6 Chemical Flooding

Miscible and Immiscible EOR Processes Fundamentals and

Prediction Models

Section 6 Chemical flooding

6.1EOR Processes Copyright Mamora & Associates


6 Chemical flooding6.1 Micellar/polymer flooding 6.2 Alkaline flooding 6.3 Design procedures6.4 Exercise on oil recovery with chemical flooding


Process descriptionThe process involves injecting a surfactant slug followed by a slug of polymer solution. Surfactant slug consists of water, surfactant, an electrolyte and a co-solvent (alcohol). The polymer solution is polymer-thickened water.

Process rationale(a) Surfactant is injected to reduce oil-water IFT,

increasing the capillary number, thus decreasing residual oil saturation. This results in improving displacement efficiency.

(b) The polymer slug reduces mobility ratio, thus improving volumetric sweep efficiency.

6.1 Micellar/polymer flooding


Reducing IFT increases capillary number and reduces residual oil (Stalkup)


MP flooding characteristics

Micellar/polymer flooding is the EOR technique most effective in lowering the IFT.

However, MP is the most complex EOR process.

MP flooding is also referred to as: detergent-, surfactant-, low tension-, chemical-, and microemulsion-flooding.


Chase Water Taper

MobilityBuffer

Slug Preflush

Mobility buffer

250-2500g/cm3polymer

0-1% Alcohol

Stabilizers

Biocide

0-100% Vpf

Slug

1-20% Surfactant

0-5% Alcohol

0-5%Cosurfactant

0-90% Oil

Polymer

5-20%Vpf

Preflush

Electrolyte (Na+, Ca++, etc.)

Sacrificial chemicals

0-100%Vpf

Chase Water Taper

MobilityBuffer

Slug Preflush

Mobility buffer

250-2500g/cm3polymer

0-1% Alcohol

Stabilizers

Biocide

0-100% Vpf

Slug

1-20% Surfactant

0-5% Alcohol

0-5%Cosurfactant

0-90% Oil

Polymer

5-20%Vpf

Preflush

Electrolyte (Na+, Ca++, etc.)

Sacrificial chemicals

0-100%Vpf

Schematic diagram of micellar/polymer process


Four types of surfactants: anionic, cationic, non-ionic and amphoteric.

(1) AnionicThe anionic monomer is associated with an inorganic metal (a cation, usually sodium). The monomer molecule dissociates in aqueous solution into free cations (positively charged), and anionic monomer (negatively charged). Anionic surfactants are the most common in MP flooding because they are good surfactants, relatively resistant to retention, stable, and can be made relatively cheap.

Types of surfactants


(2) CationicThe cationic surfactant molecule contains an inorganic anion to balance the charge. In solution it ionizes into a positively charged monomer, and the anion. Cationic surfactants are readily adsorbed by clays and thus not used in MP flooding.

(3) Non-ionicThis class of surfactant does not have ionic bonds.Non-anionic surfactants are much more tolerant to high salinities than anionic, but they are poorer surfactants. The non-ionic surfactants are used extensively in MP floods mainly as co-surfactants.


(4) AmphotericThis surfactant contains characteristics of two or more of the previous classifications and therefore has not been used for EOR processes.


S O-Na+

O

O

R

(b) Texas No. 1 sulfonate

S O-Na+

O

O

CC

CC

CC

CC

CC

CC

CC

C

C

(a) Sodium dodecyl sulfate

O

CC

CC

CC

CC

CC

CC

O S O-Na+

O

- x

+ -+ x

+ -

Anionics Cationics Noionics Amphoterics

Sulfonates, Sulfates,

Carboxylates, Phosphates

Quaternary ammonium organics, pyridinum,

imidazonlinium, piperidinium, and

sulfononium compounds

Alkyl-, alkyl- aryl-, acyl-, acylamindo-

acyl- aminepolyglycol, and polyol ethers

Aminocarboxylic acids

Summary of surfactant types


Monomers

Micelles

Total Surfactant Concentration

S

u

r

f

a

c

t

a

n

t

M

o

n

o

m

e

r

C

o

n

c

e

n

t

r

a

t

i

o

n

Critical Micelle Concentration

(CMC)

MonomersMonomers

Micelles

Total Surfactant Concentration

S

u

r

f

a

c

t

a

n

t

M

o

n

o

m

e

r

C

o

n

c

e

n

t

r

a

t

i

o

n


(CMC)


(CMC)

Typical CMC values are 10-5 10-4 kg-mol/m3. Size of micelles is 10-4 to 10-6 mm.

Critical micelle concentration


WATER

WATER

OIL

OIL WATER(O)

MOLECULARDISPERSION

IN OIL

(W)

MOLECULARDISPERSIONIN WATER (S1)

WATEREXTERNAL

(S2)

OILEXTERNAL

Surfactant-brine-oil phase behavior


Ternary diagram to represent surfactant/oil/brine phase behavior


i Species Concentration Unit j Phase

1 Water Volume Fraction 1 Aqueous

2 Oil Volume Fraction 2 Oleic

3 Surfactant Volume Fraction 3 Microemulsion

4 Polymer Weight percent or g/m3

Numbering of phases and species


At low brine salinity, a typical MP surfactant will exhibit good aqueous phase solubility.

Oil occupies the central core of the swollen micelles.

The tie lines within the 2-phase envelope have a negative slope.

The plait point PR in this system is located closer to the oil apex.

Type II (-) behavior


Type II (-) behavior


Type II (+) behavior


Type III behavior


Simplified phase diagram for microemulsionsystem


Changes in phase conditions

Changing any condition besides salinity - that enhances the surfactants oil solubility will usually cause a shift from type II (-) to type II (+). These conditions include: Decreasing temperature Increasing surfactant molecular weight Decreasing oil specific gravity Increasing concentration of high molecular weight

alcohols. Decreasing surfactants oil solubility will cause the

reverse change


Pseudoternary or tent' diagrams of micellar-polymer phase behavior


6.2 Alkaline flooding

Alkaline flooding is also known as caustic flooding. It is a high pH chemical EOR method which has many similarities with micellar flooding. The difference is that in micellar flooding the surfactant is injected, while in alkaline flooding the surfactant is generated in situ.


6.2 Alkaline flooding

High pHs indicates large concentrations of hydroxide anions COH-. The pH of an ideal aqueous solution is defined as:

( )

OH

HOHw

H

CCC

k

CpH

2

log

+

+

=

=


Controlling pH

There are two methods for increasing the pH of a reservoir fluid:

(1) By dissociation of a hydroxyl containing species such as NaOH, or KOH.

(2) By adding chemicals that will bind with CH+.


Sources of OH-

Sodium hydroxide or sodium carbonate dissociates in water following the dissociation reactions:

+

+++

OHCOHOHCO

NaCOCONa

22

2

3222

3

2332

+ + OHNaNaOH


Surfactant formation

OH - by itself is not a surfactant since the absence of a lypophilic tail makes it exclusively water soluble. However, if the oil contains acidic hydrocarbon components (HAo), some of it may partition into the aqueous phase.


OIL

ROCK

M

H

NaOH

H2O

H2O

HAoOH-

Na+ A-

HAo

HAw A- + H+

OIL

ROCK

M

H

NaOH

H2O

H2O

HAoOH-

Na+ A-

HAo

HAw A- + H+

Schematic diagram of alkaline flood recovery


Oil requirements

If no acidic species are present in the crude, no surfactant can be generated.

To determine the oil characteristics needed for alkaline flooding we must characterize its acidity.


Acid number

The acid number is the milligrams of potassium hydroxide (KOH) needed to neutralize one gram of crude oil.

The acidic species HAo is removed from the crude oil to the aqueous phase

The aqueous phase is brought to neutral pH=7 by adding KOH.


Useful considerations For a meaningful value, the oil must be free of acidic

additives such as corrosion inhibitors and acidic gases such as H2S and CO2.

A good alkaline flooding candidate will have an acidic number of 0.5 mg/g or greater.

SPE DISTINGUISHED LECTURER SERIESis funded principally

through a grant of the

SPE FOUNDATIONThe Society gratefully acknowledges

those companies that support the programby allowing their professionals

to participate as Lecturers.

And special thanks to The American Institute of Mining, Metallurgical,and Petroleum Engineers (AIME) for their contribution to the program.


Chemical EORThe Past, Does It Have A Future?

Sara ThomasPERL Canada [email protected]


The Past :Limited Commercial Success


FUTURE: Very Bright

Past experience

High oil prices

Scaled models

Objectives Why chemical EOR methods have not been

successful? Process limitations Current status of chemical floods Recent changes that make such methods

attractive


Chemical EOR Holds A Bright Future

Conventional oil RF

Chemical EOR Target in Selected Countries

100

8477

63 6151

4026 24

12 10 10 9 7 6 4 4 3 3

173

0.3 0.20.60.90

20

40

60

80

100

120

140

160

180

S

.

A

r

a

b

i

a

U

S

A

I

r

a

n

I

r

a

q

K

u

w

a

i

t

A

b

u

D

h

a

b

i

V

e

n

e

z

u

e

l

a

R

u

s

s

i

a

L

i

b

y

a

N

i

g

e

r

i

a

C

h

i

n

a

Q

a

t

a

r

M

e

x

i

c

o

C

a

n

a

d

a

B

r

a

z

i

l

N

o

r

w

a

y

O

m

a

n

I

n

d

i

a

U

K

D

u

b

a

i

D

e

n

m

a

r

k

R

o

m

a

n

i

a

G

e

r

m

a

n

y

F

r

a

n

c

e

B

i

l

l

i

o

n

B

b

l

s

Assumed: Primary Rec. 33.3 %OOIP Chem. Flood Rec. 33.3 %OIP


100 84 77 63 61 51 40 26 24 12 10 109

7

6

4 43 3

173

0.3 0.20.6

0.9

0123456789

10S

.

A

r

a

b

i

a

U

S

A

I

r

a

n

I

r

a

q

K

u

w

a

i

t

A

b

u

D

h

a

b

i

V

e

n

e

z

u

e

l

a

R

u

s

s

i

a

L

i

b

y

a

N

i

g

e

r

i

a

C

h

i

n

a

Q

a

t

a

r

M

e

x

i

c

o

C

a

n

a

d

a

B

r

a

z

i

l

N

o

r

w

a

y

O

m

a

n

I

n

d

i

a

U

K

D

u

b

a

i

D

e

n

m

a

r

k

R

o

m

a

n

i

a

G

e

r

m

a

n

y

F

r

a

n

c

e

B

i

l

l

i

o

n

B

b

l

s

Assumed: Primary Rec. 33.3 %OOIP Chem. Flood Rec. 33.3 %OIP

Chemical EOR Target in Selected Countries


Chemical Methods

Chemical EOR methods utilize: Polymers Surfactants Alkaline agents Combinations of such chemicals

ASP (Alkali-Surfactant-Polymer) flooding MP (Micellar-Polymer) flooding


Classification

CHEMICAL METHODS

PolymerSurfactantAlkali

Emulsion

MicellarASP


Chemical Floods History

50,000

100,000

150,000

200,000

250,000

300,000

1995 1997 1999 2001 2003O

i

l

P

r

o

d

u

c

t

i

o

n

,

B

/

D

Total

0

5,000

10,000

15,000

20,000

25,000

1978

1980

1982

1984

1986

1988

1990

1992

1994

1996

1998

2000

2002

2004

2006

O

i

l

P

r

o

d

u

c

t

i

o

n

,

B

/

D

Total

Polymer

Micellar

AlkalineSurfactant

USA CHINA


Chemical Floods - Current Status Worldwide

OGJ April 12, 2004

China

Venezuela

France

IndiaIndonesia USA

Total Number of Projects: 27


Chemical Floods - Production Worldwide

OGJ April 12, 2004

China

France Indonesia

USA

Total oil production: 300,000 B/D


Objectives of Chemical Flooding

Increase the Capillary Number Nc to mobilize residual oil

Decrease the Mobility Ratio M for better sweep Emulsification of oil to facilitate production


Chemical Flooding - General Limitations Cost of chemicals

Excessive chemical loss: adsorption, reactions with clay and brines, dilution

Gravity segregation Lack of control in large well spacing

Geology is unforgiving! Great variation in the process mechanism, both

areal and cross-sectional


Polymer Flooding

Loss to rock by adsorption, entrapment, salt reactions

Loss of injectivity Lack of control of in situ advance High velocity shear (near wellbore), ageing, cross-

linking, formation plugging Often applied late in waterflood, making it largely

ineffectivemixing zone

Polymer Flood

residual oiloil

waterpolymer slugdrivewater


Polymer Flood - Field Performance

Sanand Field, India

1989 1991 1993 19950

25

50

75

100

125

500

530

560

590

620

650

Projected

EOR OIL


Polymer Flood Field ProjectsProject Flood Type Formation Polymer Rec., %OIP

1 Taber Manville South Secondary Sandstone PAA 22 Pembina " " " 03 Wilmington " " " 04 East Colinga " " Biopolymer 05 Skull Creek South " " PAA 86 Skull Creek Newcastle " " " 107 Oerrel " " " 238 Hankensbuettel " " " 139 Owasco " " " 7

10 Vernon " " " 3011 Northeast Hallsville " Carbonate " 1312 Hamm " Sandstone " 913 Sage Spring Cr. Unit A " " " 1.214 West Semlek " " " 515 Stewart Ranch " " " 816 Kummerfeld " " " 617 Huntington Beach " " " 418 North Stanley Tertiary " " 1.119 Eliasville Caddo Tertiary Carbonate " 1.820 North Burbank Tertiary Carbonate " 2.5


Variations Surfactant-Polymer Flood (SP) Low Tension Polymer Flood (LTPF)

Adsorption on rock surface Slug dissipation due to dispersion Slug dilution by water Formation of emulsions

Treatment and disposal problems

Surfactant Flooding

mixing zone

Polymer Flood

residual oiloil

waterpolymer slugdrivewater


Surfactant Flood -Field Performance

Glenn Pool Field, OK

1984 86 87 88 89 90 91 9285

1,000

100

10

OIL

WOR


Process depends on mixing of alkali and oil Oil must have acid components

Emulsification of oil, drop entrainment and entrapment occur Effect on displacement and sweep

efficiencies? Polymer slugs used in some cases

Polymer alkali reactions must be accounted for

Complex process to design

Alkaline Flooding

Alkaline Flood

mixingzones

oil

waterdrivewater

causticslug

residual oil

lowIFTzone


Alkaline Flooding Field Performance

Field Slug Size Conc. Oil Satn. Consum. Oil Rec.% PV wt% %PV mg/g rock %OIP

1 Whittier 8 0.2 51 2.4-11.2 42 Singleton 8 2.0 40 - 53 N. Ward Estes 15 4.9 64 17.2 84 L. A. Basin 5 0.4 30 - 35 Orcutt Hill 2 0.42 50 0.5 26 Van 12 0.14 25-35 0.6-1.2 37 Kern River 48 0.15 52 1.3 none8 Harrisburg 9 2.0 30-40 - 69 Brea-Olinda 1.2 0.12 50-60 - 2


Alkaline-Polymer Flood

David Field, Alberta

0.1

1

10

100

10

1

100

1969 1974 1979 1984 1989 1994 1999 2004

Oil Cut

Oil Rate

PrimaryWaterflood Alkaline-Polymer

Flood

1000


ASP: Alkali-Surfactant-Polymer Flooding

Several variations:

ASP SAP PAS Sloppy Slug

Injected as premixed slugs or in sequence

ASP Flood

oil bank

S

u

r

f

a

l

k

a

l

i

drivewater polymer

oil

water

Field tests have been encouraging Successful in banking and producing residual oil Mechanisms not fully understood


ASP Pilot Daqing, China

10

100

20

1993

Oil Cut

Oil Rate

1994 1995 1996

50


Utilizes microemulsion and polymer buffer slugs Miscible-type displacement Successful in banking and producing residual oil Process limitations:

Chemical slugs are costly Small well spacing required High salinity, temperature and clay Considerable delay in response Emulsion production

Micellar Flooding

mixingzone

d

r

i

v

e

w

a

t

e

r

oil

water

micellarslug

p

o

l

y

m

e

r

oil bank

mixing zone

Micellar Flood


ASP vs. Micellar Flood -Lab Results Mitsue Oil Core Floods

Earlier oil breakthrough and quicker recovery in micellar flood

Micellar Flood

0

20

40

60

80

100

0 0.5 1 1.5 2 2.5

Pore Volumes Injected

O

i

l

C

u

t

,

%

;

C

u

m

.

R

e

c

o

v

e

r

y

,

%

O

I

P

Slug 5% Buffer 50% Soi 32%

92% OIP

Oil Cut

ASP Flood

0

20

40

60

80

100

0 0.5 1 1.5 2 2.5Pore Volumes Injected

Alkali 5%,Surfactant 10%,Polymer 60%

Soi 38% 80% OIP

Oil Cut


Micellar Flood Typical Performance

Bradford Special Project No. 8

10

100

1,000

0.1

1

10

Dec. 81 Dec. 82 Dec. 83 Dec. 84 Dec. 85

Oil Cut

Oil Rate

micellarinjection


Micellar Slug Size, %PV

00

20

40

60

80

100

2 4 6 8 10 12 14

Henry S

119-RHenry E & Henry W

Wilkins

Dedrick

Micellar Flood Field Tests


ASP and MP Field Projects

* %OOIP

ASP Floods Started Appln. Acre Rec., %OIPDavid, Alberta 1986 Tertiary 252 *21West Kiehl, Wyoming 1987 " 106 34.4Gudong, China 1992 " 766 29.4Cambridge, Wyoming 1993 " 72 *26.8Daqing, China 1994 " 8.4 23.9Karamay, China 1996 " 766 *24Viraj, India 2002 " 68 *24

Micellar Floods Dedrick (IL) 1962 Secondary 2.5 *49.7Robinson, 119-R (IL) 1968 Tertiary 40 39Benton (IL) Shell 1972 " 160 29Robinson, 219-R (IL) 1974 " 113 27North Burbank (OK) 1976 " 90 11Robinson, M1 (IL) 1977 " 407 50Bradford (PA) 1980 " 47 50Salem Unit (IL) 1981 " 200 47Louden (IL) 1977 " 40 27Louden (IL) 1980 " 80 33Chateaurenard, (France) 1983 " 2.5 67


Other Methods

Emulsion flooding Micellar-Alkaline-Polymer flood (MAP) ASP-Foam process Surfactant huff npuff Surfactant with thermal processes


Reasons for Failure

Low oil prices in the past Insufficient description of reservoir geology

Permeability heterogeneities Excessive clay content High water saturation Bottom water or gas cap Fractures

Inadequate understanding of process mechanisms

Unavailability of chemicals in large quantities Heavy reliance on unscaled lab experiments


Scale-Up Methods

Require: Knowledge of process variables or complete

mathematical description Derivation of scaling groups Model experiments Scale-up of model results to field

Greater confidence to extend lab results to field


Scaling Groups Micellar Flood:

Additional Groups: Slug Size, Flood Rate, Mixing Coefficient, Oil

Recovery

( ) ( ) ( )1p M Mp M

M p P

oi oi oi Mpp M p M PS s

oi m oi oi

S S S rkPV PV v v a r

S k S S = = = =

max max max max

max maxmax

max max

* *

* *

2 * 2

LE LE

EA

c c rw o rE w A E

o o c ro w rw E L L

oi o L o oi L o

ro ro

P P k k q qL pd gh gh P k k q q

S L q L S Kkk pt kk p

max ,

s sLro T oi o L s p

C CKkk p K S C C


010

20

30

40

50

60

0 0.2 0.4 0.6 0.8 1 1.2

Pore Volumes Produced

O

i

l

R

e

c

o

v

e

r

y

,

%

O

I

P

Predicted

Actual

Results: Prediction vs. Actual


Chemical EOR & Heavy Oil

Applicable methods: Surfactant flooding unsuccessful Alkaline flooding unsuccessful CO2 immiscible; cyclic stimulation Limited

success with WAG Problems:

Unfavourable mobility ratio Rock-fluid reactions, chemical loss, dilution Lack of scaling criteria, inadequate simulation Often used where steam is not suitable Gravity segregation


EOR Screening Criteria

Oil viscosity < 35 cp Oil API gravity > 30 API Permeability 100 md Porosity 15% Temperature < 150 F Depth < 9,000 ft Pressure not critical Oil saturation 45% Oil in place at process

start 600 Bbl/acre-ft

Formation sdst preferred Thickness 20-30 ft Stratification desirable Clay content < 5% Salinity < 20,000 ppm Hardness < 500 ppm Oil composition Light,

intermediates & organic acids desirable

No bottom water or gas cap

Most important: geology and mineralogy


How To Plan a Flood

Choose a process likely to succeed in a candidate reservoir

Determine the reasons for success or failure of past projects of the process

Research to fill in the blanks Determine process mechanisms Derive necessary scaling criteria Carry out lab studies

Field based research Establish chemical supply Financial incentives essential


Process Evaluation

Compare field results with lab (numerical) predictions

Relative permeability changes? Oil bank formation? If so, what size? Mobility control? Fluid injectivity? Extent of areal and vertical sweep? Oil saturations from post-flood cores?


Interpretation of Results

Large number of chemical floods with little technical success

Field tests implemented for tax advantage misrepresent process performance

Questionable interpretations distort process potential


Cost of Chemicals

As oil prices rise, so does cost of chemicals, but not in the same proportion

Typical Costs: Polymer - $3/lb Surfactant - $1.20/lb Crude oil - $60/bbl Caustic - $0.60/lb Isopropanol - $20/gallon Micellar slug - $25/bbl

Process Efficiency: volume of oil recovered per unit volume (or mass) of chemical slug injected


The Case for Chemical Flooding

Escalating energy demand, declining reserves Two trillion bbl oil remaining, mostly in depleted

reservoirs or those nearing depletion Infill drilling often meets the well spacing required Fewer candidate reservoirs for CO2 and miscible Opportunities exist under current economic

conditions

Improved technical knowledge, better risk assessment and implementation techniques


Conclusions

Valuable insight has been gained through chemical floods in the past failures as well as successes

MP and ASP methods hold the greatest potentialfor commercial success; polymer flooding a third option

Chemical flooding processes must be re-evaluated under the current technical and economic conditions


Chemical floods offer the only chance of commercial success in many depleted and waterflooded reservoirs

Chemical flooding is here to stay because it holds the key to maximizing the reserves in our known reservoirs

Conclusions


6 Chemical Flooding

Documents

Transcript of 6 Chemical Flooding