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
2= Change in Sw Max due to
imbibition of wetting chemical
(SurPlus) at ambient atmospheric
pressure
3= Change in Sw Max due to
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
non- wetting 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
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
Oil Rock System Model
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
non- wetting 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
Surfactant Huff & Puff in
a reservoir
Non Symetrical
Distribution
Symetrical
Disribution
Well BWell A
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Well B
Surfactant Huff & Puff in
a reservoir
Non
Symetrical
Distribution
Well A
Non
Symetrical
Disribution
Well C Well D
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Well C Well D
Surfactant Huff & Puff in
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
Fracture Rock 0.2 MicronMatrix
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Fracture
Matrix
50 Micron
SMR Fluids
Counter Current
Flow , Oil and the
Chemical
Spontaneous Imbibition
Test
Fracture Rock 0.2 MicronMatrix
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Fracture
Matrix
60 Micron
Counter Current
Flow , Oil and the
Chemical
Spontaneous Imbibition
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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Results of Spontaneous Imbibition Test of Oil and Rock
from well # 135 at T = 60 C, Using Amott Imbibition Cell
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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
SeMAR Concentration 2%
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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
SeMAR Concentration 3%
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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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Oil Viscosity Reduction
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
Oil Viscosity Reduction
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
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OIL RECOVERY SUMMARY
F C Fl d T
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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
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SeMar Injection in Carbonate Oil Reservoir
SeMar Core-Flood in OilCarbonate core
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PV Injected
RecoveryFactor
(%)
23%
Water Injection
0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0
Soaking
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220
230
240
250
ARAHAN - BANJARSARI OIL GAIN
BS
Field AB
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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
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Is the project economically viable?
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HUFF & PUFF STEPS
HUFF PUFF
3000 bbls Chemical
Solution
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SOAKINGINJECTION PRODUCTION
1 - 5 days
PUFF
December, 11-12 , 2009
W ll
WellNo water
channeling
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SOAKING PROSES
SURROUNDING
WELL
Well
Water
Chanelling
December, 11-12 , 2009
Surfactant Injection in
Homogeneous Reservoir
Surfactant Injection in
Heterogeneous Oil Reservoir
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December, 11-12 , 2009
So = 60 %
So = 40%
20%
So = 60 %
So = 40%
20%
Production WellInjected Surfactant
Surfactant Injection in
Homogeneous Reservoir
Surfactant Injection in
Heterogeneous Oil Reservoir
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December, 11-12 , 2009
So = 60 %
So = 40%
20%
OIL
OIL
Injected
Surfactant
Water
ChannelFluid Flow in
Mature Field
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December, 11-12 , 2009
OIL
Production
Well
OIL
Heterogeneous Oil
Reservoir
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December, 11-12 , 2009
Injected
Surfactant
OILOIL
Production
Well
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FLOODING
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Oil Recovery Factor of EOR Surfactant
S f t t Fl di1 X %
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Surfactant Flooding
Surfactant FloodingWater Flood
Surfactant FloodingWater Flood
Surfactant FloodingWater Flood
1
2
3
4
X %
No Good WF
Very good WF
Producer Well
Water Flooding
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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
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Un-swept Area
Un-swept Area
Trapped Oil
Surfactant
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. 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
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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
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SurfactantInjection
Well
Un-sweptArea
Un-swept
Area
Trapped Oil
Swept Area
SurfactantInjection
Well
Un-sweptArea
Un-swept
Area
25 %
Trapped Oil
SWEEP EFFICIENCY
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ON INJECTION PATTERN
Between RF versus Cost
(economics concern)
Well Injection Pattern
5 - spot 7 - Spot
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Producer
Injector
5 spot 7 Spot
Injector
Producer
Surfactant / Water Injection
Pattern
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7- SPOT 5-SPOT
Swept
Area
Swept
Area
Unswept
Unswept
Unswept
Unswept
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OIL OILRF = 35 % RF = 25 %
The Injected Surfactant FlowsThrough
Water Channeling
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December, 11-12 , 2009
OIL OIL
OIL
RFWF= 35 %
RFSUR= 12 %
RFWF= 25 %
RFSUR= 17%
RF = 17 %
RF = 22 %
RF = 10 %
RF = 27 %
OIL
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OIL RECOVERY BY STRIPPING
Production
Well
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OIL
STRIPPING
Injection
Well
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Core of
Reservoir Rock
Stripping Phenomenon
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sand
Rock Surface
SURFACTANT OIL OIL
Oil
Sand
Fluid
Flow
Sand
Surfactant Injection Flow
through Water channels in
ProductionWell
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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
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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 andflowed by injecting
surfactant.
25 %
Sor
5-Spot Injection
Pattern
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-
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Relation Between RF Water Flood VS RF Surfactant
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RecoveryFactorSurfactan
t
Recovery Factor of Water
Flood
Seven Spots Pattern
Five Spots Pattern
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Surfactant Injection Pattern
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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
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OIL
OILOIL
Swept AreaSwept Area
One Quarter of 5-Spot
Pattern
OIL OILRFWF= 35 % RFWF= 25 %
The Injected Surfactant FlowsThroughWater Channeling
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December, 11-12 , 2009
OIL
RFSUR= 12 % RFSUR= 17%
RF = 17 %
RF = 22 %
RF = 10 %
RF = 27 %
OIL
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OIL RECOVERY BY STRIPPING
-
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Well pattern pada reservoir
yang sama.A
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Well Spacing 40 Acres
Well Spacing 60 Acres
Jika tekanan reservoir
sama, apakah PI nya sama?
B
Well pattern pada reservoir
yang sama.
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Well pattern pada reservoir
yang sama.A
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Well Spacing 40 Acres
Well Spacing 60 Acres
Jika tekanan reservoir
sama, apakah PI nya sama?
B
Swept Area
Well pattern pada reservoir
yang sama.A
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Well Spacing 40 Acres
Well Spacing 60 Acres
Jika tekanan reservoir
sama, apakah PI nya sama?
B
Swept Area
5-Spot
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9-spot
7-Spot
4-Spot
5 SPOT
PATTERN
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Injector
Producer
5 SPOT
PATTERN
-
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5 SPOT
PATTERN
-
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5 SPOT
PATTERN
-
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5 SPOT
PATTERN
-
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1
2
9 SPOT PATTERN
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80.00
100.00
WCT-90%
98 00
99.00
100.00
WCT-90%
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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
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1
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2
3
4
5
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6
7