Presentasi-surfactant Flooding Carbonate Reservoirs

8/11/2019 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.

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Presentasi-surfactant Flooding Carbonate Reservoirs