aspek laboratorium untuk menunjang perencanaan water flooding dan water flooding improvement
TRANSCRIPT
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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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CONTENTS (Continued)
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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CONTENTS (Continued)
2.7 Water Rock Compatibility Tests
2.8 Water Flooding Laboratory Tests
III. CONCLUSIONS
5
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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
Scaling Index at 140oF 1.58 -2.80
Scaling Index at 175oF 2.04 -2.51
Remarks
CaCO3 scale at 77oF SI > 0, Formed SI > 0, Formed
CaCO3 scale at 140oF SI > 0, Formed SI > 0, Formed
CaCO3 scale at 175oF 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
Solubility at 140oF meq/l 25.93 21.52
Solubility at 175oF meq/l 25.65 18.67
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
IW3 - RW + 30 ppm Alum
y = 5.0165e-0.0027x
R2 = 0.9433
0.01
0.10
1.00
10.00
100.00
0 100 200 300
Cumulative Volume (cc)
FlowR
ate(cc/second)
IW3 - RW + 60 ppm Alum
y = 4.2355e-0.0027x
R2 = 0.9449
0.01
0.10
1.00
10.00
100.00
0 50 100 150 200 250
Cumulative Volume (cc)
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
IW1 - GS Injection Water
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
IW1 - GS Injection Water
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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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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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