

saturation more than 40% PV. Higher viscosity with less than 100 cp may be

applicable for combustion floods.

Hydrocarbon, nitrogen, carbon dioxide, and surfactant floods are applicable to

higher oil gravities and lower oil saturations than those needed for steam floods.

Screening of those processes that are potentially applicable for enhanced oil

recovery processes is a necessary step, thus eliminating those that definitely are

not. A candidate reservoir for one or more enhanced oil recovery processes

should not be discarded because it does not satisfy one or two criteria. Each

prospect should be evaluated on its own merits by analyzing the many reservoir

operational and economic variables. (3)

1.3 Miscible Displacement Mechanism:To explain the different processes in miscible flooding, ternary diagrams are

widely used. In the following, ternary diagrams will be shown for the different

flooding conditions. Figure (1.3) summarizes the different processes.

Since the dilution path (I2-J3) in figure (1.3) does not pass through the two-phase

region or cross the critical tie line, it forms first contact miscible displacement.

The path (I1-J1), which entirely lies on the two-phase region, forms immiscible

displacement. When the initial and injected compositions are on the opposite side

of the critical tie line, the displacement is either a vaporizing gas drive (I2-J1) ora condensing gas drive (I1-J2).


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Figure (1.3): Conditions for Different Types of Oil Displacement by Solvents.(7)

1.3.1 First Contact Miscible Flooding:The most direct method to achieve miscible displacement is by injecting a

solvent that mixes with the oil completely, such that all mixtures are in single

phase. To reach the first-contact miscibility between solvent and oil, the pressure

must be over the cricondenbar since all solvent-oil mixtures above this pressure

are single phases. If she solvent, for instance a propane-butane mixture is liquid

at reservoir pressure and temperature, the saturation pressure for the mixture of

oil and solvent will vary between the bobble-point pressure for the oil and the

bobble-point pressure for the solvent. In this case the cricondenbar is higher than

the two bobble-point pressures. If the solvent is gas at reservoir pressure and

temperature, the phase behaviour is more complicated. In this case, the

cricondenbar may occur at mixtures intermediate between pure oil and pure

solvent.

If natural gas or CO2 is chosen as a solvent to sweep the reservoir, a miscible

slug must be created ahead of the injected gas in order to reach a miscible

displacement process. The slug may be of propane or liquefied petroleum gas,

and the slug must be completely miscible with the reservoir oil at its leading edge

and also completely miscible with the injected gas at its tailing edge. The volume

of the injected slug material must be sufficient to last for the entire sweep

process. The first contact flooding will not continue if the slug is bypassed. The

first contact minimum miscible pressure (FCMMP) is the lowest pressure atwhich the reservoir oil and injection gas are miscible in all rations.


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1.3.2 Multiple Contact Miscible Flooding:The degree of miscibility between a reservoir oil and injection gas is often

expressed in terms of the minimum miscibility pressure (MMP). The multiple

contact miscibility pressure (MCMMP or just MMP) is the lowest pressure at

which the oil and gas phases resulting from a multi-contact process, vaporizing

or condensing, between reservoir oil and an injection gas are miscible in all

rations.

Multiple contact miscible injection fluid is normally natural gas at high pressure,

enriched natural gas, flue gas, nitrogen or CO2. These fluids are not first-contact

miscible and forms two-phase regions when they mix directly with the reservoir

fluids. The miscibility is achieved by mass transfer of components witch results

from multiple and repeated contact between the oil and the injected fluid through

the reservoir. There are two main processes where dynamic miscible

displacement can be achieved. Those are the vaporizing and the condensing gas

drive.

The following descriptions explain the mechanisms for gas drives in general, but

the difference between CO2 and natural gas is that the dynamic miscibility with

CO2 does not require the presence of intermediate molecular weight

hydrocarbons in the reservoir fluid. The extraction of a broad range of

hydrocarbons from the reservoir oil often causes dynamic miscibility to occur at

attainable pressures, which are lower than the miscibility pressure for a dry

hydrocarbon gas.

Vaporizing Gas Drive:Vaporizing gas drive is a particular case of a multiple contact miscibility process.

It is based on vaporization of the intermediate components from the reservoir oil.

A miscible transition zone is created, and C2 to C6 (CO2can extract up to C30) is

extracted due to the high injection pressure. A vaporizing gas miscible process

can displace nearly all the oil in the area that has been contacted. However, the

fraction of the reservoir contacted may be low due to flow conditions andreservoir heterogeneities. The process requires high pressure at the oil-gas


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interface, and the reservoir oil must contain a high concentration of C2 to C6,

particularly if HC gas is used.

The pressure required for achieving dynamic miscibility with CO2 is usually

significantly lower than the pressure required for other gases as natural gas, flue

gas or nitrogen. By using CO2, also higher molecular weight hydrocarbons can

be extracted. The lower pressure and the extraction of higher hydrocarbon

fractions are a major advantage of the CO2 miscible process.

Figure (1.4): Multiple Contacts Vaporizing Gas Drive.(7)

Figure (1.4) shows a ternary diagram for this process. The displacement is not

first contact miscible because the dilution path passes through the two-phase

region. To explain the process in the figure, one has to image that there are a

series of mixed cells that represent the permeable medium in a one-dimensional

displacement. The first cell initially contains crude oil to which one adds an

amount of solvent so that the overall composition is given by the mixture. The

first mixture (the point on the tie line L1-G1 where it crosses the solventcrude

line) will split into two phases, gas G1 and liquid L1, determined by the

equilibrium lines. The gas G1 will have a much higher mobility than the liquid

L1, and moves into a second mixing CO2 injection for cell to form the next


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mixture. The liquid L1 remains behind to mix with more pure solvent. In the

second cell the mixture splits into G2 and L2 and so on. Behind the second cell

as it is shown in this figure the gas phase will no longer form two phases on

mixing with the crude. From this point all compositions in the displacement will

be a straight dilution path between the crude and a point tangent to the bimodal

curve. The displacement will be first contact miscible with a solvent composition

given by the point of tangency. Now the process has developed miscibility since

the solvent has been enriched in intermediate components to be miscible with the

crude. The vaporizing gas drive occurs at the front of the solvent slug. The

process is called a vaporizing gas drive since the intermediate components have

vaporized from the crude.

Condensing Gas Drive:When a rich gas is injected into oil, oil and gas are initially immiscible. Multiple

contacts condensing drive will occur when the reservoir oil in a particular cell

meets new portions of fresh solvents. A miscible bank forms through

condensation of the intermediate components from gas into oil. Then a process

similar to the vaporizing drive will be developed, and the oil behind the front

becomes progressively lighter. The successive oil compositions formed behind

the front will occupy a greater volume in the pores than the original oil because

of swelling. This will then lead to form a mobile oil bank behind the zone of gas

stripped of intermediate components. The process continues unless developed

miscibility conditions are met.

The process is shown schematically in figure (1.5) where the first mixing cell

splits into liquidL1 and gas G1. Gas G1 moves on to the next mixing cell and

liquid L1 mixes with fresh solvent to form the next mixture. Liquid L2 mixes

with fresh solvent, and so on. The mixing process will ultimately result in a

single-phase mixture. Since the gas phase has already passed through the first

cell, the miscibility

now develops at the rear of the solvent-crude mixing zone as a consequence of

the enrichment of the liquid phase from the intermediate components. The front

of the mixing zone is a region of immiscible flow owing to the continual

contacting to the gas phases G1, G2, and so on. Since the intermediate


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component condenses into the liquid phase, the process is called a condensing

gas drive.

Figure (1.5): Multiple Contacts Condensing Gas Drive. (7)

CO2 cannot form miscibility alone, but through a vaporizing drive were injected

CO2 vaporizes some of the light components in the oil. These are subsequentlyre-condensed at the displacement front creating an enriched zone with favorable

mobility characteristics, referred to as a combined vaporizing and condensing

drive.

Combined Vaporizing and Condensing Mechanism:Experimental observations and calculations with equation of state have shown

that miscible displacement by rich gas injection seems to be due to a combined

vaporizing and condensing mechanism. The main conclusions from those articles

are:

1. A combined vaporizing and condensing gas drive mechanism is more likely than

a pure condensing gas drive when rich gas is injected into reservoir oil.

2. A pseudo miscible zone develops quite similar to that in a condensing gas drive.

3. Some residual oil remains trapped behind the displacement as in a vaporizing gas

drive. (7)


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1.4 Miscible Methods:Miscible methods include hydrocarbon gas, carbon dioxide, and nitrogen. In

addition, flue gas and partial miscible/immiscible gas floods may be also

considered.

Miscible flooding involves injecting a gas or solvent that is miscible with the oil. As

a result, the interfacial tension between the two fluids (oil and solvent) is very low.

Very efficient microscopic displacement efficiency takes place.Figure (1.6): Miscible Method.

(2)

1.4.1 Hydrocarbon Miscible Flooding:Hydrocarbon flooding consists of injecting light hydrocarbon through the

reservoir to achieve miscible flooding as shown in figure (1.7).

Mechanisms:

Hydrocarbon miscible flooding recovers crude oil by: Generating miscibility (in the condensing and vaporizing gas drive). Increasing the oil volume (swelling).


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Decreasing the viscosity of the oil.

Figure (1.7): Hydrocarbon Miscible Flooding.(2)

Screening Parameters:

Crude Oil

Parameter value Unit

Gravity > 35 API

Composition C2C7 high%

Viscosity < 10 cp

Oil saturation > 30% PV

Reservoir:


Type of formation sandstone or carbonate

Net thickness thin unless dipping

Average permeability N.C

Depth > 2000 ft

Temperature N.C

Limitations:


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Minimum depth is set by the pressure needed to maintain the generatedmiscibility. The required pressure ranges from about 1,200 psi for the LPG

process to 3,0005,000 psi for the High Pressure Gas Drive, depending on the

oil.

A steeply dipping formation is very desirable - pen-nits gravity stabilization ofthe displacement that normally has an unfavorable mobility ratio.

Three Different Methods are used as Following:

High Pressure (Vaporizing) Gas Drive: in the high-pressure gas injectionprocess, a lean gas (low in the C2 through C8 hydrocarbon, i.e. intermediate) is

utilized. The injected gas is enriched within the reservoir by a transfer of

intermediate hydrocarbons from the oil to the gas. To accomplish this transfer, the

oil must contain sufficient quantities of hydrocarbons in the C2 through C6 rang,

and the reservoir pressure should generally be in excess of 2500 psi. If the

reservoir oil is low in intermediate hydrocarbons, it will be impossible for

evaporating-gas drive to develop a miscible front.

Advantages:

1. The lean gas process provides a displacement efficiency approaching 100%.2. Lean gas is less expensive than propane or enriched gas.3. The process can regenerate miscibility if lost.4.No slug sizing problems due to continuous injection occur.5. Gas can be cycled and re-injected.

Disadvantages:

1. The process has limited applicability because reservoir oil must be richin C2-C6 components.

2. It involves high injection pressures.3. Areal sweep efficiency and gravity segregation are poor.4. Cost of natural gas is high; substitute gases require higher injection

pressure.


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Enriched (Condensing) Gas Drive: an enriched gas drive system forms amiscible-solvent front by condensation of the intermediates from the injected

enriched gas. Under reservoir conditions, the intermediates condense to form the

solvent bank. The process is applicable in the general pressure range of 17003000

psi.

Advantages:

1. The enriched gas process displaces essentially all residual oil contacted.2. Miscibility can be regained if lost in the reservoir.3. This process is lower cost than the propane slug process.4. It develops miscibility at lower pressures than lean gas drive.5. Large slug sizes minimize slug design problems.

Disadvantages:

1. The process has poor sweep efficiency.

2. Gravity override occurs in thick formations.

3. Gas costs are high.

4. Viscous fingering leads to slug dissipation.

Liquid Petroleum Gas (LPG) Slug Drive: in miscible slug injection, aslug (or band) of LPG or propane is driven by dry gas or water through the

reservoir. This slug miscibility displaces the reservoir oil from the swept portions

of the reservoir. At pressures above 1100 psi, the LPG is also miscible with the

driving gas. The quantity of LPG is required to maintain miscible conditions are an

important factor in the economics of miscible flooding. In the case of low solvent

(LPG) content, miscibility is lost when the (LPG) deteriorates. At that point, the

displacement will become immiscible rather than miscible, and recovery will drop

accordingly.

Advantages:

1. All contacted oil is totally displaced.

2. Low pressures are needed for miscibility.

3. The process is applicable in a wide range of reservoirs.

4. It can be used as a secondary or tertiary process.


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Disadvantages:

1. Process involves poor sweep efficiency, is best applied in steeply dipping

beds.

2. Sizing of slug is difficult due to dispersion.

3. Slug materials are expensive.

1.4.2 Carbon Dioxide Flooding:Carbon dioxide CO2 is a very powerful vaporizer of hydrocarbons. Hydrocarbon

fraction as heavy as those in the gasoline and gas-oil range are vaporized into the

injected CO2, this enables CO2 to develop miscibility even through there may be

very little of the ethane through hexane components in the crude oil. The

mechanism by which CO2 miscibly displaces oil is through a multiple contact

extraction of hydrocarbons in the C2-C30 range. Suitable oils are usually in the

25-45 API range and are present in reservoirs deep enough so that displacement

can take place above the minimum miscibility pressure.

Miscible displacement by CO2 is similar to that in a vaporizing gas drive. The

only difference is that a wider range of components, C2 to C30, is extracted. As aresult, the CO2 flood process is applicable to a wider range of reservoirs at lower

miscibility pressures than those for the vaporizing gas drive as shown in figure

(1.8)


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Figure (1.8): Carbon Dioxide Flooding. (2)

Mechanisms:

CO2 recovers crude oil by:

Generation of miscibi1ity. 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.


Crude Oil:


Gravity 26 API

Viscosity < 15 CP

Composition High % of C5C12

Oil saturation > 20% PV

.

Reservoir:



Net thickness thin unless dipping

Average permeability N.C

Depth > 2,000 Ft

Temperature N.C

Limitations:

Very low Viscosity of CO2 results in poor mobility control. Availability of CO2.


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Advantages

1. Miscibility can be attained at low pressures.2. Displacement efficiency is high in miscible cases.3. This process aids recovery by solution gas drive.4. It is useful ova a wider range of crude oils than hydrocarbon injection

methods.

5. Miscibility can be regenerated if lost.Disadvantages:

1. CO2 is expensive to transport and not always available.2. Poor sweep and gravity segregation can result under certain

conditions.

3. Corrosion is increased.4. Special handling and recycling of produced gas is necessary.

1.4.3 Nitrogen Flooding: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 is

also considered for use as chase gases in hydrocarbon- miscible and CO2 floods.

Nitrogen flooding vaporizes the lighter components of the crude oil and

generates miscibility if the pressure is high enough. In addition it provides a gas

drive where a significant portion of the reservoir volume is filled with low-cost

gases.

Miscibility can only be achieved with light oils at high pressures; therefore, deep

reservoirs are needed.

A steeply dipping reservoir is desired to permit gravity stabilization of the

displacement, which has a very unfavorable mobility ratio.


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Mechanisms:

Nitrogen and flue gas flooding recover oil by accomplishing the following:

Vaporizing the lighter components of the crude oil and generatingmiscibility if the pressure is high enough or given sufficient pressure.

Providing a gas drive whereby a significant portion of the reservoirvolume is filled with low-cost gases.

Figure (1.9): Nitrogen Miscible Flooding.(2)


Crude Oil:Parameter value Unit

Gravity > 24, > 35 API

Viscosity < 10 CP

Composition High % of C1C7

Oil saturation > 30 % PV


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Reservoir:



Net thickness thin unless dippingAverage permeability N.C

Temperature N.C

Depth > 4,500 Ft

Limitations:

Miscibility can only be achieved with light oils at high pressures;therefore, deep reservoirs are needed.

A steeply dipping reservoir is desired to permit gravity stabilization of thedisplacement, which has a very unfavorable mobility ratio.

Advantages:

1. Large volumes may be injected, because of the low cost.Disadvantages:

1. Viscous fingering results in poor vertical and horizontal sweepefficiency.

2. Flue gas injection can cause corrosion.3.Non-hydrocarbon gases must be separated from saleable gas.4.Requires a much higher pressure to generate or develop miscibility.

1.5 Chemical flooding:Chemical flooding is any isothermal EOR process whose primary goals are to

recover oil by (1) reducing the mobility of the displacing agent (mobility control

process), and/or (2) lowering the oil/water interfacial tension.


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1.5.1 Polymer Flooding:Polymer flooding consists of adding polymer to the water of a water flood to

decrease its mobility. Adding a polymer leads to an increase in viscosity, as well

as to a decrease in aqueous phase permeability and a lower mobility ratio. The

remaining oil saturation decreases, due to the increased efficiency of the water

flood, even if the irreducible oil saturation is not affected by this technique.The

polymer is used not only to affect the mobility of the injected solution, but also to

plug high conductivity zones, that can be near the wells as well as deep in the

reservoir.

Polymer injection sequence consists of: a preflush with low-salinity brine; the

polymer solution itself; a freshwater buffer to protect the polymer solution from

backside dilution; and, finally, drive water.

Since the water used in the injection is usually a dilution of an oil-field brine,

interactions with salinity are important, particularly for certain classes of

polymers. Salinity is the Total Dissolved Solids (TDS) content of the aqueousphase. All chemical flooding properties depend on the concentration of specific


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ions rather than salinity only. In particular the total divalent cation content, also

called hardness, is critical to the chemical flood properties. The two most often

used materials in polymer flooding are Polysaccharide and Polyacry-lamides.

Figure (1.10): Polymer Flooding Mechanism.(2)

Mechanisms:Polymers improve the recovery by:

Increase the viscosity of water.

Decrease the mobility of water. Contacting a larger volume of the reservoir.


Crude Oil


Gravity > 25 API

Viscosity: < 150 CP

Composition N.C

Oil saturation (Mobil oil) > 10 % PV

Reservoir


Type of formation Sandstone preferred;

carbonate.

Net thickness N.C

Average permeability > 10 (normally) Md

Depth < 9000 Ft

Temperature < 200 F


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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 avoids extensive fractures. If

fractures are present, the cross linked or gelled polymer techniques may

be applicable.

Advantages:

1. Reduce residual oil saturation far below that attained by water flood.2. Areal and sweep efficiency are increased.3. Polymers are nontoxic and noncorrosive.4. Polymer floods require similar production technology as water flood.5. Use of polymers reduces producing water oil ratio.

Disadvantages:

1. Polymers are degradable either by chemical, bacterial, or shearingaction.

2. Polyacrylamides require special surface handling.3. Polysaccharides require filtration and bactericides.4. Incremental oil recoveries may not warrant the extra front- end

expense of polymer.

1.5.2 Surfactant Flooding:Also known as micellar-polymer flooding, low-tension water flooding, and

micro-emulsion flooding, this method typically involves injecting a small slug of

surfactant solution into the reservoir, followed by polymer thickened water, and

then brine. Despite its very high displacement efficiency, miscellar-polymer

flooding is hampered by the high cost of chemicals and excessive chemical

losses within the reservoir.


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Mechanisms:

Surfactant / micellar polymer recovers crude oil by:

Lowering the interfacial tension between oil and water. Solubilization of oil. Emulsification of oil and water. Mobility enhancement.


Crude Oil


Gravity > 25 API

Viscosity < 30 Cp

Composition Light to intermediate

Oil saturation > 30 % PV


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Figure (1.11): Surfactant Flooding Mechanism. (2)

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.

With commercially available surfactants, formation water chloridesshould be < 20,000 PPM and divalent ions (Ca++ and Mg++) < 500

PPM.

Advantages:

1. This process involves high unit displacement and Areal sweepefficiency.

2. Production technology is similar to water flooding.3. Gravity segregation is usually unimportant.4.The process is applicable to wide range of reservoirs.

Disadvantages:1. Front-end chemical costs are high.2. Performance prediction is poor due to mixing and dispersion of slug

material.

3.Slug design process is sophisticated.

Reservoir


Type of formation sandstone preferred

Net thickness > 10 Ft

Average permeability > 20 Md

Depth < 8000 Ft

Temperature < 175 F


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Figure (1.12): Caustic Flooding Mechanism. (2)

1.5.3 Caustic Flooding:In the alkaline or caustic flooding process, the alkali reacts with the acidic

constituents in the crude leading to lower water-oil interfacial tension,

emulsification of oil and water, and solubilization of rigid, interfacial films. Also,

the alkali may react with the reservoir rock, leading to wettability alteration. All

of these mechanisms will potentially increase oil recovery.

The alkaline flooding process is a relatively simple process as compared to other

chemical floods, but is still sufficiently complex to warrant careful laboratory

investigation and field trials before application.

The alkaline materials used most commonly in recent flooding are sodium

hydroxide and sodium other osilicate (silicate buffer system of sodium

hydroxide). Other alkali materials proposed and studied include sodium

carbonate, ammonium hydroxide, polyphosphate, and hydroxyl amine.


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Mechanisms:

Caustic flooding recovers crude oil by:

A reduction of interfacial tension resulting from the produced surfactants. Changing wettability of reservoir rock. Emulsification and entrainment of oil. Emulsification and entrainment of oil to aid in mobility Control.


Crude Oil


Gravity: 13-35 API

Viscosity: < 200 CP

Composition some organic acids

Oil saturation above waterflood

residual

Limitations:

The acidic content of a crude oil is commonly characterized as the acidnumber, i.e. the milligrams of potassium hydroxide required to neutralize

one gram of crude oil. An acid number of 0.1 would be quite low and 5.0

would be very high. Crude oil acid numbers above 0.5 mg KOH/g oil

generally indicate good candidates, and acid numbers between 0.2 and

0.5 justify further evaluation. However, it is not necessarily true that all

crude oils having high acid content are good candidates.

Reservoir

Parameter Value UnitType of formation sandstone preferred

Net thickness N.C


Depth < 9000 Ft

Temperature < 200 F


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Because of the incompatibility of alkaline chemicals with divalent ions,low salinity reservoirs are preferred and soft water is required to make the

alkaline solution. Further, if the hardness content on the formation water

is high, a preflush is needed to separate the reservoir brine from the

alkaline slug.

Sandstone reservoirs with low gypsum and clay content are preferred.Advantages:

1. The process is relatively in expensive to apply.2. Mobility control is better than in gas injection processes.3. The process is applicable to a wide range of crude oil.4. Conversion with water flooding to caustic flooding is easy.

Disadvantages:

1. Corrosion potential may require coating of all piping, tanks and tubing.2. The process is not well suited for carbonate reservoirs.3. Gypsum or anhydrite may precipitate in production well bores.

1.6 Thermal Processes:Thermal recovery generally refers to processes for recovering oil from

underground formations by use of heat.

The heat may be supplied externally by injecting a hot fluid such as steam or hot

water into the formations, or it may be generated internally by combustion. In

combustion, the fuel is supplied by the oil in place and the Oxidant is injected

into the formations in the form of air or other oxygen-containing fluids.

The most commonly used thermal recovery processes are steam injection

processes and in-situ combustion.

The common factor in all thermal methods is the increase in temperature of part

of the reservoir.

Thermal methods of enhanced oil recovery introduce heat into a reservoir to

lower the viscosity of the oil and facilitate its flow. These methods are used


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primarily whit high viscosity and high density crude oils that respond poorly to

other recovery methods.

1.6.1 Steam Injection:In recent years steamflooding has acquired a major role in the tertiary recovery

of crude oils, especially heavy, viscous oils, steam injection is the most widely

used and profitable enhanced recovery technique available today. The process

involves the injection of steam generated at the surface or downhole (to reduce

heat losses) continuously, or in cycles.

Mechanisms:Steam recovers crude oil by:

Heating the crude oil and reducing its viscosity. Supplying pressure to drive oil to the producing well.


Crude Oil


Gravity: < 25 API

Viscosity < 20 CP

Composition N.C

Oil saturation > 40 %50 % PV

Reservoir


Type of formation sand or sandstone with

high porosity


Average permeability 200 Md

Depth 3005,000 Ft

Temperature N.C


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Limitations:

Applicable to viscous oils in massive, high permeability sandstones orunconsolidated sands.

Oil saturations must be high, and pay zones should be > 20 feet thick tominimize heat losses to adjacent formations.

Less viscous crude oils can be steamflooded if they don't respond towater.

Steamflooded reservoirs should be as shallow as possible, because ofexcessive wellbore heat losses.

Steamflooding is not normally done in carbonate reservoirs.

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

A low percentage of water-sensitive clays is desired for good injectivity.

Cyclic Injection:Cyclic steam injection, also known as "steam soak" or "huff and puff", is a

single well operation. Steam is injected into a (producing) well for some

time, is allowed to "soak" for a period of time, and the well is subsequently

returned to production. Steam heats up the areas close to the wellbore, and

with a close well spacing, this process can generate a very good production

rate at a relatively low cost. The ultimate recovery from cyclic steam

injection is considerably lower, typically in the range of 10-25% of the oil-

in-place.

Advantages:

1. Steam injection is a proved production technique where no othermethod may be feasible.

2. Steam generators can be fueled by produced oil or by gas or coal.3. Front-end costs are moderate compared to chemical methods.4. Displacement efficiency is high, recovering up to 60% of the original

oil in place for steam drive.


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Figure (1.13): Cycles Injection Mechanism. (2)

Disadvantages:

1. Ultimate recovery for steam soak is low, up to 10% of the original oilin place.

2. The process is limited by depth due to heat losses and high steampressure.

3. Sand production is common.4. Emulsion handling of produced fluids is necessary.5. Good quality boiler-feed water is not always available.6. Steam generator emission cause air quality problems.

Continuously Injection:This process employs continuous injection of steam, usually at lower rates than

used more often. Recoveries from steamflooding are typically in the range of 50-

60% (sometimes up to 75%) of the oil-in-place.


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steam soak, into wells designated as injectors, which are critically placed as to

distance and direction from production wells. Continuous injection, called steam

drive or steamflooding, provides a higher ultimate recovery and is, therefore,

Figure (1.14): Continuous Injection Mechanism. (2)

Advantages:

1. Successful with heavy oil.2. Recovery 50% to 60% of OOIP.3. Produced oil used for fuel.

Disadvantages:

1. Close spacing required.2. Depth limitation due to heat loss.3. Availability of good-quality boiler-feed water.4. Early steam breakthrough gives low efficiency.5. Shallow depths dictate low injection pressure.6. Sand control.7. Emulsions.


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8. Figure (1.15): In-Situ Combustion Mechanism. (2)

1.6.2 In Situ Combustion:In-situ combustion is a displacement process in which an oxygen- containing gas

is injected into a reservoir where it reacts with the crude oil to create a high-

temperature

combustion front that is propagated through the reservoir. In most cases, the

injected gas is air, although the use of 100% oxygen has been reported. The fuel

consumed by the combustion front is a residuum produced by a complex process

of cracking, coking, and steam distillation that occurs ahead of the combustion

front. In-situ combustion is possible if the crude-oil/rock combination produces

enough fuel to sustain the combustion front. There are two types of forwardcombustion: dry combustion and wet combustion.

Mechanisms:In situ combustion recovers crude oil by:

The application of heat which is transferred downstream by conductionand convection, thus lowering the viscosity of the crud.

Burning coke that is produced from the heavy ends of the crude oil. The pressure supplied to the reservoir by the injected air.


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Crude Oil


Gravity < 40 (10-25) normally API

Viscosity < 1,000 CP

Composition some asphaltic

components

Oil saturation > 40 % - 50 %.

Reservoir


Type of formation sand or sandstone with

high porosity



Depth > 500 Ft

Temperature > 150 F

Limitations:

The reservoir chosen for in situ combustion operation should have no gas capor water zone within the area of operation.

Shallow depths from 300 to 4000 ft are generally applicable. Shallow depthslimit injection pressures. Air compression costs for deep reservoirs are

excessive.


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Advantages:1. In situ combustion is applicable to a wide variety of reservoirs up to

40 API.

2. The process involves more efficient heat generation than steaminjection.

3. Displacement efficiency is high although some oil is burned.4. Air is readily available.5. The process may produce oil that is lighter than original oil.

Disadvantages:

1. Design problems exist in controlling flame front.2. Producing equipment can be damaged by heat.3. Corrosion and emulsion handling are necessary.4. Compression costs are high.5. Gravity segregation may be a problem.6.Noxious gas may be formed due to combustion. (4-8-9)

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