chemical eor s2 1

8/9/2019 Chemical EOR S2 1

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Surfactant and SeMAR for EOR

By

Leksono MucharamFTTM ITB 2014


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IntroductionS

MAR (Solution by Chemical Modifier to EnhanceRecovery) is a special chemical modified toaccelerate recovery of oil fields. With a low

concentration in a system, SMAR has the ability toimbibe and alter the amount of energy on thesurface or interfacial layers of the system.

SMAR is also a wetting agent that takes part on

lowering the interfacial tension of a fluid and helpsdistribute the fluid on the rock surface.

Surfactant is Surface Active Agent. This chemical isable to lower IFT berween water and oil phases.


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Typical of Mature oil field

High water cut

Oil production decreases significantly

Water channel has been formed every wherein the reservoir.

Low pressure

Difficult to increase by conventional methods Remaining oil in place may range from 50 % to

90 %.


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December, 11-12 , 2009

E O RMethods

Thermal Flooding

CO2 Flooding

Gas Injection

Chemical Flooding

Others

SCREENING OF EOR

METHODS

Reservoir Depth

Cost

Availability

Reservoir Temperature

Reservoir Pressure

Oil Properties

Limitations


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Oil

Traped

Water Channel

Oil Trapped in the tigher

porosity reservoir

Oil

Mature Oil Field


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EOR

The primary goals in reservoir EOR operations are to

displace or mobilize more remaining oil from existing

formations than can be achieved using conventional

waterflooding techniques. Remaining oil left in reservoirs

after long-time recovery operations is normally

discontinuously distributed in pores. From the view point of

fluid flow mechanics, there are two main forces acting on

residual oil drops: viscous and capi l lary forces. In

capi l lar ly force, not only size of pore, this also

inc ludes adhession force between sol id su rface (rock

propert ies) and l iqu ids.


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Advantages of SeMARSeMAR is new paradigm Chemical for Reservoir Performance Improvement,

because not Classified as Surfactant or Polymer

SeMAR

Cost

effective

at low oil

price

Proven for a

wide range of

reservoirconditions

Sandstone or

carbonatereservoirs; oil-

or water-wet

Unaffected

by high

salinity

Based on

both low IFT

and

wettability

alteration

Tailor-made

products

derived from

extensive labtesting

Resistant to

high temps.


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SeMAR

Improvement oil recovery & Reservoir

Performance by chemical means

How it works

Improve imbibition by:

Change wettability of reservoir rock to become

more water wet or totally water wet

Significantly reduce capillary pressure, thereby

releasing energy to allow movement of fluids Improve flow performance in reservoir by

means of visco-modification phenomena in

water channels


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Origins of SeMAR Indonesia has long history of oil exploration & production and

technological innovation in the industry

Academic research stimulated by declining domestic oilproduction in Indonesia and general lack of success withconventional chemical EOR technology

Research took a holistic approach to modifying reservoirfluid parameters in situ Imbibition (wettability and capillarity)

Visco-emulsion (block water channels)

Mobilize and sweep unswept oil

Extensive lab testing and innovative chemical formulations

SeMARsuccessfully applied in a variety of reservoirsituations Depleted oil fields (high water cut; low fluid influx)

Oil-wet carbonate reservoirs

Highly heterogeneous reservoirs

Wide ranges of oil gravity, oil viscosity, water salinities and reservoirtemperatures


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Capillary pressure (Pc)controls

initial fluid saturation distribution in

equilibrium situations

Wettabilitycontrols value of Pcand

relative permeability curves to a

large extent

Relative permeability (Kr)controls

fractional flow character when

coupled with fluid viscosity data inmultiphase flow

Interfacial tension (IFT)only

controls degree of (im)miscibility of

fluid phases

Fluid-Rock PropertiesReservoir performance primarily impacted by four

fundamental reservoir/fluid characteristics


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Swr(ior)

= 1Sor(ior)

Change in Sw (%)

Pc

0.0

Free imbibition process

Free imbibition theory

( +)

( -)

Drainage

processImbibition

process

Swi1 2 3

Legend

Pc = Capillary pressure

Sw = Water saturation

Swi = Initial water

saturation

Swr(ior)= Residual watersaturation after Improved

Oil Recovery (IOR) at

maximum Pressure-

Volume (max PV)

Sor(ior)= Residual oil

saturation after IOR at

max PV

Explanatory Notes

1= Change in Sw Max due to

imbibition of water at ambient

atmospheric pressure


imbibition of wetting chemical

(SurPlus) at ambient atmospheric

pressure


imbibition of wetting chemical

(SurPlus) at reservoir pressure

(Swr(ior)= 1Sor(ior))


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EOR

From the view point of fluid flow mechanics, there are two

main forces acting on residual oil drops: v iscous and

capi l lary fo rces. In capi l lar ly fo rce, no t on ly size of

pore, this also inc ludes adhession force between sol id

su rface (roc k p ropert ies) and l iqu ids.

= Pc


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Wettingand Non-WettingA general term referring to one or more of the

following specific kinds of wetting: adhesional wetting,

spreading wetting, and immersional wetting. It is

frequently used to denote the contact-angle betweena liquid and a solid is essentially zero where there is

spontaneous spreading of the liquid over the solid.

Nonwetting, on the other hand, is frequently used to

denote the case where the contact angle is greater

than 90o, so that the liquid rolls up into droplets.


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OW

WSOS

Water

Rock Surface

Wettability of Oil-Water-Solid

System

OIL Angle


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lFT, methane/n-pentane systems at 100 oF


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OILWATER

Non-Wetting

Phase Wetting Phase

Sand Stone

wo

Interfacial Tension

Between Water and Oil

WETTING AND NON-WETTING PHASES


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Oil phase will be displaced spontaneouslyfrom the tube if the pressure of the oil

phase is reduced, even though the

pressure in the water phase is less than

the pressure in the oil phase.

PO PW

PO PW>


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By petroleum engineering convention,

the capillary pressure is po pW for

oil/water systems. Thus PC is negative

for an oil-wet surface.

PO PW

PO PW>


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cos2

p-p

thatso,cos-:Note

)-(2p-p

0r)(2-)r(p-r)(2)r(p

nwwwnw

wsnws

wsnwswnw

nws2

wws2

nw

r

r

nww

qs

qsss

ss

psppsp

=

=

=

=+

Pnw Pw


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When two immiscible phases are placed in

contact with a solid surface, one of the phases is

usually attracted to the surface more strongly

than the other phase. This phase is identified as

the wetting phase while the other phase is the

nonwetting phase.

WETTING PHASE


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DEGREE of WETTING

PHASE

Totally WettingNormal Wetting

Non WettingAbsolute Non Wetting

Stronger Wetting phase is related to lower contact angle

between liquid phase and the solid. Also, the lower contact

angle is related to stronger ability to imbibe non-wetting fluid.

This phenomena can be obtained by Spontaneous Imbibition

Test using Amott Imbibition Cell.


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Spreading

The tendency of a liquid to flow and form

a thin coating an interface, usually a solid

or immiscible liquid surface, in an attempt

to minimize interfacial free energy. Such aliquid forms a zero contact angle as

measured through itself.


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Spreading

1 2 3

4 5 6

7

Totally Wet


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The equation below describes the Young

equation, representing the force balance in the

direction parallel to the rock surface:

- = Cos


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CONTACT

ANGLE

Water Wet

Water

OIL

MINERAL

CONTACT

ANGLE

Oil Wet

Water

OIL

MINERAL


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Interfacial Contact Angles : (a) Silica Surface and (b) Calcite Surface


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Consider the oil/water interface in the horizontal glass

capillary tube in Figure above, which is at static equilibrium.Water strongly wets the glass surface with a contact angle

near zero.If sensitive pressure gauges were attached to each

end of the capillary tube to measure the water-phase

pressure and the oil-phase pressure, we would observe that

the oil-phase pressure is always larger than the water-phase

pressure, regard- less of the length of the tube. Water can be

displaced from the capillary tube by injecting oil into the

tube.

PO PW

PO PW>

Oil Water


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Oil will be displaced spontaneously fromthe tube if the pressure of the oil phase

is reduced, even though the pressure in

the water phase is less than the

pressure in the oil phase.

PO PW

PO PW>


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In petroleum engineering convention,

the capillary pressure is po pW for

oil/water systems. Thus PC is negative

for an oil-wet surface.

PO PW

PO PW>


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Capillary pressure characteristics, strongly water-wet

rock. Curve 1, drainage and Curve 2, imbibition.


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Oil/water capillary pressure characteristics,

Tensleep sandstone, oil-wet rock. Curve 1,

drainage and Curve 2, imbibition.

Oil/water capillary pressure characteristics,

intermediate wettability. Curve 1, drainage,

Curve 2, spontaneous imbibition, and Curve 3,

forced imbibition.


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Fluid distribution during

waterflood of water-wet rock


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Residual Oil Saturation (SOR)

The oil saturation that remains trapped in a

reservoir rock after a displacement process

is dependent on many variables. These

include wettability, pore size distribution,

microscopic heterogeneity of the rock, and

properties of the displacing fluid.


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Lets examining the characteristics of water-wet systems in

which oil has been displaced by water to a residualsaturation. It is assumed that the displacement process

occurs without bypassing, which has been attributed to

viscous fingering or rock heterogeneities.

The value of the residual oil saturation is important for

two reasons. First,it establishes the maximum efficiency for

the displacement of oil by water on a microscopic level.

Secondly, it is the initial saturation for EOR processes in

regions of a reservoir previously swept by a waterflood.

Value of SOR


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Fluid distribution during waterflood of

an oil-wet rock

The trapping process in uniformly oil-wet rock differs

from the process in uniformly water-wet rock. An oil film

surrounds the sand grains and is connected to smaller

flow channels. Oil flow persists at diminishing rates until

the smallest oil channels can no longer transmit fluid

under the prevailing pressure gradient.

Velocity = 1 2 ft/day

Flow Path

Trapped

Oil


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Fluid distribution during waterflood of

an oil-wet rockOil Trap

AreaWater

Channel

WaterOil


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Water Wet Water + 0.5 % Surfactant

Water Wet Water + 0.5 % SeMAR


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Totally Wet

SeMAROil Wet

In Horizontal Capillary Tube

RockRock

Rock

Rock

Oil Wet

SeMAR

SeMAR


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Water channel Water channelWater channel

Waterchannel

Waterchannel

Waterchannel

Waterchannel

Oil Trapped Oil

Rock

Oil Rock System Model


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Surfactant channel Surfactant channelSurfactant channel

Surfactant

channel

Surfactant

channel

Surfactant

channel

Surfactant

channel

Oil Trapped Oil

Rock



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Surfactant channel Surfactant channelSurfactant channel

Surfactant

channel

Surfactant

channel

Surfactant

channel

Surfactant

channel

Oil Trapped Oil

Rock


Oil Rock Reservoir Model


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Oil Rock Reservoir Model

Larutan Surfactant with ultra

low concentration

Low Porosity

Higher

Porosity


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Wettability is the next most important factor inwaterflood recovery after geology (Morrow, 1990).

The recovery efficiency of a flooding process is a

function of the displacement efficiency and sweep

efficiency. These efficiencies are a function of theresidual oil saturation (waterflood and chemical

flood) and mobility ratio, respectively. The

residual oil saturation to waterflooding is a

function of wettability with the lowest value atintermediate wettability (Jadhunandan and

Morrow, 1995).

RECOVERY EFFICIENCY IN WATER FLOOD

PROCESS


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Carbonate formations

Wettability alteration has received moreattention recently for carbonate formations

compared to sandstones because carbonate

formations are much more likely to be

preferentially oil-wet (Treiber, et al., 1972).

Also, carbonate formations are more likely to be

fractured and will depend on spontaneous

imbibitionor buoyancy for displacement of oilfrom the matrix to the fracture.

C b R i


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Carbonate Reservoir

Giants Carbonate

Fields in the

Middle East are:

Ghawar

Zakum

Kirkuk

Marun

North

P t h i l P ti f C b t


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Petrophysical Properties of Carbonate

Reservoir

A. Porosity and Permeability

Carbonate reservo irs are character ized

by extreme heterogeneity o f po ros i ty

and permeabi l i ty.

This is related to the complexi t ies of the

or ig inal depos i t ional env ironment andthe diagenet ic inf luences that can

mod ify the or ig inal textu res.

C S ti l Vi f Sli d


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Cross-Sectional View of Sliced

Carbonate Rock (contd)


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Model Pore Dimension

In 1950s, some

reservoir engineer

proposed complex

model of sinuous,constant cross

section flow tubes to

estimate fundamentalreservoir properties.


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Spontaneous Imbibition

Spontaneous imbibition is the process by

which a wetting fluid is drawn into a porous

medium by capillary action (Morrow andMason, 2001). The presence of surfactant

in some cases lowers the interfacial tension

and thus the capillary pressure to negligiblevalues.


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Hydrocarbons

Nonionics

Anionics

Cationics

Amphoterics

HEAD TAIL

SURFACTANT

SODIUM DODECYL BENZENE


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SODIUM DODECYL BENZENE

SULFONATE

CH2 CH2 CH2 CH2 CH2CH2 CH CH3CH3

SO3 Na+

HYDROPHILIC

HEAD

BENZENE RING

HYDROPHOBIC

TAIL

Anionics

SODIUM BENZENEExample :


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SODIUM BENZENE

SULFONATE

CH2 CH2 CH2 CH2 CH2CH2 CH CH3CH3

SO3 Na+ HYDROPHILICHEAD

BENZENE RING

HYDROPHOBIC

TAIL

OIL

Water

MICELLE


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MICELLE

OIL

Water

The Micelle are quite small and are

invisible to the eye. Indeed, the radius ofthe micelle is roughly the length of the

surfactantstail, which may range from 2

to 4 nm (10-12 m) = 0.000004 micron

Micellar solutions are often quitetransparent. They will easily pass through

most pores in sedimentary rock, so

micellar solutions can be injected as

treatment fluids.


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December, 11-12 , 2009

Formation

Water

ReservoirRock

Crude Oil

Fresh Water : vary in composition

Low Salinity, Medium Salinity and High Salinity

Mono valence and bivalence

Sand Stone ( - ), Carbonate ( + ), Shale,

Clay, Volcanic (+), Combination andmany other minerals rock

Oil Reservoir

Paraffinic Oil, Resin Oil, Light Oil,

Medium Oil, Heavy Oil, AsphalticOil, Asphalt.

Oil Wetting Reservoir System


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Water

ROCK GRAIN

ROCK GRAIN

OIL

OIL

After Chemical Injection

Channeling

Mi l i


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Microemulsion

Mix between oil and Surfactant solution


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Microemulsion

A special kind of stabilized emulsion in which the

dispersed droplets are extremely small ( < 100

nm) and the emulsion is thermodinamically

stable. These emulsions are transparent and

may form spontaneously. In some usage a lower

size limit of about l0 nm is implied in addition to

the upper limit.


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Macroemulsion

The term macroemulsion is

sometimes employed to identify

emulsions having droplet sizes

greater than a specified value, or

alternatively, simply to distinguish an

emulsion from the microemulsion or

micellar emulsion types.


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Spontaneous ImbibitionSpontaneous imbibition is the process by which a

wetting fluid is drawn into a porous medium bycapillary action (Morrow and Mason, 2001). The

presence of surfactant in some cases lowers the

interfacial tension and thus the capillary pressure to

negligible values. Spontaneous displacement bywetting surfactant (SeMAR) can still occur in this

case by buoyancy or gravity drainage (Schechter, et

al., 1994).

OilWater Wet

OilSeMAR


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W tt bilit Alt ti f Oil Ph


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Wettability Alteration of Oil Phase on a

Marble Plate


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The height of the retained oil in oil-wet matrix pores is a

function of the pore radius, IFT and contact angle.


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The IFT is a fundamental thermodynamic

property of an interface. It is defined as

the energy required to increase the areaof the interface by one unit.

IFT ( Interfacial Tension )


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Surface tension of paraflin hydrocarbons.23


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lFT, methane/n-pentane systems at 100 oF


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When two immiscible phases are placed in

contact with a solid surface, one of the phases is

usually attracted to the surface more stronglythan the other phase. This phase is identified as

the wetting phase while the other phase is the

nonwetting phase.

WETTING PHASE

S h ti Di f th S i i D A t


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Schematic Diagram of the Spinning Drop Apparatus


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Schematic Diagram of Capillary Tube and Epoxy Sealant

( Lyman Handy )


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Phase Behavior


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SCREENING OF EOR


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December, 11-12 , 2009

E O R

Methods

Thermal Flooding

CO2 Flooding

Gas Injection

Chemical Flooding

Others

METHODS

Reservoir Depth

Cost

Availability

Reservoir Temperature

Reservoir Pressure

Oil Properties

Limitations

SEVERAL SCREENING FOR


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SEVERAL SCREENING FOR

SURFACTANT SELECTION

1. Very Low adsorbtion (Not adsorbed by rock

surface). This will not be good for Spontaneous

Imbibition.

2. Very low (Ultra Low) concentration of

Surfactant

3. Not affected by themperature


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Surfactant Injection

SURFACTANT

Flood

HUFF & PUFF STEPS3000 bbls Chemical

Solution


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SOAKINGINJECTION PRODUCTION

1 - 5 days

HUFF PUFF

December, 11-12 , 2009

Solution

Volume of fluid required to beWell


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r h

injected = Vf into production well

or huff & puff well.

2f rh0.56bbls)(V =

Where :

h = net thickness of formation, ft

= avg porosity of rock, fractionr = radius of influence, ft

Q = liquid rate of the well, bbl/d

W = fluid velocity in reservoir, ft/D

hw

Q0.8937r =

Volume of the chemical to be injected

(Estimated )


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W ll C W ll D


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Well C Well D

Surfactant Huff & Puff in

a reservoir

Surfactant

Distribution

Surfactant

Distribution

W ll A W ll B


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Well A Well B


a reservoir

Non Symetrical

Distribution

Symetrical

Disribution

Well BWell A


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Well B


a reservoir

Non

Symetrical

Distribution

Well A

Non

Symetrical

Disribution

Well C Well D


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Well C Well D


a reservoir

Surfactant

Distribution

Surfactant

Distribution

Channeling


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Weak Water Drive

Production WellsHuff and Puff well

in a reservoir

Surfactant concentration

getting lower

Field Result of SMaR Implementation


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at Daleel Field Oman

Daleel field is located in Oman, Middle East. The oil is produced from carbonate

reservoir. The incremental oil gain is more than twice from the forecast baseline after

SeMAR injection using Huff and Puff Method.

DL-104 Performance


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0

100

200

300

400

500

600

DL 104 Performance

test_oil bbl/d

Oil Production Increases

DL 103 P f


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0

100

200

300

400

500

600

DL-103 Performance

test_oil bbl/d

Oil Rate

Start SurPlus

Injection

Oil Production

Increases


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0

100

200

300

400

500

600

DL-104 Performance

test_oil bbl/d

Start of SurPlus Injection


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Commonly Water

Wet Reservoirs

Commonly Mix Wetting

Reservoirs

Commonly Oil Wetting

ReservoirsCarbonate Oil

Reservoirs,

Heavy oil reservoirs


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0.0 0.1 0.2 0.3 0.4 0.50.6

0.

0

0.

1

0.

2

0.

3

0.

4

0.

5

Oil Recovery Factor of Water

Flooding or Natural Water Flooding

Potentialo

fOilRecovery

FactorFromS

urfactant

Flo

oding

I II III

Heavy oil reservoirs,

Resinics Oil

Reservoirs.


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Interfacial tension (ift) measurement

PHASE BEHAVIOR ANALYSIS

(TUBE TEST)


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February, 15 2010 PETROLEUM ENGINEERING

INSTITUTE OF TECHNOLOGY BANDUNG

(TUBE TEST)

Middle Phase ShowsMiscibility of DiluteSurfactant in Oil

Lower Phase, ShowsImmiscibility of

Surfactant in Oil

SurfactantSolution

Oil


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OIL Water

Imbibition Process

SeMAROIL

OIL

Surfactant

At CMC, a surfactant reaches the lowest IFT value


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Surfactant Concentration

CMC

IF

T

I F T

Micelle

Critical Micele Concentrations


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IFT

Surfactant Concentration

1 2 3

Start to form

middle phase

CMC

( Dynes / cm )

( % )

IFT < 1x10-3 merupakan Ultra

Low IFT Surfactant


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Thin Film of


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adsorbed

surfactantOIL

Silica Rock

Thin Film of

adsorbed

surfactantOIL

Silicate or

Carbonate Rock

Thin Film of


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adsorbed

surfactantOIL

Silica Rock

Thin Film of

adsorbed

surfactantOIL

Silicate or

Carbonate Rock

OIL Thin Film ofadsorbed

surfactant


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Silica

Rock

Silica

Rock


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Water

Chemical

Oil

Chemical

Water

Water

Oil

Oil

Closed

Closed

Closed

Closed

Open

Open

Open

Open

Oil

Capillary TubeCounter Flow

Phenomenon


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Water

Oil

Closed

Closed

Open

Open

Oil

Oil

WaterClosed Open

Oil

WaterClosed Open

Oil

Water

SeMAR

Water

Fracture Rock


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Fracture

Matrix

Fracture Rock 0.5 MicronMatrix


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Fracture

50 Micron


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Cross-Sectional View of Sliced


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Carbonate Rock

2 m

0.2 m

Matrix

Fracture

Rock



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Fracture

Matrix

50 Micron

SMR Fluids

Counter Current

Flow , Oil and the

Chemical


Test



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Fracture

Matrix

60 Micron

Counter Current

Flow , Oil and the

Chemical


Test

SMR Fluids

CORE +

OIL


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Imbibition Test results from cores

with only one top side is open.

SMR Fluids

CORE +

OIL


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Imbibition Test In Carbonate Core

IMBIBITION TEST RESULTS OF PARTIALLY OPEN CORE


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100

9080

70

60

50

40

30

20

10

00 5 10 15 20

25 Time, Days

OilRecovery(%)

SAMPLE

Core

Sample

One SideOpen Only

Formation water

Oil


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Soaking

120 min


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Results of Spontaneous Imbibition Test of Oil and Rock

from well # 135 at T = 60 C, Using Amott Imbibition Cell


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FREE

IMBIBITION


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Sw

(%)

Pc

0.0Free

Imbibition

( + )

( - )

Pc = Pnw - Pw


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Heavy Oil and Carbonate

Reservoirs


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Oil Viscosity Reduction

GLASS

SEMAR REDUCING OIL

VISCOSITY


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TUBE

OIL

OIL

OIL OIL

SEMAR

R

OIL

Capillary

OIL FLOW

VERY SLOW

OIL FLOW

VERY FAST


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0

200

400

600

800

1000

1200

0 20 40 60 80 100

avg,cp

% oil

SeMAR Concentration 2%

90 C

80 C

70 C

Semar Reducing

Heavy Oil Viscosity

800

1000

1200

cp



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0

200

400

600

800

1000

1200

0 20 40 60 80 100

avg,cp

% oil

90 C

80 C70 C

0

200

400

600

800

0 20 40 60 80 100

avg,c

% oil

90 C80 C

70 C



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73.14

75.14

79.94

68

70

7274

76

78

80

82

avg,cp

S16A 2% S16A 3% S16A 4%

API 17

Imbibition test on Heavy Oil with API 17


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0

1

2

3

4

5

6

7

8

9

0 2 4 6 8 10 12 14 16

%O

ilRecovery

Soaking Time (Day)

Formation

Water (KS-

18)

Sea Water

(KS-4)

S16A 0.5%

(KS-1)

S16A 1%

(KS-3)

8 X

API = 17Imbibition test on Heavy Oil with API = 17

140

Viscosity of Mixture, Oil and SEMAR S28A (0.5%)

Z-Field B - Field

253 CP


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135

10 20 30 40 50 60 70 80 90 1000

20

40

60

80

100

120

0

% Volume of Oil

Viscosity

ofMix(cP)

114 CP

76 CP

MIXTURE SEMAR AND OIL

350

Viscosity of Mixture, Oil and SEMAR S28A (0.5%)

Z-Field


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136

10 20 30 40 50 60 70 80 90 1000

50

100

150

200

250

300

0

% Volume of Oil

114 CP

Viscosity

ofMix(cP) Brine + Oil

SEMAR + Oil


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using Thermal


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138

144cp

2 cp

Temperature, C

60 C 300 - 350 C

Viscosity,

cp

using Thermal

P = 14.7 psi

Semar


using SEMAR and Thermal

253

cp


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139

144cp

2 cp 2 cp

Temperature, C

70 C 300 - 350 C

SEMAR

Viscosity,

cp

using SEMAR and Thermal

P = 14.7 psi

78

cp

p


140/199

OIL RECOVERY SUMMARY

F C Fl d T


141/199

141

Core Flood

Total

Incremental Oil

Recovered ( % )

Total RecoveryFactor ( % ),

including water

flood / drive

Core Flood # 1

SEMARS28A* 0.5 %47 98

Core Flood # 2

SEMARS28A 0.5 %45 96

From Core Flood Test


142/199

SeMar Injection in Carbonate Oil Reservoir

SeMar Core-Flood in OilCarbonate core


143/199

PV Injected

RecoveryFactor

(%)

23%

Water Injection

0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0

Soaking


144/199


145/199

220

230

240

250

ARAHAN - BANJARSARI OIL GAIN

BS

Field AB


146/199

0

10

20

30

40

50

60

70

80

90

100

110

120

130

140

150

160

170

180

190

200

210

Jan-09 Feb-09Mar-09 Apr-09 May-09 Jun-09 Jul-09 Aug-09 Sep-09 Oct-09 Nov-09 Dec-09 Jan-10 Feb-10 Mar-10 Apr-10 May-10 Jun-10 Jul-10 Aug-10 Sep-10 Oct-10 Nov-10 Dec-10

BOPD

DATE

AR

TOTAL OIL GAIN SINCE1/5/09 UNTIL 31/12/10 =

64,243 BBL OIL

BASELINE

Start S-13A*

Injection


147/199

Is the project economically viable?


148/199

HUFF & PUFF STEPS

HUFF PUFF

3000 bbls Chemical

Solution


149/199

SOAKINGINJECTION PRODUCTION

1 - 5 days

PUFF

December, 11-12 , 2009

W ll

WellNo water

channeling


150/199

SOAKING PROSES

SURROUNDING

WELL

Well

Water

Chanelling

December, 11-12 , 2009

Surfactant Injection in

Homogeneous Reservoir


Heterogeneous Oil Reservoir


151/199

December, 11-12 , 2009

So = 60 %

So = 40%

20%

So = 60 %

So = 40%

20%

Production WellInjected Surfactant


Homogeneous Reservoir


Heterogeneous Oil Reservoir


152/199

December, 11-12 , 2009

So = 60 %

So = 40%

20%

OIL

OIL

Injected

Surfactant

Water

ChannelFluid Flow in

Mature Field


153/199

December, 11-12 , 2009

OIL

Production

Well

OIL

Heterogeneous Oil

Reservoir


154/199

December, 11-12 , 2009

Injected

Surfactant

OILOIL

Production

Well


155/199

FLOODING


156/199

Oil Recovery Factor of EOR Surfactant

S f t t Fl di1 X %


157/199

Surfactant Flooding

Surfactant FloodingWater Flood



1

2

3

4

X %

No Good WF

Very good WF

Producer Well

Water Flooding


158/199

Un-swept Area

Un-swept Area

Trapped Oil

Water

Injection Well

Swept Area

In Swept Area, trapped

oil can not be displaced

by water, however it

could be released and

flowed by injecting

surfactant.

25 %

Sor

Producer Well

Surfactant Flooding


159/199

Un-swept Area

Un-swept Area

Trapped Oil

Surfactant

Injection

Well

Swept Area




could be released and

flowed by injecting

surfactant. In addition tothat, surfactant flood

can improve swept

areal by stripping out oil

zone close by.

25 %

SOR

Producer

Well

Water Flooding in

Medium Oil

Producer

Well

Water Flooding in

Heavier Oil


160/199

WaterInjection

Well

Un-sweptArea

Un-swept

Area

Trapped Oil

Swept Area

WaterInjection

Well

Un-sweptArea

Un-swept

Area

Trapped Oil

25 %

Producer

Well

Surfactant Flooding in

Medium Oil

Producer

Well

Surfactant Flooding in

Heavier Oil


161/199

SurfactantInjection

Well

Un-sweptArea

Un-swept

Area

Trapped Oil

Swept Area

SurfactantInjection

Well

Un-sweptArea

Un-swept

Area

25 %

Trapped Oil

SWEEP EFFICIENCY


162/199

ON INJECTION PATTERN

Between RF versus Cost

(economics concern)

Well Injection Pattern

5 - spot 7 - Spot


163/199

Producer

Injector

5 spot 7 Spot

Injector

Producer

Surfactant / Water Injection

Pattern


164/199

7- SPOT 5-SPOT

Swept

Area

Swept

Area

Unswept

Unswept

Unswept

Unswept


165/199

OIL OILRF = 35 % RF = 25 %

The Injected Surfactant FlowsThrough

Water Channeling


166/199

December, 11-12 , 2009

OIL OIL

OIL

RFWF= 35 %

RFSUR= 12 %

RFWF= 25 %

RFSUR= 17%

RF = 17 %

RF = 22 %

RF = 10 %

RF = 27 %

OIL


167/199

OIL RECOVERY BY STRIPPING

Production

Well


168/199

OIL

STRIPPING

Injection

Well


169/199

Core of

Reservoir Rock

Stripping Phenomenon


170/199

sand

Rock Surface

SURFACTANT OIL OIL

Oil

Sand

Fluid

Flow

Sand

Surfactant Injection Flow

through Water channels in

ProductionWell


171/199

a Mature Oil Reservoir

Injection

Well

Oil

Channel

WaterChannel

In this phenomenon,

oil phase is stripped

by the surfactant and

then it is flown to theproduction well.

Producer Well

Water Flooding


172/199

Un-swept Area

Un-swept Area

Trapped Oil

Water

Injection Well

Swept Area




could be released andflowed by injecting

surfactant.

25 %

Sor

5-Spot Injection

Pattern


173/199


174/199


175/199

Relation Between RF Water Flood VS RF Surfactant


176/199

RecoveryFactorSurfactan

t

Recovery Factor of Water

Flood

Seven Spots Pattern

Five Spots Pattern


177/199


178/199

Surfactant Injection Pattern


179/199

7- SPOT 5-SPOT

Swept

Area

Swept

Area

(a) Oil properties, (b) Rock Properties ( c )

Geometry of the reservoir, (d) Injected Fluid, (e)

Injection rate, (f) formation water properties.

Factor affecting Sweep eff:

Water Channeling due to WaterFlooding Implementation

OIL OIL

Heterogeneity Effect


180/199

OIL

OILOIL

Swept AreaSwept Area

One Quarter of 5-Spot

Pattern

OIL OILRFWF= 35 % RFWF= 25 %

The Injected Surfactant FlowsThroughWater Channeling


181/199

December, 11-12 , 2009

OIL

RFSUR= 12 % RFSUR= 17%

RF = 17 %

RF = 22 %

RF = 10 %

RF = 27 %

OIL


182/199

OIL RECOVERY BY STRIPPING


183/199


184/199

Well pattern pada reservoir

yang sama.A


185/199

Well Spacing 40 Acres


Jika tekanan reservoir

sama, apakah PI nya sama?

B


yang sama.


186/199


yang sama.A


187/199





B

Swept Area


yang sama.A


188/199





B

Swept Area

5-Spot


189/199

9-spot

7-Spot

4-Spot

5 SPOT

PATTERN


190/199

Injector

Producer

5 SPOT

PATTERN


191/199

5 SPOT

PATTERN


192/199

5 SPOT

PATTERN


193/199

5 SPOT

PATTERN


194/199

1

2

9 SPOT PATTERN


195/199

80.00

100.00

WCT-90%

98 00

99.00

100.00

WCT-90%


196/199

0.00

20.00

40.00

60.00

0 1 2 3 4

RF,%

PoreVolume

94.00

95.00

96.00

97.00

98.00

0 200 400 600

RF(

%)

Rate Injeksi Surfaktan, bbl/D

Rate Injeksi Surfaktan

(bbl/D)RF (%)

200 95.00

240 96.30

300 97.00

400 98.50

500 99.00

TriangleHorizontal

wells


197/199

1


198/199

2

3

4

5


199/199

6

7

chemical eor s2 1

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