Presentasi-surfactant Flooding Carbonate Reservoirs
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Transcript of Presentasi-surfactant Flooding Carbonate Reservoirs
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SURFACTANT FLOODINGCARBONATE RESERVOIRS
WENY ASTUTI 22213038
NIA SETYA B. 22213045
RIMA DINIATUL H. 22213062
KAPITA SELEK
Wilton T. Adams and Vernon H. Schievelbein
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Outline
IntroductionSurfactant Formulation
Laboratory Operation
Field OperationResult
Conclusion
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INTRODUCTION
West texas carbonate reservoirs contain vast amounts of res
It consists of dominantly a micritic limestone containing little Characteristic reservoir :
The formation is located about 5000 ft (1500 m) below th
Formation thick is about 100 ft (30 m)
Reservoir temperature is 109oF (43oC)
Horizontal permeability is 1-25 mD (Average 5,9 md)
Average porosity is 12 % (Range from 818%)Oil viscosity is 1.29 cp (1.29 mPa.s)
Oil gravity is 31.4 Oapi (0.87 g/cm3)
FVF is 1,14
Original formation water is 220000 ppm total dissolved so
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SURFACTANT FORMULATION
Nonemulsion formulation contain 1.5 % (wt/vol) solubilize
and 3.5% witco petroleum sulfonates. Solubilizer A is alky
sulfates.
Emulsion formulation contains 1.46% solubilizer B, 3.6%
petroleum sulfonates, 0.95% synthetic sulfonate, 4% gas o4% slaughter crude. Solubilizer b is alkylaryl ether sulfates
Both formulation were designed to tolerate the high salinity
divalent ion environment of the slaughter reservoir.
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LABORATORY OPERATION
Using core with 24 in long and 2 in in diameter
Brine permeability of clean cores ranged from 10
Porosity from 0.18 to 0.19%
Irreducible oil saturation usually 0.3 to 0.32%
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Oil Saturatio
reduce from 0.07 and RF
Non Emulsio
formulation S
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Oil Saturatio
reduce from and RF is 70
Emulsion for
Slug
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TWO WELL TEST OBJECTIVES
Purpose :
to define better oil recovery potential of chemical floods
carbonate matrix
Evaluating the two well test pattern for simplified field ch
flood evaluation Evaluating a biopolymer product that was new to the ind
Evaluating isopropyl alcohol (ipa) as a tracer
Evaluating the concept of preblending surfactant compo
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TEST SITE
- Injection Pressure max 1500
psi
- Permeability is 25 mD
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PV is obtained from :
- In house potential flow modelthat provides streamlines
- Arrival times
- Associated PV assuming
constant flowwrates
- Uniform Pay Thickness- Unit mobility
- No fluid movement to or from
other intervals
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First well pair ( Wells C1 and E2) :
9900 bbl
Second well pair ( Wells G1 and
E1) :
12000 bbl
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FIELD OPERATION
First Well-Pair Test (Wells C1and E2)
April 24, 1981
Bob-Slaughter-Block Brine
injection into well C1
June 27, 1981 340 ppm of thiocynate
tracer was injected
August 26, 1981
Emulsion formulation was
injected
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There was a decline in
injection rate with the
constant 1500 psi (10.3 Mpa)
Oct 1981, a hot water flush,followed by a short shut in
and backflow was done.
The decline in injection rates
was caused by an imbalance
between the higher viscosity(8-20 cp) of surfactant
solution and the increase in
water relative permeability
because of oil mobilization
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Feb 13, 1982
Average 75 bbl/d of
surfactant had beeninjected over 171 days
March1982
Filter catridges were
replaced
An injection solution batchMarch and part of a batch at
the end of May were
discarded due to bacterial
contamination at the surface
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In late April 1982
Polymer injection had
declined to only 40 b/d and
concluded on July 16, with
average 40 b/d over 146days.
In mid August 1982
Workover was performed due
to the injection rates did not
increase as expected after
the injection switch to fresh
water
Dec 5, 1982
Injection of postpolymer
tracer slug of thiocyonate
was begun and concluded
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Freshwater Injection
continued until Nov 8,1983
About 1.000.000 bbl of
water had been injected
since the end of
polymer slug Injection was switched to
field brine
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Second Well-Pair Test (Well G1
and E1)
April 21, 1981Brine injection into Well G1
began
July 1981
Pretest thiocyanate tracer
injection began for 24 days atan average rate 131 b/d
A long period water injection
During 350 days period, about
68.500 bbl of brine were
injected at average rate about
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30 July 1982
Injection of Nonemulsionsurfactant system began. Slug
was limited about 5000 bbl
Late September 1982
Surfactant injection was
concluded after injecting 5058bbl over 61 days at an
average rate of 83 b/d
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Oct 1, 1982
Polymer injection began,
accompanied by isopropanol
as a tracer. Polymer solution
were injected about 3700 bbl
at an average rate of 71 b/d
over 45 days
Freshwater injection continued
after the end of the polymer slug
until January1983.
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Jan 6, 1983
A 3800 bbl slug of thiocyanate
tracer was started and
continued for 19 days at an
average rate of 200 b/d.
Then followed by fresh water
injection until November 1982
Injection was switched to brine
More than 50,000 bbl [8000 m3]
of water have been injected
intoWell G-I since the end of
polymer injection
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RESULT
Matching :
Pre flood thiocyanatetracer
Oil Recovery
Calculation
RecoveryEfficiency
Sweep Efficiency
Retention
Estimate
PV(initial estimation is
from potential flow
model)
Computer simulatorIntercomp CFTE
chemical flooding
Simulator
Depend on
Swept area oil saturatio
Calculated us
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FIRST WELL PAIR TEST
Pre-surfactant tracer recovery was good (78.7%)
Good reservoir interval isolation
Good pattern containment
Ethanol is tracer for emulsion surfactant system
Ethanol recovery (97%), all surfactant entered the app
layer
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Surfactant recovery was 65%
Surfactant was retained by various mechanism
adsorbtion and partitioning into the oil unrecovered f
the swept volume
Polymer recovery was high (55%)
Polymer sample did noy show any evidence of
biological, oxidative, or shear degradation
Isopropanol was good tracer for polymer solution Indicator of polymer sweep efficiency
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Response to surfactant at Well E2 was prompt
1 week the oil cut had risen on surfactant and trace
detectable in produced fluids
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During the period preciding
surfactant injection,
a constant 1.3%
waterflood oil cut was
assumed
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PV calculated was 9651 bbl (the
best estimation)
Used to calculate recoveryefficieny and retention
Based on laboratory core flood
and previous experience in the
field
Oil saturation was assumedto be 32%
Target reservoir oil volume
3088 bbl
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SECOND WELL PAIR TEST
Tracer recovery were good but not complete/
Surfactant was traced with Iodide ion, which was not
by any non-emulsion system component.
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Surfactant, tracer and oil response at Well E-1 were dela
more gradual compared with the emulsion-system test.
This could be the result of larger PV in the non-emulsio
pattern and poorer confinement to the interval.
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Calculated PV was a
little under 14000 bbl.
(Not much confidence)
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CONCLUSIONS
Both surfactant formulations recovered very significaof oil from the dolomite reservoir.
The concept of using well pairs for surfactant system
to gain performance and scale-up data was tested.
Tests with multiple-component surfactant formulation
greatly facilitated and made more reliable if componeconcentrates are pre-blended at chemical blending p
before shipment and final dilution in the field.
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CONCLUSION
A commercial biosacharide was an effective mobilityagent in this low-permeability carbonate matrix.
Isopropanol and ethanol are good tracers.