wfc 08 03 chemical flooding-concepts

Road Map Penelitian Surfaktan Peptida

Surfactant Peptida LEMIGAS (SUPEL)

2011-2012

Phase Behavior: Fase Tengah

IFT: 0,03 dyne/cm (@ 25oC, pH 11); 0,06 dyne/cm (@ 25oC, pH 11, 1 bln)

Perubahan sudut kontak (wettability): 63o 15o

Adsorpsi: 0,19 mg/g

Salinitas: 11.400 mg/l APIo: 43,8 Viscositas: 0,63 cp

Belajar dari Pepfactant® (AM-1 & AFD-4)

Perancangan Surfaktan Peptida LEMIGAS

0,025 %

Achievements

1. Usulan PatenSekuen Molekul Asam Amino Peptida Bersifat Surfaktan Anionik

2. Karya Tulis Ilmiaha. Pengaruh Jenis Struktur Molekul Peptida terhadap Tegangan

Antar Muka: Sebuah Upaya Pengembangan Surfaktan EOR dengan Nanobioteknologi

b. Perancangan Surfaktan Protein untuk Pengurasan Minyak

3. 104 Inovasi Indonesia Prospektif - 2012

CHEMICAL FLOODING: CONCEPTS AND MECHANISMS

Objektif eksplorasi-eksploitasi migas

OOIP =366 MMstb

Initial Primary Recovery

Cadangan =90 MMstb

SecondaryRecovery

TertiaryRecovery

Cadangan =155 MMstb

Cadangan =235 MMstb

Fie

ld o

il r

ate

primary

secondary waterflood

tertiary EOR

Field Life Time

1 2

3

Time

RF = 25%RF = 42%

RF = 64%

Reservoar Model

akumulasiesink/sourckeluaraliran -masuk aliran

aliran masuk aliran keluar

q

Dx

x

A

x+x

Hukum kekekalan massa:

i

nn

ii

n pppS

tqu

111

oo

ooo

SBt

quBx

11more familiarform

Fie

ld o

il r

ate

primary

secondary waterflood

tertiary EOR

Field Life Time

Oil recovery phases and EOR technology

LEMIGAS

Time

xpAkk

qo

roo

25% +15% ???primary secondary

Recovery factor

tertiary

OOIP+25%

t

op tqN0

d

N

NRF p

Who is the hero in the reservoir engineering

Physics Newton and Einstein

Biology Darwin

Reservoir Engineering

Henry Darcy (1856)

Illustration of a typical chemical flood

LEMIGAS

Oil

DrivingFluid( Water )

TaperedPolymerSlug forTransitionto DriveWater

PolymerSolutionforMobilityControl

SurfactantSlug forReleasingOil

AdditionalOilRecovery( Oil Bank )

Production Well

InjectionFluids

InjectionPump

InjectionWell

Recovery factor for displacement processes

Oil recovery pada setiap proses displacement fungsi dari:- Volume reservoar yang disapu (swept) oleh fluida injeksi, dinyatakan dengan

volumetric displacement efficiency (EV) – macroscopic.

- Recovery factor pada area yang disapu oleh fluida injeksi, dinyatakan dengan displacement efficiency (ED) – microscopic.

Material balance untuk oil displaced (Np) dinyatakan sebagai:

Recovery factor:

Vpo

o

o

op EV

B

S

B

SN

2

2

1

1

IAD

VDp

EEE

EEN

NRF

1 21

121oo

ooD BS

BSE

So1 = saturasi minyak pada awal displacementSo2 = saturasi minyak pada akhir displacementBo1 = FVF minyak pada awal displacementBo2 = FVF minyak pada akhir displacementVp = reservoir pore volume

EA = areal displacement efficiencyEI = vertical displacement efficiency

Stability of displacement

EV

ED

So1 So2

So2< So1

So1

Stability of displacement

Stability of displacement is controlled by mobility ratio, M defined as:

M < 1

M > 1

d

DM

D= mobility of displacing fluid

phase behind the frontd= mobility of displaced fluid

phase ahead of the front

Stability of displacement in dipping reservoirs

water

oilinterface

Unconditionally stableMo < 1 >

water

oil

Unconditionally stableMo = 1 =

water

oil

Stable if Ng > Mo - 1Mo > 1 <

water

oil

Unstable if Ng < Mo - 1Mo > 1 <

Data:Reservoir dip angle sin 0.22Permeability, mD 418

Water density, kg/m3 1000

Oil density, kg/m3 780

Acceleration of gravity, m/s2 9.8w, cp 0.4o, cp 2.1

kro0, fraction 0.80

krw0, fraction 0.25

Water injection rate, bwpd 3800

Flow area, m2 9500

Required: Check the stability of oil displacement and determine the critical injection rate required for stability

M0 1.64u, m/s 7.36E-07Ng 0.168

M0 - 1 0.64

This displacement is unstable since Ng < (M0 - 1)

ucrit, m/s 1.93E-07

qcrit, bwpd 999

w

wg u

gkN

sin 1 Darcy = 10-12 m2

1 bbl = 0.1589873 m3

1 cp = 0.001 kg/m.s

Example:Recovery factor for a waterflood and EOR displacements

OOIP =366 MMstb

Initial Primary Rec.

Cadangan =90 MMstb

WF SPF

Cadangan =155 MMstb

Cadangan =235 MMstb

Data:Soi, % 65Boi, rb/stb 1.23OOIP, MMstb 366Cumulative primary production, MMstb 90Bo1, rb/stb 1.20So2, % 30Bo2, rb/stb 1.17Ev2, % 66So3, % 15Bo3, rb/stb 1.16Ev3, % 76

Required: Waterflood and SP RF and the ultimate RF afterSP flood

Pore Volume, MMbbl 693Primary RF, % 25So1, % 48ED2,% 36Waterflood RF, % 24Cumulative Secondary recovery by WF, MMstb 65Ultimate RF after waterflood, % 42Target Potential EOR, MMstb 211ED3,% 50Surfaktan Polimer (SP) RF, % 38Cumulative Tertiary recovery by SPF, MMstb 80Ultimate RF after SP flood, % 64

Factors affecting displacement efficiency

Areal displacement efficiency affected by:

Vertical displacement efficiency affected by:

Displacement efficiency affected by:

• Mobility ratio

• Lateral heterogeneity

• Injection volume

• Injection/production

well pattern

• Mobility ratio

• Gravity segregation

• Layer heterogeneity


• Relative permeability

characteristics

• Fluid viscosity

• Rock wettability


• Gravity forces

• Capillary forces

Flooding patterns

Injector Producer

Areal displacement efficiency

Five-spot pattern:

4394.0123.0ln3048.0511.00712.0ln2062.01

1

MfME

wA

Direct line drive:

8805.00865.0ln3714.09402.01568.0ln3014.01

1

MfME

wA

Vertical displacement efficiency

Data:L, ft 300h, ft 10Porositas, % 15Soi, % 75

Siw, % 25

ko, mD 200

s, g/cm3 0.70s, cp 2.3

o, g/cm3 0.85o, cp 2.3Frontal advanc rate, ft/day 0.5Darcy velocity, ft/day 0.075

Required: Vertical displacement efficiency

u, bbl/(day-ft2) 0.0134Rv/g 63

M 1

EI, % 86

Any change in a parameter in Rv/g that reduces its numerical value contribute to gravity effects, which leads to early breakthrough of the displacing fluid.

Vertical displacement efficiency

Dykstra-Parsons Method

wroorw kkMo 00

X0 10137.18094.0499.2948.184.0WORY DPDP VMV

6891.0935.06453.1X 2 DPDP VV

Y1077.2Yln103.4Yln1062.4Yln016.0Yln182.0199.0 414332 IE

Data:VDP 0.67

M0 2

WOR 5

Required: Vertical displacement efficiency

X 0.6627Y 7.81ln Y 2.06

EI, % 60

WOR 0.1 0.2 0.5 1 2 5 10 25 50Y 0.72 0.87 1.30 2.02 3.47 7.81 15.04 36.74 72.89ln Y -0.32 -0.14 0.26 0.71 1.24 2.06 2.71 3.60 4.29EI, % 14 18 25 33 44 60 72 86 93

Microscopic displacement efficiency

The residual oil saturation is a function of the trapping mechanisms.

Trapped

Wetting phase Non-wetting phase

r1r2

Aspect Ratio = r1 /r2

Large Aspect Ratio Trapping

Small Aspect Ratio No Trapping

Trapped

Wetting phase Non-wetting phase

r1r2

Aspect Ratio = r1 /r2

Large Aspect Ratio Trapping

Small Aspect Ratio No Trapping

Wetting phase

Non-wetting phase

Solid grains

Trapping mechanisms are a function capillary.


Capillary desaturation curve relates the amount of trapped nonwetting or wetting phase as a function of capillary number.

21

121oo

ooD BS

BSE

Other forms of capillary number

)]/()/[( 00orowrw

vckk

uN

Laboratory

w

vcu

N 0rw

wvc

k

uN

Field

p

wvc Ah

qN

565.0

p

wvc Ah

qN

565.0


Imbibition and drainage processes based on wettability of the porous medium.

Immiscible and miscible processes based on mixing between displacing fluid and oil.

Effect of wettability changes, mixing fluids, and interfacial tension on oil-water relative permeability curves

Chemical flooding

Chemical floods are methods where one or more of specially selected

chemical substance are added to the injection water with the main

objective of increasing oil recovery factor beyond waterflood levels.

The following mechanisms can be achieved with chemical floods:

Increasing the macroscopic volumetric displacement efficiency due to

reduction of mobility ratio. Achieved by using polymers.

Increasing the microscopic displacement efficiency due to reduction of

residual oil saturation. Achieved by using surfactants and alkaline.

Increasing the imbibition efficiency due to alteration of reservoir rock

wettability. A Achieved by using surfactants and alkaline.

Chemical flooding

Most filed applications are designed that utilize at least two chemical

substances.

These combination floods include:

Surfactant – polymer (SP), also known as micellar-polymer (MP),

Alkaline – surfactant – polymer (ASP),

Alkaline – polymer (AP).

Thin film spreading agent surfactant – polymer (TFSA-P)

The role of chemical substances

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

hydrocarbon species 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.

Polymer

Polymer substance

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 water that result in high solution viscosity

Polymer types:

Polymer solution viscosity

Solution viscosity affected by:

• Polymer type and Concentration

• Salinity

• Shear rate

• Visco-elastic effects

• Inaccessible pore volume (IPV)

1

10

100

1000

0.01 0.1 1 10 100

Shear Rate, 1/s

Ap

pa

ren

t V

isc

os

ity

, cp

1000 ppm Bio-polymer

1000 ppm HPAM

1000

10000

30000

1000

10000

30000

Salinity, ppm

1

10

100

1000

0.01 0.1 1 10 100

Shear Rate, 1/s

Ap

pa

ren

t V

isc

os

ity

, cp

Bio-polymer

HPAM2000

1000

500

2000

1000

500

Concentration, ppm

Salinity = 10000 ppm

0

10

20

30

40

50

60

70

80

90

100

0 500 1000 1500 2000

Polymer Concentration, ppm

So

luti

on

Vis

co

sit

y, c

p

Bio-polymer

HPAM

1% NaCl

Temp. = 25 C

Shear rate = 5 s-1

Permeability reduction and visco-elastic effects

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

Permeability reduction and visco-elastic effects

Resistance factor, permeability reduction factor, and residual resistance factor are

the technique index of describing the retention amount of polymer and polymer

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

wp

pw

k

k

P

PR

1

2F after

1

3RF

w

w

k

k

P

PR

Experimental procedure:

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

pressure P1.

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

kR

p

w

p

w

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.

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 injected

slug. Mathematical expression is:

plpplpp CbCa 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,

plpppl CD 1 s = rock solid density, kg/m3

f = porosity, fractionCpl = polymer concentration in solution, g/m3

Dpl = polymer adsorption, fraction of floodable PV, usually referred to as polymer frontal advance loss

Polymer degradation

Temperature

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

and lose their viscosity

Hydrolysis

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

pronounced in low pH environment.

Oxidation

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

that lead to polymer loss.

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 break polymer molecules into smaller segments.

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.

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

Polymer concentration required to achieve a maximum

mobility ratio.

Polymer solution slug size required

Total mass of polymer required for a flood

minimum

behind

wrworo

wrwprpPF

kk

kkM

425.01 22.078.011 wpKorVFIPVplps HSDV

2.01log DPDPK VVH

plpsvb CVEnV -310 kg mass,Polimer

Surfactants

Courtesy from Gary A. Pope

Surfactant substances

Surfactants or surface active agents are chemical substances that concentrate at

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

Most common surfactants monomer consist of a hydrocarbon portion (nonpolar -

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

Classified according to the ionic nature of the head:

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

when dissolved in water.

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

and yield cations when dissolved in water.

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

do not ionize in water but provide characteristics similar to surfactants.

-

+

Surfactant substances

Anionic surfactants ionize in water into inorganic cations and hydrocarbon-

sulfonate anions.

As the surfactant concentration increases, several of the sulfonate anions combine

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

referred to as Micellar Floods.

Individual monomers Micelles

Surfactant Concentration

IFT

Critical Micelle Concentration(CMC)

Surfactant-water-oil phase behavior

Daerah

2 Fasa

Daerah

1 Fasa

Plait Point

Brine

Surfaktan

Minyak

Brine

Mikroemulsi

Type II+

Brine

Brine

Mikroemulsi

minyak

2 Fasa

Daerah

1 Fasa

Surfaktan

Minyak

2 Fasa

Daerah

3 Fasa

Type III

Daerah

2 Fasa

Daerah

1 Fasa

Plait Point

Brine

Surfaktan

Minyak

Minyak

Mikroemulsi

Type II-

Salinity increases

Optimal salinity

1.0E-04

1.0E-03

1.0E-02

1.0E-01

1.0E+00

IFT

(d

yne/

cm)

IFT mo

IFT mw

l u m

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

Vo/

Vs

atau

Vw

/Vs)

Vo/Vs

Vw/Vs

Kadar Garam (% Berat NaCl)

At optimal salinity:

Interfacial tensions are equal and

minimum

Solubilization parameters are equal

and maximum

Optimal salinity

Displacement efficiency is maximum at optimal salinity

0

10

20

30

40

50

60

70

80

90

100

0 0.4 0.8 1.2 1.6 2 2.4 2.8 3.2

Salinity, % NaCl

Dis

pla

ce

me

nt

Eff

icie

nc

y1.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

Inte

rfa

cia

l Te

ns

ion

, mN

/m

SalinityIncreasing

SalinityDecreasing

Surfactant retention

Surfactant anions get retained in reservoir rocks due to:

Adsorption on positively-charged surfaces

Reaction with divalent cations

Trapping of oil-continuous micro-emulsions

sls

slss Cb

Ca

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

Ad

so

rpti

on

, mic

ro g

-mo

le/g

cla

y

10% Co-surfactant

6% Co-surfactant

2% Co-surfactant

No Co-surfactant

Use of co-surfactants can reduce surfactant retention

Surfactant retention

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

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 20 24Clay Content, % wt

Su

rfac

tan

t Ret

entio

n, m

g/g

of R

ock Lab Data

Field Data

Lab data

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 3.5Salinity, % NaCl

Su

rfac

tan

t Ret

entio

n, m

g/g

of R

ock

Effect of Phase Trapping

Selecting suitable surfactant

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

Determination of surfactant retention

Determination of residual oil saturation

Surfactant slug volume required

Mass of surfactant required

Estimating RF from SP floods

References

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

Society of Petroleum Engineers Inc., USA.

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

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

Netherlands.

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

Engineers, Richardson, Texas, USA.

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

Metode 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 Field”,

The 1998 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., Kooping,

S., and James, C. Mack, 2006, “Successful Field Pilot of In-Depth Colloidal Dispersion Gel (CDG)

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

673.

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wfc 08 03 chemical flooding-concepts

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