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Nguyễn Gia Hào

Academic year: 2023

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ABSTRACT

Wettability plays an important role of two phase À uids À ow in porous media. The displacement ef¿ ciency of oil by injected À uid is also dictated by wettability characteristic of reservoir rocks. This papers contents a highlight of the reservoir wettability modi¿ cation by injecting TFSA (Thin Film Spreading Agent) surfactant for EOR applications through a laboratory study . TFSA used in this study is called Coconut Ethanolamide with a HLB (Hydrophilic-Lipophilic Balance) level around 13 to 15 which is very suitable for TFSA purposes.

Several laboratory evaluations have been done to screen this surfactant with the aim of getting the best properties that ful¿ ll the criteria for EOR chemical injection. Then TFSA solution tests have been carried out including compatibility, thermal stability, phase behavior, and ¿ ltration test. The results suggest that all measured parameters are suitable for chemical injection. Others parameters measuring rock À uid interactions for instance: adsorption, wettability, imbibition, relative permeability, and core À ood experiments has been done to ¿ nd the quantitative numbers for screening this surfactant. All experiment results categorize as moderate levels for passing the screening criteria for chemical injection except for the adsorption which is excellent. Even though the results of laboratory tests show this TFSA is valid for chemical injection, improvement by adding some chemicals is still suggested to ¿ nd a better TFSA formula.

Keywords: Wettability modi¿ cation, thin ¿ lm spreading agent, chemical injection

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Core Depth Permeability Porosity Grain Density

Remarks Plug No. (Feet) (mD) (%) (gr/cc)

1 2868 44.02 33.20 2.70 Wettability measurement

2 2918 3.79 16.90 2.70 Wettability measurement

3 2868 97.56 28.32 2.70 Capillary imbibitions (surf TFSA 0.1%-oil) 4 2918 228.80 26.84 2.70 Capillary imbibitions (surf TFSA 0.1%-oil) 5 2868 44.02 33.20 2.70 Spontaneous Imbibition (Surf TFSA 0.3%-Oil) 6 2918 3.79 16.90 2.70 Spontaneous Imbibition (Surf TFSA 0.1%-Oil)

7 2851.2 50.77 28.94 2.71 Kro-Krw (oil-water)

8 2920.2 207.00 28.36 2.70 Kro-Krw (oil-TSFA 0.1%)

9 2899 115.50 28.31 2.70 Stacked core flooding

10 2925.5 248.50 28.64 2.71 Stacked core flooding

11 2945 249.10 26.58 2.70 Stacked core flooding

12 2887 277.30 33.93 2.71 Stacked core flooding

13 2885 58.80 28.15 2.70 Dynamic adsorption

14 Core Chips Static adsorption

15 Core Slices Wettability measurement by contact angle

7DEOH

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Constituents meq/L mg/L

Sodium 267.49 6,151.50

Calcium 25.45 510.1

Magnesium 5.13 62.4

Iron 0.08 2.3

Barium 0 0

Total Cations (excl. Fe) 6,724.00

Chloride 281.4 9,977.60

Bicarbonate 9.52 580.8

Sulphate 7.15 343.6

Carbonate 0 0

Hydroxide 0 0

Total Anions 10,902.00

Total Equiv. NaCl Conc. 17,067.10

pH 7.45

7DEOH 5HVXOWRIZDWHUDQDO\VLV

Analysis Result/Units

Acid Number 0.085 mgKOH/g

Pour Point 78 oF

Asphaltene Content 0.82 %

Resin Content 3.04 %

Wax Content 25.46 %

Viscosity 2.04 Cp at 83oC

7DEOH 2LOFKDUDFWHULVWLFV

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Concentration Observation Result

1st day 5thday 12thday 19thday 27thday 60th day 0.10%

Clear Clear Clear Clear Clear Clear

0.20%

0.30%

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IFT (dyne/cm)

0.10 5.43E-02

0.20 2.74E-01

0.30 1.23E-01

TFSA Concentration (%)

Winsor Type Micro-emulsion

0.10 1

0.20 1

0.30 1

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TFSA Concentration

(%)

IFT ( Dyne / cm ) and Observation

1st day 14th day 30th day 60th day

0.10%

5.431E-02 4.247E-01 4.206E-01 8.271E-02

Transparent Brownish

Transparent Brownish

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Transparent Brownish

0.20%

2.739E-01 2.767E-01 3.532E-01 1.418E-01

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Transparent Brownish

Transparent Brownish

Transparent Brownish

0.30%

1.453E-01 2.783E-01 2.784E-01 9.524E-02

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Transparent Brownish

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20 40 60 80 100 120

0 500 1000 1500 2000

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Time (s) TFSA Filtration Test

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TFSA _0.2%

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No. meter mD % Water wet index Oil wet index

1 2868.00 44.020 33.201 0.0108 0.6762

2 2918.00 3.794 16.896 0.0636 0.0000

No.

Sample

Immersion Fluid

Immersion

Time Droplet Contact Angle

Degrees Wettability

1 Formation Water 8 Weeks Oil 13.20 Oil Wet

2 TFSA - 0.01% 2 Weeks Oil 28.56 Oil Wet

3 TFSA - 0.01% 4 Weeks Oil 37.87 Oil Wet

4 TFSA - 0.01% 8 Weeks Oil 30.19 Oil Wet

7DEOH

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Concentration %

Adsorption Method

Adsorption P Pgr/gr

0.1 Static 400.07

0.3 dynamic 364.74

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Core Number

TFSA (%)

K (mD)

POR (%)

Pore Volume (cc)

Imbibition (cc)

RF (%)

5 0.1 601.40 30.92 18.44 3.90 21.15

6 0.1 62.62 20.43 11.23 0.60 5.34

IMBIBITION OF 0.1 % TFSA SATURATION AT VARIOUS PRESSURE

Pressure, PSI 1 5 10 42 35 50 100 500 1000 2000

Core Number

Oil Production (% OOIP)

3 0.19 0.29 0.43 0.48 0.76 1.14 45.27 59.82 61.06 61.06 4 0.49 0.78 23.30 35.80 31.60 38.10 47.40 61.00 62.10 62.20

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0.001 0.010 0.100 1.000

0 10 20 30 40 50 60 70 80 90 100

Relative Permeability, fraction

Water Saturation, Per Cent Pore Space Relative Permeability vs Water Saturation

krw -oil/TFSA

kro-oil/TFSA

Sample No. : 110 Air Perm. (mD) : 207.0 Porosity, % : 28.36 TFSA vs. Oil Sample No. : 72 Air Perm. (mD) : 50.77 Porosity, % : 28.94 Water vs. Oil

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kro-oil/water

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Composition Concentration Viscosity @ 83oC

Injection Volume

(PV) pH

Main Slug

TFSA 0.10% 6.05 0.3 8.06

Polymer-X 0.18%

Polymer Protective Slug

4.46 0.2 8.42

Polymer -X 0.08%

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Test Parameters Results Category

Compatibility Clear excellent

IFT 10-1 to 10-2 dyne/cm excellent

Pahse Behaviour Winsor Type-1 Good

Thernal stability 60 days Good

Filtration Test 1.2 excellent

Adsorption 364.74 to 400.07 Pgr/gr excellent

Wettability Do not change not good (need a longer resident time) Spontaneous Imbibition 5.34 to 21.15 %OOIP Good

Forced Imbibition 61.06 to 62.20 %OOIP Good

Relative Permeability Do not change not good (need a longer resident time)

Core Flooding 13.50% OOIP Good

0%

10%

20%

30%

40%

50%

60%

0.0 2.0 4.0 6.0 8.0 10.0

Oil Recovery (%)

Pore Volume Injected Core Flood Result of Stacked-Core

TFSA Injection

Chemical Injection Begin Water Flood

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