aspek laboratorium untuk menunjang perencanaan water flooding dan water flooding improvement

8/3/2019 ASPEK LABORATORIUM UNTUK MENUNJANG PERENCANAAN WATER FLOODING DAN WATER FLOODING IMPROVEMENT

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ASPEK LABORATORIUM UNTUK

MENUNJANG PERENCANAAN WATER FLOODING

DAN WATER FLOODING IMPROVEMENT

Workshop : Bandung, 2 Desember 2009

Prepared by : LEMIGAS - Water Flood Team

Research and Development Centre For Oil and Gas Technology

LEMIGAS

JL. CILEDUG RAYA, CIPULIR, KEBAYORAN LAMA JAKARTA 12230 , PO. BOX 1089 JAKARTA 10010PHONE : 021-7394760, 7394422 (7 LINES) Ext. 1427, FAX : 021-7222978 1


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CONTENTS

I. INTRODUCTION

1.1 Background

1.2 Objective

II. PROCEDURE, RESULTS and DISCUSSIONS

2.1 Source of samples

2.2 Core analysis (basic parameters)

a. Permeability, porosity and descriptions

b. Pore throat distribution

2.3 Crude oil analysis

2.4 Water analysis and other properties 2


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2.5 Determination of injection water quality.

a. Compatibility or not between injection water (IW)

with formation water (FW) ?

b. Scaling problem ?

c. Emulsion block problem ?

d. Bacteria problem ?

e. Dissolved oxygen problem?

f. Corrosion problem ?g. High total suspended solids concentration

and high relative plugging index value ?

CONTENTS (Continued)

3


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2.6 Problem solving.

a. Incompatible water IW with FW

b. Scaling problem

c. Emulsion block problem

d. Bacteria problem

e. Dissolved oxygen problem

f. Corrosion problem

g. High total suspended solids concentration

and high relative plugging index value

4


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2.7 Water Rock Compatibility Tests

2.8 Water Flooding Laboratory Tests

III. CONCLUSIONS

5


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6

I.1 Background

a. The decrease of oil production.

b. The cumulative oil production has approached

ultimate primary recovery.

I.2 Objective

To set up scope of works based on standard operational

procedure (SOP), which are specially focused on complete

water, crude oil & core analysis, determination of injection

water quality (before and treatment), rock compatibility and

water flooding laboratory tests

I. INTRODUCTION


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Difference of water quality

Figure - 2.1 Source of samples

IW3

Water - GS River water River water Formation waterProduced water


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Nama Sumur

Nomor Sampel

Kedalaman (ft)

: I - 38

: 6B

: 3160.05

Length, cmDiameter, cmAcre, cm

2

Bulk Volume, ccCore Weight, grGrain Volume, ccPore Volume, cc, (measured)Air Permeability, mDPorosity, %Grain density, gr/cc

= 5.740= 3.800= 11.335= 65.098= 131.415= 49.326= 15.772= 152.400= 24.228= 2.664

SD : Gy,hd, vf-fg, sbang-sbrnd,mod-w srtd, qtz, slimica, v sli arg, sli/loc calc

Nama Sumur

Nomor Sampel

Kedalaman (ft)

: I - 38

: 7A

: 3166.46

Length, cmDiameter, cmAcre, cm

2

Bulk Volume, ccCore Weight, gr

Grain Volume, ccPore Volume, cc, (measured)Air Permeability, mDPorosity, %Grain density, gr/cc

= 5.400= 3.800= 11.335= 61.242= 121.611

= 45.944= 15.298= 37.130= 24.979= 2.647

SD : Gy-ltbrn, hd, vf-mg, sbang-sbrnd,mod srtd, qtz, slimica, v sli arg

No. Well Depth Perm. Porosity(feet) (mD) (%) < 0.1 mm < 0.1 - 10 mm > 10 mm

6B I # -38 3160.05 37.13 24.979 17 41 28

7A I # -38 3166.46 152.4 24.228 18 38 42

Pore size distribution, % PV

Figure 2.2 Core Analysis (basic parameter)

Table 2.2 Pore Size Distribution


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9

Tabel 2.2 Oil Hydrocarbon Compositional Analysis

CRO-1, Wt % CRO-3, Wt %

Methane CH4 0.0000 0

Ethane C2H6 0.0221 0.0084

Propane C3H8 0.1629 0.0319

i-butane C4H10 0.1274 0.0359

n-butane C4H10 0.2883 0.0772

i-pentane C5H12 0.4006 0.112

n-pentane C5H12 0.3951 0.1172

Hexanes C6H14 0.9419 0.5074

Heptanes C7H16 1.8162 1.8433

Octanes C8H18 7.3997 4.971

Nonanes C9H20 4.0547 5.9202

Decanes C10H22 3.5969 4.3084

Undecanes C11H24 5.0572 5.3594

Dodecanes C12H26 4.0538 5.2628

Tridecanes C13H28 6.8126 6.1243

Tetradecanes C14H30 5.8682 7.9412

Pentadecanes C15H32 5.8547 7.001Hexadecanes C16H34 5.7156 4.8043

Heptadecanes C17H36 4.3576 4.8512

Octadecanes C18H38 5.6688 5.2039

Nonadecanes C19H40 3.8111 3.3483

Eicosanes C20H42 2.9937 2.614

Heneicosanes C21H44 3.3151 2.6758

Docosanes C22H46 3.1308 2.5965

Tricosanes C23H48 2.8668 2.3238

Tetracosanes C24H50 2.7796 2.4395

Pentacosanes C25H52 2.7294 2.2876

Hexacosanes C26H54 2.5015 2.2254

Heptacosanes C27H56 2.4867 2.2204

Octacosanes C28H58 2.2560 2.2989

Nonacosanes C29H60 2.3316 2.1825

Triancontanes C30H62 2.1221 2.1124

Heneitriacontanes C31H64 1.4093 1.6968

Dotriacontanes C32H66 0.9040 1.3498

Tritriacontanes C33H68 0.8750 1.2893

Tetratriacontanes C34H70 0.3166 0.6684

Pentatriacontanes C35H72 0.2400 0.465

Hexatriacontanes C36H74 0.1093 0.2954

Heptatriacontanes C37H76 0.0816 0.1926

Octatriacontanes C38H78 0.0484 0.1188

Nonatriacontanes C39H80 0.0385 0.0801

Tetracontanes C40H82 0.0586 0.0377

Total 100.0000 100.0000

COMPONENTS


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10

Table 2.4.1The Results of Injection Water and Formation Water Analysis

With Using API RP45 Method

IW1 - GS FW - 1 IW3 - River water FW - 3

Dissolved Solids

Cation (mg/l) Unit

Sodium, Na+

(calc) mg/L 837.80 850.20 1.10 644.90

Calcium, Ca++

mg/L 109.10 80.80 12.10 92.90

Magnesium, Mg++

mg/L 15.90 7.40 0.00 9.80

Iron, Fe++

(total) mg/L 0.00 0.00 3.40 4.50

Barium, Ba++

mg/L 70.00 11.00 0.00 0.60

Anion (mg/L)

Chloride, Cl-

mg/L 1,338.90 1,160.40 17.90 856.90

Bicarbonate, HCO3-

mg/L 379.10 550.30 9.20 568.60

Sulfate, SO4=

mg/L 11.00 1.00 0.00 0.00

Carbonate, CO3=

mg/L 0.00 0.00 0.00 0.00

Hydroxide mg/L 0.00 0.00 0.00 0.00

Other Properties

Specific Gravity, 60/60oF 1.0058 1.0043 1.0078 1.0078

pH @ 77oF 7.85 8.00 5.85 7.8

Total hardness mg/l 125.00 88.20 30.25 272.43

Hydrogen Sulphide mg/l 0.00 0.00 Nil Nil

Total equivalent, NaCl mg/l 2,414.60 2,250.60 33.00 2,173.70

TDS (Total Dissolved Solids) 2,820.00 2,720.00 40.30 5,410.00

TSS (Total Suspended Solids) 22.75 245.00 62.00 78.00Resistivity (ohm - meter) (ohm - meter) 1.32 @ 125 F 1.41 @ 125 F > 10 1.75

Laboratory Tests


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11

2.5.1 Results of Water Compatibility Tests

245.00

166.00

115.00

59.50

22.75

0.00

50.00

100.00

150.00

200.00

250.00

300.00

0 % IW1 +

100 % FW1

25 % IW1 +

75 % FW1

50 % IW1 +

50 % FW1

75 % IW1+

25 % FW1

100 % IW1 +

0 % FW1

Mixing Ratio

TSS(mgr/L) 78.00

73.8069.80

65.70 62.00

0.00

20.00

40.00

60.00

80.00

100.00

T

SS(mgr/L)

0 % IW3 +

100 % FW3

25 % IW3 +

75 % FW3

50 % IW3 +

50 % FW3

75 % IW3 +

25 % FW3

100 % IW3

+ 0 % FW3

Mixing Ratio

Figure 2.5.1aThe results of water compatibility tests

between IW1 GS with FW1

Figure

2.5.1bThe results of water compatibility testsbetween IW3 RW with FW3


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12

Scaling Problem and Solving


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13

Table 2.5.2.1Results of CaCO3 Scaling Index Tendency and CaSO4 Solubility Calculations

With Using Stiff and Davis Method

No. Laboratory Units

Tests IW1 - GS IW3 - RW

1 Calcium, Ca+2

ppm 109.10 12.10

2 Bicarbonate, HCO3-

ppm 379.10 9.20

3 Carbonate, CO3=

ppm 0.00 0.00

4 Sulfate ppm 11.00 0.00

5 pH 7.85 5.85

6 CaCO3 scaling Index (SI)

Scaling Index at 77oF 0.87 -3.65



Remarks

CaCO3 scale at 77oF SI > 0, Formed SI > 0, Formed



7 Actual CaSO4 conc. meq/l 0.2292 0.0000

Solubility at 77oF meq/l 25.93 21.61



Remarks Solubility > than Solubility > than

Actual CaSO4 conc. Actual CaSO4 conc.

CaSO4 scale Unformed Unformed

Injection Water


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14

Figure 2.5.2.1The Result of Relative Plugging

Index (RPI) of IW1 GS before treatment

Figure 2.5.2.2The Result of Relative Plugging

Index (RPI) of IW3 RW before treatment

TSS = 22.75 ppm, RPI = 31.87

IW1 - GS + 0 ppm scale inhibitor

y = 4.9971e-0.0084x

R2

= 0.9686

0.01

0.10

1.00

10.00

100.00

0 50 100 150 200 250

Cumulative Volume (ml)

FlowRate(ml/second)

IW3 - RW + 0 ppm Alum

y = 1.6587e-0.0314x

R2

= 0.9123

0.01

0.10

1.00

10.00

0 50 100 150 200

Cumulative Volume (cc)

FlowRate(cc/secon

d)

TSS = 62 ppm, RPI = 96.09


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15

Figure 2.6.2.1

Influence of scale inhibitor On TSS and RPI ofIW1 GS injection water

Figure 2.6.2.2

Inhibition Efficiency of CaCO3 scale withscale inhibitor in IW1 GS injection water

1.75 2.73

22.75

3.67

31.87

4.43

0

10

20

30

40

50

IW1 - GS

+ 0 ppm

Inhibitor

IW3 -

RW + 10

ppm

Inhibitor

IW3 -

RW + 20

ppm

inhibitor

Injection water

[TS

S,ppm]

danRPI

(TSS, ppm) RPI82.26 96.10

0.00

50.00

100.00

% Inhibition

Efficiency

%Eff-

IW1+10

ppm

%Eff-

IW1+20

ppm

IW1 - GS Injection Water

(No and With Scale Inhibitor)

IW1 + 10 ppm scale inhibitor

y = 3.3644e-0.0007x

R2

= 0.913

0.01

0.10

1.00

10.00

100.00

0 200 400 600 800 1000

Cumulative Volume (mL)

Flow

Rate(mL/second)

IW1 + 20 ppm scale inhibitor

y = 3.7302e-0.0009x

R2

= 0.8994

0.01

0.10

1.00

10.00

100.00

0 100 200 300 400 500 600 700 800

Cumulative Volume (mL)

Flow

Rate(mL/second)


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16

Figure 2.6.2.2

Influence of Alum On TSS and RPI of IW3

RW injection water

4

62

8 6.93

96.09

10.93

0

50

100

150

IW3 - RW

+ 0 ppm

Alum

IW3 - RW

+ 30 ppm

Alum

IW3 - RW

+ 60 ppm

Alum

Injection water

[T

SS,ppm]

danRPI

TSS, ppm (RPI


y = 5.0165e-0.0027x

R2 = 0.9433

0.01

0.10

1.00

10.00

100.00

0 100 200 300


FlowR

ate(cc/second)


y = 4.2355e-0.0027x

R2 = 0.9449

0.01

0.10

1.00

10.00

100.00

0 50 100 150 200 250


FlowR

ate(cc/second)


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Emulsion Block

Problem and Solvings

Qualitative tests Quantitative tests


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Kualitatif

Sebelum penambahan Reverse Demulsifier Setelah penambahan Reverse Demulsifier

IW1-GS

0

100

80

60

40

20

3200 3100 3000 2900 2800 2700

%

T

r

a

ns

m

i

t

t

a

n

c

e

Wavenumbers (cm-1)

A

CH3

CH2

P

Qualitative

2960 cm-1

for CH3 dan 2925 cm-1

for CH2

Oil content in water by Infra Red

Spectrophotometer

IW1-GS+ rev.S

IW1-GS


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19

37.21

5.49 6.33 8.56

0.00

50.00

100.00

IW1-G

S

IW1-G

S+10

ppm-

S

IW1-GS+

10ppmA

-78

IW1-GS+

10ppmA

-68

Influence of Reverse Demulsifier on Oil Content

in IW1 - GS Injection water

OilCo

ntent(ppm) Inhibition Efficiency

85.24 %

2.6.3 Emulsion Block Problem and Solving


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Bacteria Problem and Solving


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SULFATE REDUCING BACTERIA

Reasons bacteria can cause a lot of problem :

1. Bacteria can conduct splitting of cell is very quick.

2. Several bacteria cells can increase population double in 20 minutes.

3. If under ideal condition, where from a bacterium can form colonies

(containing million of bacteria cells) in several hour.

21


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Table 2.5.4

Figure 2.5.4.1

Photographs of Sulfate Reducing Bacteria Tests Results 22

Sample Results (colonies/cc)

-

IW3 - RW < 10

The Results of SRB Determination

IW1 - GS IW3 - RW

T bl 2 6 4


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23

Water Type of Total bacteria Countsample Bacteria (colonies/cc)

IW1 - GS Bacillus Panthothenticus 1,950Bacillus Pumilus

IW3 - RW Bacillus Subtilis 2,550Bacillus Panthothenticus

Bacillus Coagulans

Table - 2.6.4Results of Total bacteria Count Determination Before Treatment With Biocide

1950

530 450 360 330 280 210

0.00500.00

1000.00

1500.00

2000.00

2500.00

Total Bacteria

Count

(colonies/cc)

IW1-G

S+0ppm-

B6

IW1-G

S+5ppm-

B6

IW1-G

S+10pp

m-B6

IW1-G

S+15pp

m-B6

IW1-G

S+5ppm-

B5

IW1-G

S+10pp

m-B5

IW1-G

S+15pp

m-B5

Influence of Biocide - B6

on Total Bacteria Count in Injection water

25501980

1195 980

160 110 60

0.00500.00

1000.001500.002000.002500.003000.00

Total Bacteria

Count

(colonies/cc)

IW3-RW+

0ppm

-B6

IW3-RW+

5ppm

-B6

IW3-RW+

10ppm

-B6

IW3-RW+

15ppm

-B6

IW3-RW+

5ppm

-B5

IW3-RW+

10ppm

-B5

IW3-RW+

15ppm

-B5

Influence of Biocide B5

on Total Bacteria Count in Injection water

Figure

2.6.4 Influence of Biocide on Total Bacteria Count in Injection Water


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Dissolved Oxygen Problem

and Solving


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25Figure

2.6.5 Influence of Oxygen Scavenger on Dissolved Oxygen in Injection Water

2.6.5 The Dissolved Oxygen Problem and Solving

4.83

2.44 2.39 2.08

3.82

2.29 4.501.78

0.00

5.00

10.00

Dissolved

Oxygen in

Water (ppm)

IW1-G

S+0p

pm-D

IW1-GS+

3.70p

pm-P

IW1-G

S+5p

pm-P

IW1-GS

+10p

pm-P

IW3-RW

+0ppm-

D

IW3-RW

+3.70

ppm-

P

IW3-RW

+5ppm-

P

IW3-RW

+10p

pm-P

Influence of Oxygen Scav anger - P

on Dissolved Oxygen in Injection water at 24 oC

4.83

2.77 2.73 2.713.82

2.47 4.50 2.43

0.00

5.00

10.00

Dissolved

Oxygen in

Water (mg/L)

IW1-

GS+0

ppm-

D

IW1-GS

+3.70

ppm-

D

IW1-

GS+5

ppm-

D

IW1-G

S+10

ppm-

D

IW3-R

W+0p

pm-D

IW3-RW

+3.70

ppm-

D

IW3-RW

+5ppm-

D

IW3-RW+

10ppm-

D

Influence of Oxygen Scavanger - D

on Dissolved Oxygen in Injection water at 24 oC


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Corrosion Problem

and Solving


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27

0.533

0.218 0.277

0.002 0.097

0.00

0.50

1.00

Corrosio

nRate

(mpy)

IW1-

GS

IW1-

GS

+10ppmM

IW1-

GS

+10ppmR

IW1-

GS+20

ppmM

IW1-

GS

+20ppmR


2.6.6 Determination of Corrosion Rate (Electrochemically)Before and After Treatment with Corrosion inhibitor

0.00

59.13 48.0899.58

81.88

0.00

50.00

100.00

Efficiency

(%)

IW1-GS

IW1-

GS

+10p

pmM

IW1-

GS

+10p

pmR

IW1-

GS+

20pp

mM

IW1-

GS

+20p

pmR


2.6.6 Influence of Corrosion Inhibitor on Corrosion Rate (Electrochemically)


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Figure A1Influence of Filtration and Scale Inhibitor

On Total Suspended Solids Concentration 28

38.45

13.738.29 6.53

31.85

12.157.69

5.65

0.00

20.00

40.00

60.00

[TSS],ppm

IW - A IW - B

Injection Water

0.45 mikron

20 - 25 mikron20 ppm inh + 20-25 mikronFiltrate, 11 mikron

40.25

10.338.67

39.18

9.53 8.42

0.00

20.00

40.00

60.00

RPI

IW - A IW - B

Injection Water

0.45 mikron

20 ppm inh + 20-25 mikron

Filtrate, 11 mikron

Figure A2The Results of Relative Plugging Index

(RPI) of Injection Water

2.7 High TSS and High RPI Problem Solving

High TSS Concentration and High RPI can be reduced by

Filtration and Addition of Chemicals into Injection Water

2 8 Rock Compatibility Laboratory Test


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Decrease of

Permeability

drastically0.00

0.40

0.80

1.20

1.60

2.00

0 30 60 90 120 150

CUMMULATIVE PORE VOLUME, PV

Kfw,mD

0.00

0.40

0.80

1.20

1.60

2.00

Kiw,mD

Formation Water Injection Water

If, the trend of curve below :

Figure : 1Rock Compatibility Test, Core No. 6A, I 38

2.8 Rock Compatibility Laboratory Test


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30

0.00

50.00

100.00

150.00

200.00

250.00

0.0 5.0 10.0 15.0 20.0

Pore Volume

Permeabilitasair,md

Air Formasi Air Injeksi


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Figure 1.Enhanced Oil Recovery Equipment

EOR Equipment For Core Flood Lab. Test


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The Procedure of Water Flooding Laboratory Tests

The process of water flood to improve oil recovery by using core media that is carried out inEOR laboratory, is described schematically below :

1. Core is saturated by formation water, which is expected saturation 100%.

2. Formation water is injected into core, so that the core is filled fully by formation water.

FwCore

FwFwCore

Fw

3. Oil is injected into core, then formation water is displaced out and core is filled by

totally oil. However, not all of formation water is displaced out of the core, part of

amount of formation water is left in the core, this is called connate water.

Oil Oil

Core

Oil Oil

Core


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5. Determination of oil recovery factor by using water flood method.Injection water is injected into core, then oil is displaced and produced. Recoverableoil is recorded. The remaining amount of oil in the core is called residual oil saturation (Sor2).In this stage, oil recovery factor and injected water cumulative (volume of injection water)can be calculated.

Core

Injectionwater

Residual oil

Core

Oil recoveryfactor

Residual oil

Core

Injectionwater

Residual oil

Core

Oil recoveryfactor

Residual oil

4. Formation water is injected into core, then oil in the core is displaced by formation wateruntil oil is not out of the core anymore. However, not all of oil is displaced out of the core,part of amount of crude oil is left in the core, this is called residual oil saturation (Sor1).

Core

Residual oil

Fw Oil, thenFw

Core

Fw Oil, thenFw

Core

FwFwFw

Core

FwFwFwFwFwFw

Core

Residual oil

Fw Oil, thenFw

Core

Fw Oil, thenFw

Core

FwFwFw

Core

FwFwFwFwFwFw

Table 2 8 1


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Core Porosity Connate Water The Incremental of Oil Rec.

No. Ka Ko,avg Kw, avg Saturation, Swc Sor1 WID1 RF1 Sor2 WID2 RF2 Factor, Calculated from

mD mD mD % % % % % % The First Phase

7A 37.13 5.79 3.55 24.94 38.11 30.06 4.63 31.83 28.23 15.38 33.66 1.83

Table 2.8.1

The Results of Oil Recovery Factor After Primary and Secondary Oil Recovery Methods

I # 38, CORE NO.7A, I FIELD

Permeability, After First Phase After Second Phase

Primary

0

10

20

30

40

50

60

70

80

90

100

0 2 4 6 8 10 12 14 16 18

Water Injected, PV

OilRecoveryFactor,%

Secondary

Primary


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Core Porosity Connate Water The Incremental of Oil Rec.No. Ka Ko,avg Kw, avg Saturation, Swc Sor1 WID1 RF1 Sor2 WID2 RF2 Factor, Calculated from

mD mD mD % % % % % % The First Phase

6B 152.40 9.99 116.18 24.18 21.83 42.20 2.16 35.97 39.88 9.82 38.29 2.32

Table - 3.8.2

SUMMARY OF THE LABORATORY TEST RESULTS AFTER THE FIRST AND SECOND PHASES OF OIL RECOVERY FACTOR

I # 38, CORE NO.6B, I FIELD

Permeability, After First Phase After Second Phase

Figure 3.9.6Oil recovery vs Water Injected

I # 38, Core no. 6B, I Field

0

10

20

30

40

50

60

70

80

90

100

0 2 4 6 8 10 12

Water Injected, PV

OilR

ecoveryFactor,%

Primary Secondary


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36

CONCLUSIONS

1. IW1

GS dan IW3

RW indicate poor water quality, because both watershave high total suspended solids and high relative plugging index values.

2. IW1 GS has positive scaling index, CaCO3 scaling problem can beprevented with addition of scale inhibitor into injection water, whereasIW3 RW indicates negative scaling index, so CaCO3 is not foundin the IW3 - RW injection water.

3. IW1 GS and IW3 RW are compatible with formation water.

4. After treatment with 20 ppm P scale inhibitor, IW1 GS shows excellent

water quality with 1.75 ppm TSS concentration and 2.75 RPI value and96.10 % inhibition efficiency of CaCO3 scale.

5. Octane is dominant component in IW1 GS injection water and tetradecanein IW3 RW injection water.


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37

CONCLUSIONS(continued)

6. TSS problem in IW3

RW injection water can be minimized withaddition of 60 ppm alum into the injection water, TSS concentrationis 4.00 ppm and RPI values is 6.93.

7. a. Biocide is used to reduce total bacteria count in IW1 GS and IW3 RW.b. Emulsion block problem is prevented with addition of reverse demulsifier.c. Corrosion problem is reduced with using corrosion inhibitor.d. Dissolved oxygen is minimized by oxygen scavanger

8. Water-rock compatibility test is done to know about influence of injectionwater on core permeability.

9. High or low oil recovery factor , not only influenced by core permeability,but also good or poor injection water is injected into the core.


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Thank You

Hopefully the Best For Us

aspek laboratorium untuk menunjang perencanaan water flooding dan water flooding improvement

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