Chemical Enhanced Oil Recovery

8/18/2019 Chemical Enhanced Oil Recovery

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CHEMICAL ENHANCED OIRECOVERY


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•

Surfactants to lower the interfacial tension between the oilwater or change the wettability of the rock

• Water soluble polymers to increase the viscosity of the wate

• Surfactants to generate foams or emulsion

• Polymer gels for blocking or diverting flow

• Alkaline chemicas such a sodium carbonate to react with crigenerate local surfactant and increase pH

• Combination of chemicals and methods


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The role of surfactant:

• Lowering oil-water interfacial tension

• Altering rock wettability

• Lowering bulk-phase viscosity

• Promoting emulsification

The role of polymer:

• Decreasing mobility ratio by increasing polymer solution viscosity

The role of alkaline:

• In alkaline flooding, high-pH chemical system is injected. Alkaline and acid hydrocarbonspecies in crude oil react to generate the surfactant.

The role of TFSA:

• Altering rock wettability towards a more water-wet

• Lowering oil-water interfacial tension.


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CHEMIC L FLOODING


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CHEMIC L FLOODING


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Polymer


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Polymer flooding


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Parameter Bio-polymers Synthetic polymers

Such as Xanthan Polyacrylamides

Made by Fermentation Hydrolysis

Charge Neutral Negatively charged

Effect of salinity Less sensitive More sensitive

Viscosity High Medium

Price Expensive Less expensive

Effect of bacteria Attacked Not attacked

Effect of shear Thinning Thickening

Polymers are made up of very large molecules and act as thickeners when dissolved in wa

result in high solution viscosity

Polymer types:

P l l i i i1000


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Polymer solution viscositySolution viscosity affected by:

• Polymer type and Concentration

• Salinity

• Shear rate

• Visco-elastic effects

• Inaccessible pore volume (IPV)

1

10

100

0.01 0.1 1

Shear Rate, 1

ApparentViscosity,cp 1000

10000

30000

Salinity, ppm

1

10

100

1000

0.01 0.1 1

Shear Rate,

ApparentViscosity,cp

2000

1000

500

2000

1000

500

Concentrati on, ppm

0

10

20

30

40

50

60

70

80

90

100

0 500 1000 1500 2000

Polymer Concentration, ppm

Solution

Viscosity,

cp

Bio-polymer

HPAM

1% NaCl

Temp. = 25

C

Shear rate = 5 s-1

P bilit d ti d i l ti ff t


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Permeability reduction and visco-elastic effect

All polymers exhibit shear thinning, non-Newtonian behavior in laboratory viscometers.

In porous media at very high shear rates, bio-polymers maintain this behavior while HPAM shows

behaves different than laboratory viscometers.

Viscosity of bio-polymers decrease with shear rate till

but retain original viscosity if shear rate is decreased back to

low values.

This behavior (shear thinning) is related to high molecule

elasticity short relaxation time (period required for

molecules to retain original shape after distortion).

Bio-polymers exhibit low apparent viscosity near injection

wells and, consequently; improved injectivity.

HPAM polymers exhibit long relaxation time and some permanent distortion if subjected to very

high shear rate and their apparent viscosity may increase (shear thickening).

Some permeability reduction results from injecting HPAM polymers into reservoir rocks.

0


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Resistance factor, permeability reduction factor, and residual resistanc

the technique index of describing the retention amount of polymer a

gel in the porous media. They are denoted by RF, Rk, and RRF.

w p

pw

k

k

P

P R

1

2F after

1

3RF

w

w

k

k P P R

Experimental procedure:

1. Saturating the core by formation water, injected water flooding, recorded the pressure

2. Injected chemical flooding 4PV 5PV, recorded the pressure P2.

3. Injected subsequent water 4PV 5PV, recorded the pressure P3.

The injection rate is 0.3 mL/min, the time interval of pressure record is 30 min.

Fk Rk

k R p

w

p

w

I ibl PV


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Inaccessible PV

• Polymer molecules are larger than water molecules

and are large relative to some pores in a porous

rock.

• Because of this, polymers do not flow through all

the pore space contacted by brine.

• The fraction of the pore space not contacted by the

polymer solution is called the inaccessible pore

volume (IPV).

• The magnitude of IPV can range from 1% to 30%,

depending on the polymer and porous medium.

P l t ti


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Polymer retention

Polymer adsorption is the main form of retention.

Measured in laboratory using representative core and fluid samples.

Polymer adsorption (p) is a function of polymer concentration (Cpl) in the

Mathematical expression is:

pl p pl p p C bC a 1 p = polymer adsorption, mg/g or g/kgap, bp = constants depend on polymer type

Converted to represent volume of polymer solution per unit pore volume,

pl p p pl C D 1 s = rock solid density, kg/m3 = porosity, fraction

Cpl = polymer concentration in solution, g/m3

Dpl = polymer adsorption, fraction of floodable PV, usua

referred to as polymer frontal advance loss

Polymer retention


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Polymer retention

Polymer adsorption is the main form of retention.

Measured in laboratory using representative core and fluid samples.

Polymer adsorption (p) is a function of polymer concentration (Cpl) in the

Mathematical expression is:

pl p pl p p C bC a 1 p = polymer adsorption, mg/g or g/kgap, bp = constants depend on polymer type

Converted to represent volume of polymer solution per unit pore volume,

pl p p pl C D 1 s = rock solid density, kg/m3 = porosity, fraction

Cpl = polymer concentration in solution, g/m3

Dpl = polymer adsorption, fraction of floodable PV, usua

referred to as polymer frontal advance loss

Polymer degradation


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Polymer degradation

Temperature

Temperatures in the range 120-130C, could cause most polymer solutions to crack and lose th

Hydrolysis

Can reduce viscosity of all polymers specially at high temperature. This effect more pronounc

environment.

Oxidation

Presence of oxygen, even in very low concentrations can prompt chemical reactions that lead

Microbial

Some types of bacteria in the system can attack and break polymer molecules.

Share rate

High shear rates (in surface pipes, valves, well perforations and near injection wellbore) can b

molecules into smaller segments.

Suitable polymer


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Suitable polymer

A suitable polymer should exhibit:

Good viscosity characteristics

High water solubility and easy mixing

Low retention in reservoir rock

Shear, temperature, chemical and biological stability

Ability to flow in the reservoir rock

Reasonable injectivity

Acceptable resistance and residual resistance:

Relatively low values are desirable for mobility control.

High values are desirable for plugging and profile control.

Selecting polymer


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Selecting polymer

Polymer concentration required to achieve a maximum mobili

Polymer solution slug size required

Total mass of polymer required for a flood

minimum

behind

wrworo

wrw prp PF

k k

k k M

425.01 22.078.011 w p K or VF IPV pl ps H S DV

2.01log DP DP K V V H

pl psvb C V E nV -310kgmass,Polimer

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Surfactants


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In a system with water and oil, a surfactant will reduce the interftension between the two liquid phases, which “liberates” residuby capillary forces, i. e. a reduction of capillary pressure in the releaving it water-wet. This “liberated” oil can now be more easilyand produced.

• Many technically successful pilots have been done

• Several small commercial projects have been completed and semore are in progress

• The problems encountered with some of the old pilots are welunderstood and have been solved

• New generation surfactants will tolerate high salinity and high so there is no practical limit for high salinity reservoirs

• Sulfonates are stable to very high temperatures so good surfacavailable for both low and high temperature reservoirs

• Current high performance surfactants cost less than $2/lb of psurfactant


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Favorable Characteristics for Surfactant Floo

• High permeability and porosity

• High remaining oil saturation (>25%)

• Light oil less than 50 cp--but recent trend is to apply to viscous o200 cp or even higher viscosity

• Short project life due to favorable combination of small well spahigh injectivity

• Onshore• Good geological continuity

• Good source of high quality water

• Reservoir temperatures less than 300 F for surfactant and less thpolymer is used for mobility control


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SURFACTANTS CHARATERISTICS

• Surfactants or surface active agents are chemical substances that conce

surface or fluid/fluid interface when present at low concentration in a s

• Most common surfactants monomer consist of a hydrocarbon portion (

lypophile) called tail and an ionic portion (polar - hydrophile) as the hea

• Classified according to the ionic nature of the head:

Anionic: sodium dodecyl sulfate (C12H25SO4Na+). Exhibit negative charge and yield

dissolved in water.

Cationic: dodecyltrimethyl ammonium bromide (C12H25Na+Me3Br-). Exhibit positi

yield cations when dissolved in water.

Nonionic: dodecyl hexaoxyethylene glycol monoether (C12H25[OCH2CH2]6OH). Neu

ionize in water but provide characteristics similar to surfactants.


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• Anionic surfactants preferred

• –Low adsorption at neutral to high pH on both sandstones

carbonates• –Can be tailored to a wide range of conditions

• –Widely available at low cost in special cases

• –Sulfates for low temperature applications

•

–Sulfonates for high temperature applications• –Cationicscan be used as co-surfactants

• •Non-ionic surfactants have not performed as well for EORsurfactants


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• Anionic surfactants ionize in water into inorganic cations and hydroca


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• Anionic surfactants ionize in water into inorganic cations and hydroca

anions.

• As the surfactant concentration increases, several of the sulfonate an

together in the form of micelles. For this reason, surfactant floods are

referred to as Micellar Floods.

Individual

monomers

Micelles

Surfactant Concen

I F T

Critical Micelle Concentra

(CMC)


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Surfactant-water-oil phase behavior


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p

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Daerah

2 Fasa

Daerah

1 Fasa

PlaitPoint

Brine

Surfaktan

Minyak

Brine

Mikroemulsi

Typ

Brine

Brine

Mikroemulsi

minyak

2 Fasa

Daerah

1 Fasa

Surfaktan

Minyak

2 Fasa

Daerah

3 Fasa

Type III

Daerah

2 Fasa

Daerah

1 Fasa

PlaitPoint

Brine

Surfaktan

Minyak

Minyak

Mikroemulsi

Type II-

Salinity increases


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Surfactant Phase Behavior

• Winsor Type I Behavior

• Oil-in-water microemulsion

• Surfactant stays in the aqueous phase

• Difficult to achieve ultra-low interfacial tensions


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• Winsor Type II Behavior

• –Water-in-oil microemulsion

• –Surfactant lost to the oil and observed as surfactant retent

• –Should be avoided in EOR


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• Winsor Type III Behavior

• –Separate microemulsion phase

• –Bicontinuouslayers of water, dissolved hydrocarbons

• –Ultra-low interfacial tensions ~ 0.001 dynes/cm

• –Desirable for EOR


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Optimal salinity


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1.0E-04

1.0E-03

1.0E-02

1.0E-01

1.0E+00

I F T ( d

y n e / c m )

IFT mo

IFT mw

l um

0.0

4.0

8.0

12.0

16.0

20.0

0.2 0.6 1.0 1.4 1.8 2.2 2.6 3.0

V o / V s a t a u

V w / V s )

Vo/Vs

Vw/Vs

Kadar Garam (% Berat NaCl)

At optimal salinity:

Interfacial tensions are e

minimum

Solubilization parameter

and maximum

Displacement efficiency is maximum at optimal salin


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sp ce e e c e cy s u op s

0

10

20

30

40

50

60

70

80

90

100

0 0.4 0.8 1.2 1.6 2

Salinity, % NaC

D

isplacementEfficiency

1.E-04

1.E-03

1.E-02

1.E-01

0 0.4 0.8 1.2 1.6 2 2.4 2.8 3.2

Salinity, % NaCl

In

terfacialTension,mN/m

Salinity

Increasing

Salinity

Decreasing

Surfactant retention


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Surfactant anions get retained in reservoir rocks due to:

Adsorption on positively-charged surfaces

Reaction with divalent cations

Trapping of oil-continuous micro-emulsions

sl s

sl s s

C b

C a

1

Langmuir Isotherm

0

4

8

12

16

20

24

28

32

36

40

44

48

0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6 1.8 2

Equilibrium Concentration, g-mole/m3

Adsorption,microg-mole/gclay

10%Co-surfactant

6%Co-surfactant

2%Co-surfactant

No Co-surfactant

Use of co-surfactants can

reduce surfactant retent

Many studies relate surfactant retention in reservoir rocks to clay content


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Many studies relate surfactant retention in reservoir rocks to clay content

water salinity

Laboratory and field tests can provide reliable retention values

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

1.1

0 4 8 12 16

Clay Content, % wt

Surfactan

tRetention,mg/gofRock

Lab Data

Field Data

Lab

Field d

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0 0.5 1 1.5 2 2.5 3 3.5

Salinity, % NaCl

Surfactan


Effect of Phase Trapping

Many studies relate surfactant retention in reservoir rocks to clay content a


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Page 44

Many studies relate surfactant retention in reservoir rocks to clay content a

water salinity

Laboratory and field tests can provide reliable retention values

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

1.1

0 4 8 12 16 2

Clay Content, % wt

Surfactan


Lab Data

Field Data

Lab d

Field data

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0 0.5 1 1.5 2 2.5 3 3.5

Salinity, % NaCl

Surfactan


Effect of Phase Trapping

Selecting suitable surfactant


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Possible candidate reservoirs for surfactant flood applications:

Medium to high oil gravity

Reasonably low salinity and hardness of formation water

Temperatures less than 100 C Relatively high residual oil saturation

Relatively low clay content with low cation exchange capacity

Select several surfactants based on preliminary screening

Conduct preliminary lab tests for further screening

Select 2 – 3 surfactants for detail lab tests

Find the right formulation and additives

Conduct core floods

Make final selection and design field pilot test

Selecting suitable surfactant


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Determination of surfactant retention

Determination of residual oil saturation

Surfactant slug volume required

Mass of surfactant required

Estimating RF from SP floods

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Surfactant Selection Criteria

• Minimal propensity to form liquid crystals, gels, macroemul

• Microemulsion viscosity < 10 cp

• Rapid coalescence to microemulsion

• Undesirable if greater than a few days and preferably less th

day• Slow coalescence indicates problems with gels, liquid crysta

macroemulsions


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lkaline

WHAT IS ALKALINE FLOODING?


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WHAT IS ALKALINE FLOODING?

It is an EOR method in which an alkaline chsuch as Sodium hydroxide,Sodium

Orthosillicate or Sodium carbonate is injec

during polymer flooding or water flooding

Operations.Alkaline flooding is also knownCaustic flooding.

HOW THIS WORKS INSIDE THE


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HOW THIS WORKS INSIDE THE

RESERVOIR?

The alkaline chemicals reacts with certain types ooil,forming surfactants inside the reservoir

Eventually,the surfactants reduce the interfacial

tension between oil and water and trigger an

Increase in oil production.Wetting characteristics

of the reservoir also can change due to Formatio

of surfactants inside the reservoir or it can be du

to some other reasons.

The use of alkali in a chemical flood is beneficial in many ways:

1 reduces the absorption of the surfactant on the reservoir ro


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1. reduces the absorption of the surfactant on the reservoir ro

2. alkali makes the reservoir rock more water-wet.

3. alkali is relatively inexpensive.

-Softened injection water is required in ASP i.e. very low conceof divalent cations (hardness) such as Ca +2 and Mg +2 . Othethese cations react with the alkali agent and form a precipitatehydroxides), which could plug the pores of most reservoirs.

-Higher salinity of the water phase can also be undesirable; it c

decrease the solubility of surfactant molecules in the water. In the alkali, usually caustic soda, reacts with components presenoil to form soap.


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CONSIDERATIONS FOR USING


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CONSIDERATIONS FOR USING…

Alkaline flooding is not recommended forcarbonate reservoirs due to the abundance

of

Calcium:The mixture between the alkaline

chemical and the calcium ions can produce

Hydroxide precipitation that may damage

the formation.

CRITERIA FOR USING…


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CRUDE OIL

Gravity 13 – 35 API

Viscosity 20 md

Depth


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EFFECTIVENESS OF DIFF.

CHEMICALS…

i. Sodium Orthosillicate upto 100%

ii. Sodium Carbonate upto 65%

iii.Sodium Hydroxide upto 80%

ADVANTAGES AND LATEST


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TECHNOLOGY…

Alkaline flooding is usually more efficient if the

acid content of the reservoir oil isRelatively high.

A new modification to the process is the addition

of surfactant and polymer to the alkali,

Giving rise to an Alkaline-surfactant-polymer(ASP) EOR method.

This method has shown to be an effective,less

costly form of micellar-polymer flooding.

PROBLEMS IN USING


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PROBLEMS IN USING…

1.Scaling and plugging in the producing

wells.

2.High caustic consumption.


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• Mobility control is critical. According to Malcolm Pitts, 99% f


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will fail without mobility control

• Floods can start at any time in the life of the field

•

Good engineering design is vital to success• Laboratory tests must be done with crude and reservoir roc

reservoir conditions and are essential for each reservoir con

• Oil companies are in the business of making money and areadverse so....

• Process design must be robust

• Project life must be short

• Chemicals must not be too expensive


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• Don W. Green and G. Paul Willhite, 2003, Enhanced Oil Recovery, SPE Textbook Series Vol. 6,

Petroleum Engineers Inc., USA.


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• Ezzat E. Gomaa, 2011, Enhanced Oil Recovery - Methods, Concepts, and Mechanisms, KOPUM

• L.P. Dake, 2002, Fundamentals of Reservoir Engineering, Elsevier Science B.V. Amsterdam, the

•

Larry W. Lake, 2005, Petroleum Engineering Handbook – Chemical Flooding, Society of PetrolRichardson, Texas, USA.

• Hestuti, E., Usman, Sugihardjo, 2009, “Optimasi Rancangan Injeksi Kimia ASP untuk Impleme

EOR”, Simposium Nasional IATMI 2009, Bandung, IATMI 09 – 00X.

• Zhijan, Q., Zhang, Y., Zhang, X., Dai, J., 1998, “A successful ASP Flooding Pilot in Gudong Oil Fi

SPE/DOE Improved Oil Recovery Symposium, Oklahoma, USA, SPE 39613.

• Harry L. Chang, Xingguang, S., Long, Xiao., Zhidong, G., Yuming, Y., Yuguo, X., Gang, C., KoopinJames, C. Mack, 2006, “Successful Field Pilot of In-Depth Colloidal Dispersion Gel (CDG) Tech

Daqing Oil Field”, SPE Reservoir Evaluation & Engineering (Desember 2006), pp. 664 – 673.

Documents

Chemical Enhanced Oil Recovery