A laboratory feasibility study of dilute surfactant injection for the Yibal field, Oman

www.elsevier.com/locate/petrol

Journal of Petroleum Science and E

A laboratory feasibility study of dilute surfactant injection for the

Yibal field, Oman

T. Babadaglia,*, A. Al-Bemanib, F. Boukadib, R. Al-Maamarib

aUniversity of Alberta, Department of Civil and Env. Eng., School of Mining and Petroleum, 3-112 Markin CNRL/NREF Edmonton,

AB, Canada T6G 2W2bSultan Qaboos University, Department of Petroleum and Chemical Engineering, Oman

Received 26 January 2004; received in revised form 27 January 2005; accepted 27 April 2005

Abstract

The Yibal field, the largest oil field in Oman, comprises 15% of the oil production of the country. The field has

had a high ultimate recovery factor and in order to maintain the current recovery trend, different management

strategies have been sought. One of the options is the injection of a dilute surfactant in addition to the current

waterflooding.

The cores from the chalky Shuaiba formation were saturated with brine and oilflooded to restore the initial reservoir

condition after cleaning. Nineteen samples were waterflooded followed by dilute surfactant injection. Eight samples were

flooded with dilute surfactant. The reason for this scheme is that some parts of the reservoir under study were totally

watered out while others are still untouched. In addition to these experiments, nine capillary (static) imbibition

experiments were conducted to treat fractured zones where recovery by capillary imbibition during injection is a

possibility. Twelve different surfactants (at different concentrations) were tested. Five surfactants were non-ionic, two

cationic, four anionic, and one was a mixture of anionic and non-ionic. The selection of the optimum concentrations was

based on IFT values at different concentrations.

The results were evaluated in terms of the final oil recovery. The average waterflooding recovery was found to be

75.1% of OOIP (out of 19 experiments) whereas surfactant injection yielded an average of 69.9% of OOIP (out of

8 experiments). This indicates that the surfactant injection is not preferable and not recommended over waterflooding for

the untouched portion of the reservoir where the rock matrix dominates the flow (unfractured portions). An additional

recovery by surfactant solution injection succeeding waterflooding was obtained and found to vary between 0% and 7.4%

of OOIP. The surfactant injection is, therefore, recommendable in the pre-waterflooded unfractured zones as long as the

proper surfactant type is selected. Half of the surfactant solutions yielded higher and faster capillary imbibition recovery

than brine. For the untouched fractured zones of the chalky reservoir, it is more effective to start the injection with

0920-4105/$ - s

doi:10.1016/j.pe

* Correspondi

E-mail addre

ngineering 48 (2005) 37–52

ee front matter D 2005 Elsevier B.V. All rights reserved.

trol.2005.04.005

ng author. Tel.: +1 780 492 9626; fax: +1 780 492 0249.

ss: [email protected] (T. Babadagli).

T. Babadagli et al. / Journal of Petroleum Science and Engineering 48 (2005) 37–5238

surfactant addition rather than waterflooding alone. Surfactant types and concentrations yielding the best performances

were identified and listed in this paper.

D 2005 Elsevier B.V. All rights reserved.

Keywords: Surfactant injection; Water injection; Yibal oil field; Tertiary oil recovery; Mature fields; Secondary oil recovery; Chalk; Naturally

fractured reservoirs

1. Introduction

Different schemes of surfactant injection received

attention in the late 1970s and early 1980s due to

economic feasibility for field applications. Early

studies were performed on sandstone reservoirs

(Boneau and Clampitt, 1977; Bae, 1985; Bae and

Syed, 1986; Bae and Petrick, 1986; Clark et al.,

1988; Saad et al., 1989; Maerker and Gale, 1992;

Kuhlman et al., 2000). More recently, laboratory

and field scale applications were reported for chalks

(Flumerfelt et al., 1993; Milter and Austad, 1996;

Michels et al., 1996; Austad and Milter, 1997;

Austad et al., 1998; Spinler, 2000; Chen et al.,

2000). The economics of the surfactant injection is

critical due to the high cost of the chemicals.

Therefore, optimum injection scheme has to be

designed (Salager et al., 1979a,b; Barua et al.,

1986; Jakobsen and Hovland, 1994; Baviere et al.,

1994; Tsau et al., 2000). Adsorption is an important

aspect of the process that plays a role in the opti-

mization and cost analysis of the projects (Hurd,

1976; Lawson and Dilgren, 1978; Lawson, 1978;

Ramirez et al., 1980; Stournas, 1983; Lewis et al.,

1986; Hong and Bae, 1990; Mannhardt et al., 1990;

Tabatabai et al., 1991). This literature provided not

only the previous experience on surfactant flooding

but was useful to gain insight into the surfactant

types used for different rock types and injection

schemes applied.

Based on recent experience with chalky carbo-

nates, surfactant injection was considered as an al-

ternative for the Yibal field to maintain the high

recovery trend. The Yibal field (a tight and fractured

carbonate reservoir), containing light oil, has been

producing with a high recovery factor. Because the

field also has a high value of original oil in place,

the possibility of EOR applications should be eval-

uated. This is a crucial issue to extend the field life

and a challenging application of effective reservoir

management.

The Yibal field has undergone different develop-

ment plans since it was discovered. Several attempts

were made to characterize the reservoir and propose

different development schemes. Litsey et al. (1986)

provided a detailed geological and petrophysical

study on the Shuaiba chalk, which is the main oil

producing formation. After an extensive field scale

reservoir simulation study, Blaskovich et al. (1985)

suggested a pattern type waterflooding scheme for

the field. Later, Bos (1989) and Eckford (1999)

evaluated the existing field performance and recom-

mended long term development scenarios. Water-

flooding performance during different periods of

the production was also evaluated and the results

were published (Grant, 1981; Mugheiry et al.,

2001).

The possibility of injecting dilute surfactant solu-

tions in the Yibal field was investigated using exper-

imental modeling, and core-flooding experiments with

plugs to clarify the response of the reservoir to sur-

factant supported water injection.

2. Experimental study

To examine the compatibility of the reservoir rock

to the injected fluids, core-flooding tests were con-

ducted. The experiments were divided into three

groups: (1) displacement of oil by unmodified

water injection in a virgin sample (primary water-

flooding), (2) displacement of oil by surfactant solu-

tion in an oil saturated core sample (secondary

recovery by surfactant), and (3) displacement of oil

in a core sample originally fully flooded by unmod-

ified injection water (tertiary recovery by surfactant).

The effect of surfactant addition to injected water on

the capillary imbibition of water into the Shuaiba

Table 1

Rock and fluid properties used in the experiments

Rock properties

Core no. Porosity

(%)

Permeability

(md)

Pore volume

(ml)

Swi(%)

Y3 28.7 4.8 11.24 19.03

Y4 29.2 4.6 10.40 16.82

Y7 27.7 2.6 9.84 17.68

Y8 28.9 2.9 10.23 18.29

Y9 29.1 3.1 10.35 17.39

Y10 28.4 2.6 9.44 16.31

Y11 27.2 2.5 9.60 15.62

Y12 29.8 2.9 10.58 17.29

Y14 27.2 2.4 9.52 19.11

Y17 28.1 1.9 10.02 20.15

Y19 30.1 2.7 10.64 21.99

Y22 30.4 3.6 10.99 19.92

Y23 29.1 2.8 10.39 21.07

Y24 27.7 2.2 9.77 24.25

Y28 30.0 2.6 10.85 27.18

Y32 29.5 3.7 10.31 20.46

Y34 29.5 4.3 11.14 19.21

Y35 24.5 2.7 8.48 23.34

Y38 29.3 3.9 9.66 10.97

Y42 31.1 6.1 11.12 20.52

Y44 27.8 2.3 9.97 18.75

Y45 26.6 2.9 9.20 17.39

Y46 27.8 2.6 9.98 18.83

Y54 28.8 2.7 10.24 18.94

Y55 29.3 2.9 10.34 19.72

Y56 28.4 2.3 9.90 21.21

Y58 28.7 2.5 10.25 21.95

Y60 27.8 2.5 10.11 21.85

Types and properties of the surfactants and oil (Yibal)

Surfactant

no.

Surfactant type Properties (major

chemical structure)

T1 Anionic+

Non-ionic blend

Surfactant (Sulfonic acid)

T2 Anionic Surfactant/non-emulsifier (Diol)

T3 Anionic Solid (powder) surfactant

(Sulfonated salts and sulfonic salts)

T4 Cationic Non-emulsifier (Quaternary

salt of fatty amine)

T5 Non-ionic Surfactant (TRITON X-100)

(t-octylphenoxypolyethoxyethanol)

T6 Non-ionic Foaming agent (ethoxylated)

T7 Non-ionic Solvent/surfactant (ethoxylated)

T8 Non-ionic Non-emulsifier (ethoxylated)

T9 Anionic Surfactant (sulfosuccinates)

T10 Cationic Surfactant (n–C12–N(CH3)3Br)

T11 Non-ionic Surfactant (IGEPAL)

(t-octylphenoxypolyethoxyethanol)

T12 Anionic Surfactant (NIAPROOF Type 4)

(C14H29SO4Na)

Table 1 (continued)

Types and properties of the surfactants and oil (Yibal)

Chemical

additive no.

Type Properties (major chemical

structure)

TC1 Mutual solvent Surfactant adsorption reducer

(Butoxyethanol)

Oil used APIo Viscosity (experimental

conditions)

IFT (experimental

conditions)

Yibal crude 40 19 (cp) 15 (mN/m)

T. Babadagli et al. / Journal of Petroleum Science and Engineering 48 (2005) 37–52 39

chalk was also studied because some parts of the

field are extensively fractured.

2.1. Materials used

The materials used are Shuaiba chalk, brine, dead

Yibal oil, surfactants and additives.

2.1.1. Rock samples

For the experiments, core plugs were taken from

cores obtained from two wells. After cleaning, with

methanol and ethanol in Soxhlet device, the plugs

were dried. The properties of the core plugs used

in the experiments are given in Table 1. Next, the

porosity and permeability values were measured.

Porosity and permeability values were found to

be between 25% and 30% and 2 and 7 mD,

respectively.

2.2. Fluid samples

Brine and degassed Yibal oil were used as the

aqueous and oleic phases during the experimental

study. Brine is 3 wt.% NaCl solution. The original

formation salinity is about 200,000 ppm of solids

which may affect surfactant stability. Because the

objective of this study is only to investigate the

rock–oil–surfactant interaction and increase of re-

covery due to surfactant, a synthetic brine was

used to saturate the samples and as displacement

fluid. The types and properties of the surfactants and

a mutual solvent used to reduce adsorption are given

in Table 1.

The interfacial tensions (IFT) between oil and

brine, and oil and surfactant solutions were also mea-

sured using the du Nouy ring method. The IFT be-


tween oil and brine was found to be 15 mN/m. This

value was also the same for oil-formation water pair.

To establish the base for the selection of the

surfactant concentrations, IFT measurements were

also conducted for surfactant solution/oil pairs. The

IFT values for different concentrations are given in

Table 2.

Table 2

IFT values for different surfactant concentrations

Surfactant no. Concentration (%) IFT (m/Nm)

T1 0.01 9.5

0.1 1

0.5 0.4

1 0.4

T2 0.01 7.5

0.03 1

0.05 1

0.1 1

T3 0.01 2.5

0.05 3

0.1 3

T4 0.01 0.4

0.05 0.5

0.1 0.5

1 0.7

T5 0.01 7.5

0.05 3

0.1 1.5

1 1

T6 0.1 4

1 2.7

1.5 2.5

T7 0.01 11

0.05 7.5

0.1 5

1 3

T8 0.01 8.5

0.03 6.5

0.05 0.4

0.1 0.2

T9 0.005 5.5

0.01 1

1 0.5

T10 0.01 8.5

0.05 3

1 2

T11 0.005 7.5

0.01 4

1 1

T12 0.01 7.5

0.03 5

0.05 3

1 0.2

2.3. Experimental procedure

After cleaning and drying the core plugs, poros-

ity and permeability values were measured. Then

the samples were saturated with brine and drained

by oil displacement to irreducible water saturation.

Oil was pumped at 0.03 ml/min until 20-pore

volumes (PV) oil has been injected to ensure

complete displacement of water to its irreducible

value. The cores were exposed to the same clean-

ing procedure and aging time before starting the

waterflooding at 0.3 ml/min. Some of the experi-

ments were followed by the surfactant solution

injection using the same rate. Each core was

used only once and all experiments were conducted

at room temperature.

3. Results and analysis

3.1. Dynamic displacement experiments

Two sets of dynamic experiments were used: (1)

waterflooding succeeded by surfactant solution injec-

tion; this was used mainly to quantify the surfactant

injection recovery as a tertiary method for the water-

flooded areas in the field, (2) surfactant solution

injection (modified waterflooding) experiments into

the oil saturated samples to quantify recovery

obtained by injecting surfactant solution as an alter-

native to waterflooding.

3.1.1. Surfactant injection after waterflooding

The experiments were continued until 100% pro-

duced water cut is reached. To ensure that water-

flooding would not yield more oil, several pore

volumes of water were injected after reaching

100% water cut. Two examples of the recovery

plots are shown in Fig. 1. In these experiments

different recovery trends were observed. Some

cases represented earlier water breakthrough. Some

other cases exhibited high waterflooding recovery

whereas some cases exhibited low waterflooding

but high surfactant recovery. Thus, it was decided

to evaluate the results using different performance

indicators.

The first indicator was the oil recovered per vol-

ume of water injected and the performances of 20

0

0.2

0.4

0.6

0.8

0 20 40 60

Produced Oil

Typ

e-T

3 @

0.1

%

Typ

e-T

2 @

0.1

%

0

0.2

0.4

0.6

0.8

0 20 40

Po

re V

olu

me

Oil

Pro

du

ced

Pore Volume Water Injected Pore Volume Water Injected

Produced Oil

Typ

e-T

1 @

0.1

%

Waterflooding

Waterflooding

Surfactant injection starts

Sur

fact

ant i

njec

tion

star

ts

Po

re V

olu

me

Oil

Pro

du

ced

Fig. 1. Recovery performance of two core samples.

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

Y-17, T

11-0.2

Y-22, T

10-0.5

Y-35, T

10-1

Y-44, T

2-0.01

Y-45, T

12-0.1

Y-54, T

11-1

Y-38, T

5-0.1

Y-10, T

6-0.1

Y-4, T

3-0.1

Y-4, T

3~T2-.1

Y-19, T

8+TC

1-0.1+5

Y-8, T

7-1

Y-46, T

9-0.01

Y-23, T

8-0.01

Y-11, T

1-0.5

Y-12, T

8-0.1

Y-3, T

1-0.1

Y-9, T

2-0.1

Y-14, T

7-0.1

Y-7, T

4-0.01

Core Number, Surfactant Type, and Percentage

Oil

Rec

ove

red

per

Po

re V

olu

me

Inje

cted

, ml/p

v

Water Flood

Surfactant Flood

Fig. 2. The performance of waterflooding succeeded by surfactant injection for 20 cases. Performance indicator: oil recovered/pore volume

injected.



different cases are given in Fig. 2. Note that one of the

plugs (Y-4) was exposed to two types of surfactant

injection after waterflooding. Both surfactants yielded

an additional recovery. Thus, there actually exists only

one waterflooding (unmodified) on Y-4 sample

(marked as Y-4, T3-0.1%). The second waterflooding

case of Y-4 (marked as Y-4, T3~T2-0.1) is water-

flooding+previous surfactant recovery (T-3-0.1%).

Hence, actually 19 waterfloods are shown in Fig. 2.

Also, one surfactant (T8) was tested twice because it

is the only surfactant with the additional chemical

(TC1, Table 1) to observe the effect of the chemical

as a wettability and adsorption changer. This plot

indicates that there is no typical trend with respect

to the amount injected for recovery of oil by water and

surfactant flooding. For plug Y-19, oil recovery/pore

volume injected is 0.7 whereas this value decreases to

0.24 for plug Y-4 (waterflooding only). One possible

explanation for this difference may be the heteroge-

neous structure of the samples. Although the plugs

were carefully selected from the homogeneous/unfrac-

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

Y-17, T

11-0.2

Y-22, T

10-0.5

Y-35, T

10-1

Y-44, T

2-0.01

Y-45, T

12-0.1

Y-54, T

11-1

Y-38, T

5-0.1

Y-10, T

6-0.1

Y-4, T

3-0.1

Y-4, T

3~T2-.1

Core Number, Surfacta

Po

re V

olu

me

Oil

Rec

ove

red

Fig. 3. The performance of waterflooding succeeded by surfactant in

waterflooding and surfactant as pore volume.

tured parts of the cores, microfractures are common in

the Shuaiba chalk and this might cause inconsistent

breakthrough times.

Another performance indicator was the pore vol-

ume (PV) oil recovered with respect to different

surfactant type (Fig. 3). The final recovery fluctuates

between 0.55% and 0.65% of PV oil with two

exceptions, which go above 0.70% of PV. Additional

recovery due to tertiary surfactant injection was also

included in Fig. 3. Samples Y-38 and Y-3 resulted in

75.56% and 75.62% of PV waterflooding recoveries,

respectively. But, 1.03% and 5.33% of PV recoveries

were added by tertiary surfactant injection, respec-

tively. On the other hand, the lowest waterflooding

recoveries were obtained for sample Y-4, Y-9, Y-19,

and Y-23. All these yielded additional surfactant

recoveries: 2.4%, 4.34%, 3.28%, and 3.84% of PV,

which are not the highest surfactant recoveries. Like-

wise, samples Y-17 and Y22 did not produce any oil

due to surfactant injection in spite of their relatively

lower waterflooding recoveries. Obviously, the per-

Y-19, T

8+TC

1-0.1+5

Y-8, T

7-1

Y-46, T

9-0.01

Y-23, T

8-0.01

Y-11, T

1-0.5

Y-12, T

8-0.1

Y-3, T

1-0.1

Y-9, T

2-0.1

Y-14, T

7-0.1

Y-7, T

4-0.01

nt Type, and Percentage

Water Flood

Surfactant Flood

jection for 20 cases. Performance indicator: oil recovery due to


formance of tertiary surfactant recovery (after un-

modified waterflooding) depends on the surfactant

type and concentration but it can be said that no

typical effect of the previous waterflooding (second-

ary recovery) history on the surfactant (tertiary) re-

covery was observed.

For evaluation of the additional recovery by sur-

factant solution injection, the percentage of the recov-

ery due to surfactant as PV and additional recovery

due to tertiary surfactant injection as PV are plotted in

Figs. 4 and 5. The percentage of the oil recovery due

to surfactant injection after waterflooding as PV was

sorted in ascending order in Fig. 4. Six cases yielded

no recovery. These cases include all surfactant types,

namely anionic, cationic and non-ionic. Note that

surfactant types T10, T11, and T12 did not yield

any additional recovery at any concentration values.

Surfactant type T2 resulted in a significant recovery at

0.1% concentration value (7.83%) even though it

showed no additional recovery at lower concentration

(0.01%). The highest percentage of surfactant (tertia-

1.4

3.6

4.3

5.

0.0 0.0 0.0 0.0 0.0 0.00

2

4

6

8

10

12

Y-17, T

11-0.2

Y-22, T

10-0.5

Y-35, T

10-1

Y-44, T

2-0.01

Y-45, T

12-0.1

Y-54, T

11-1

Y-38, T

5-0.1

Y-10, T

6-0.1

Y-4, T

3-0.1

Y-4, T

3~T2-.1

Core Number, Surfactan

Oil

Pro

du

ctio

n(S

urf

acta

nt

to

Wat

er F

loo

d)

%

Fig. 4. The performance of waterflooding succeeded by surfactant injection

to surfactant.

ry) recovery was obtained with surfactant T4 (0.01%)

as being 10.34%. When the surfactant performance

was indicated as oil production due to surfactant

injection after waterflooding (as pore volume) without

changing the order of the core numbers, the trend is

almost the same except two samples: Y-3 and Y-46

(Fig. 5). The descending order will then be T4

(0.01%), T1 (0.1%), T7 (0.1%), T2 (0.1%), T8

(0.1%), T1 (0.5%), and T9 (0.01%) and so on, if the

evaluation is done for oil recovery due to tertiary

surfactant injection as PV.

Figs. 3 and 5 were re-plotted in terms of the

recovery of OOIP rather than PV because each sample

has different Swi values. Slight changes in the recov-

ery were observed in some cases. For example, the

highest PV recovery was obtained for samples Y-38

and Y-3 in Fig. 3, whereas Y-3 and Y-35 turned out to

be the highest % OOIP recovery cases in Fig. 6. The

recovery by tertiary surfactant injection is shown in

Fig. 7. The highest recovery was obtained for surfac-

tant T4. Evaluation of the results in terms of PV

0

5.9 5.96.5

6.9 7.0 7.17.6 7.8

8.7

10.3

Y-19, T

8+TC

1-0.1+5

Y-8, T

7-1

Y-46, T

9-0.01

Y-23, T

8-0.01

Y-11, T

1-0.5

Y-12, T

8-0.1

Y-3, T

1-0.1

Y-9, T

2-0.1

Y-14, T

7-0.1

Y-7, T

4-0.01

t Type, and Concentration

for 20 cases. Performance indicator: percentage of the recovery due

1.0

2.12.4

2.9

3.3 3.4

4.0 3.84.2 4.3

5.3

4.3

5.3

6.1

0.00.00.0 0.0 0.0 0.00.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

Y-17, T

11-0.2

Y-22, T

10-0.5

Y-35, T

10-1

Y-44, T

2-0.01

Y-45, T

12-0.1

Y-54, T

11-1

Y-38, T

5-0.1

Y-10, T

6-0.1

Y-4, T

3-0.1

Y-4, T

3~T2-.1

Y-19, T

8+TC

1-0.1+5

Y-8, T

7-1

Y-46, T

9-0.01

Y-23, T

8-0.01

Y-11, T

1-0.5

Y-12, T

8-0.1

Y-3, T

1-0.1

Y-9, T

2-0.1

Y-14, T

7-0.1

Y-7, T

4-0.01


% P

ore

Vo

lum

e O

il R

eco

vere

d(T

erti

ary

Su

rfac

tan

t F

loo

d)

Fig. 5. The performance of waterflooding succeeded by surfactant injection for 20 cases. Performance indicator: pore volume recovery due to

tertiary surfactant injection.


recovery (Fig. 5) or % OOIP recovery (Fig. 7) did not

show any difference and the same trend was obtained.

In several cases, two surfactant concentration

values were applied for the same surfactant, i.e., T8,

T7, and T1. It is interesting to note that the higher

concentration (lower IFT) did not necessarily yield

higher recovery for two surfactant types (T1 and T7).

For example, for surfactant type T1, 0.5% concentra-

tion (IFT=0.45 mN/m) resulted in higher recovery

(6.59% of OOIP) than that of 0.1% (IFT=1.1 mN/m

and 4.94% of OOIP). But the difference in the IFT

values was trivial. The same can be said for T7. For

surfactant type T8, however, higher concentration

(0.1%) yielded higher recovery (5.1% of OOIP) than

that of (4.9% of OOIP) lower concentration (0.01%).

This is expected because there is a considerable dif-

ference between the IFT values of these two concen-

trations: 8.5 and 0.1 mN/m, respectively (Table 2), as

opposed to the trivial differences in IFT values ob-

served for the different concentrations of surfactant

types T7 and T1.

One sample (Y-4) was exposed to injection of two

different surfactant types. After complete waterflood-

ing, T3 at 0.1% concentration was applied and 2.9%

of OOIP was produced. The process was continued

with a stronger surfactant with high concentration

(T2 at 1%) and an additional recovery of 0.6% of

OOIP was obtained. This indicates that the depen-

dency of the recovery on the surfactant type and

concentration is more pronounced than the previous

flooding history.

3.1.2. Surfactant injection without pre-waterflooding

To clarify whether starting the injection with sur-

factant solution (modified waterflooding) rather than

unmodified waterflooding is more effective, eight

experiments were conducted. The surfactant types

yielding the highest performance in the previous

experiments were selected and the solutions were

injected as modified waterflooding. The lowest and

highest recoveries were observed as 64.17% and

74.8% of OOIP, respectively. The average recovery

was 69.9% of OOIP. Different concentration values

were tested for two surfactant types, T1 and T2.

Higher concentration (or lower IFT) resulted in a

higher recovery for T2 but the opposite was observed

0

10

20

30

40

50

60

70

80

90

100

Y-17, T

11-0.2

Y-22, T

10-0.5

Y-35, T

10-1

Y-44, T

2-0.01

Y-45, T

12-0.1

Y-54, T

11-1

Y-38, T

5-0.1

Y-10, T

6-0.1

Y-4, T

3-0.1

Y-4, T

3~T2-.1

Y-19, T

8+TC

1-0.1+5

Y-8, T

7-1

Y-46, T

9-0.01

Y-23, T

8-0.01

Y-11, T

1-0.5

Y-12, T

8-0.1

Y-3, T

1-0.1

Y-9, T

2-0.1

Y-14, T

7-0.1

Y-7, T

4-0.01


% o

f O

OIP

Rec

ove

red

Water Flood

Surfactant Flood

Fig. 6. The performance of waterflooding succeeded by surfactant injection for 20 cases. Performance indicator: oil recovery due to

waterflooding and surfactant as % OOIP.


for T1. The IFT decreased from 1.1 to 0.45 mN/m

when the concentration is increased from 0.1% to

0.5% for T1. This change is trivial and no significant

effect in the recovery performance is expected. In case

of surfactant type T2, however, the IFT decreased

8 fold (from 7.5 to 0.9 mN/m) by increasing the

concentration from 0.01 to 0.1 mN/m. This is

expected to be the reason behind the difference in

the two recovery values. The performances of T1

and T2 in both modified and unmodified injection

cases are in similar manner.

To compare the modified and unmodified water-

flooding results, the ultimate recoveries are plotted

altogether in Fig. 8. Table 3 summarizes the informa-

tion about the experiments whose results are graphed

in Fig. 8. The average oil recoveries for unmodified

waterflooding and modified (surfactant solution)

waterflooding were found to be 75.1% and 69.9%

of OOIP, respectively. Surprisingly, the addition of

surfactant into water (modified waterflooding as a

secondary recovery fluid) did not yield more recovery

than waterflooding (unmodified) on the average. Eight

waterflooding (unmodified) cases exceeded the high-

est recovery (75.8% of OOIP, experiment 27 in Fig. 8)

by surfactant solution (modified waterflooding).

The ultimate recoveries are sorted in descending

order in Table 4. Three surfactant types (T1, T4, and

T7) showed a consistent behavior for both cases by

yielding the highest recoveries. Type T2 performed in

different ways for both cases. As a tertiary recovery

agent, it resulted in considerably high recovery (5.3%

of OOIP) whereas it yielded a low recovery as a

secondary recovery agent (66.7% of OOIP) that is

below the average recovery value of 69.9% of OOIP.

Another inconsistency appeared in the case of type

T8 supported by additional chemical (TC1 in Table 1).

The highest recovery was obtained with this mixture

when it was injected as a secondary recovery agent

(modified waterflooding). This mixture also yielded a

reasonably good performance (4.2% of OOIP) but not

0.0 0.0 0.0 0.0 0.0 0.0

1.2

2.52.9

3.5

4.2 4.2

4.9 4.9 4.95.1

6.6

5.3

6.5

7.4

0

2

4

6

8

10

Y-17, T

11-0.2

Y-22, T

10-0.5

Y-35, T

10-1

Y-44, T

2-0.01

Y-45, T

12-0.1

Y-54, T

11-1

Y-38, T

5-0.1

Y-10, T

6-0.1

Y-4, T

3-0.1

Y-4, T

3~T2-.1

Y-19, T

8+TC

1-0.1+5

Y-8, T

7-1

Y-46, T

9-0.01

Y-23, T

8-0.01

Y-11, T

1-0.5

Y-12, T

8-0.1

Y-3, T

1-0.1

Y-9, T

2-0.1

Y-14, T

7-0.1

Y-7, T

4-0.01


% o

f O

OIP

Rec

ove

red

by

Ter

tiar

y S

urf

acta

nt

Flo

od

Fig. 7. The performance of waterflooding succeeded by surfactant injection for 20 cases. Performance indicator: recovery due to tertiary

surfactant injection as % OOIP.


the highest as a tertiary injection agent (tertiary injec-

tion of surfactant solution).

The performances of T8 supported by the mutual

solvent (TC1) as injectants in secondary and tertiary

injection processes needed further analysis. The addi-

tive TC1 (mutual solvent) is commonly used in silica

origin formation to prevent the adsorption of surfac-

tant onto silica surface, emulsion preventer, and ren-

der the silica water-wet when mixed with an anionic

surfactant. Because of these properties, it yielded the

highest recovery among the surfactant (modified

waterflooding) cases. In other words, it provided a

better penetration of the injected fluid into formation.

This validates the second point above regarding the

microemulsion effects on the recovery by surfactant

solution injection. As a tertiary injection fluid (after

waterflooding) the addition of the mutual solvent did

not result in an increase in the recovery. Surfactant

type T8 yielded additional 5.1% of OOIP recovery at

0.1% concentration. With the addition of the mutual

solvent, the recovery was 4.2% of OOIP.

When the surfactant solution is injected as a sec-

ondary recovery fluid, the critical issue is the better

penetration of the fluid provided by less emulsion,

more water wettability, and less adsorption. On the

other hand, when the surfactant is injected as a tertiary

recovery fluid (after waterflooding) the critical issue is

the reduced IFT between oil and water and oil and

rock rather than a better penetration causing a better

sweep.

3.2. Static imbibition experiments

This type of experimentation was conducted to

clarify recovery due to capillary imbibition in the

fractured portions of the Shuaiba chalk. Surfactant

solutions are expected to change capillary imbibition

performance on sandstone and chalky carbonates

0

5

10

15

20

25

30

35

40

45

50

55

60

65

70

75

80

85

90

95

100

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27

Experiments in ascending order

% O

OIP

Oil

Rec

ove

ry

Water Injection Surfactant Injection After WaterfloodingContinued With Another Surfactant Surfactant Injection

AVERAGE RECOVERY BY WATER INJECTION ONLY=75.1% AVERAGE RECOVERY BY SURFACTANT INJECTION

ONLY = 69.9%

Fig. 8. A summary of the displacement experiments: comparison of the recoveries due to water injection (unmodified waterflooding) surfactant

injection succeeding waterflooding (tertiary recovery) and surfactant injection (secondary recovery, modified waterflooding). Table 3 displays

the description of each experiment.


(Keijzer and de Vries, 1990; Al-Lawati and Saleh,

1996; Alveskog et al., 1998; Babadagli et al., 1999;

Spinler, 2000; Babadagli, 2001, 2002, 2003). This

change could be due to lowered IFT or change of

the wettability from oil- to water-wet. Recent labora-

tory studies on North Sea chalk showed that the

surfactant solution injection yields considerable in-

crease in the recovery from this rock (Milter and

Austad, 1996; Michels et al., 1996; Austad and Milter,

1997; Austad et al., 1998; Spinler, 2000; Chen et al.,

2000), confirming the previous observations.

After restoring initial conditions by saturating the

samples with brine and displacing by oil, they were

immersed in imbibition tubes filled with brine and

surfactant solution. The ultimate recoveries are

shown in Fig. 9. Brine imbibition yielded a recovery

of 12% of OOIP for two samples. Four surfactant

solution cases resulted in higher ultimate recovery

than with brine. Thus, injection of surfactant solution

has a positive effect on recovery if it is injected into

fractured zones of the field, where capillary imbibition

is expected to be the dominating recovery mechanism.

The recovery performances of the surfactants are

ranked in descending order (from the best to worst

performance) in Table 5. One surfactant type (T11)

was found to be not useful at all as an additive to

water. One of them (T8) should be used at suitable

concentration values for successful process. Some

types could be good candidates for any application,

such as surfactant types T4 and T7. Surfactant type T2

yielded an interesting performance. It gave good

results for static imbibition and as a tertiary recovery

agent but not as a secondary recovery agent (third

column in Table 5). In the environment without a pre-

Table 3

Details about the experiments shown in Fig. 8

Exp. no. Surfactant type

and concentration

Core no. Experiment

1 T3 (0.1%) and

T2 (0.1%)

Y4 Displacement (Water+

Surf. solution)

2 T2 (0.1%) Y9 Displacement (Water+

Surf. solution)


Surf. solution)

4 T7 (1%) Y8 Displacement (Water+

Surf. solution)


Surf. solution)


Surf. solution)

7 T8 (0.1%) with

TC1 (5%)

Y19 Displacement (Water+

Surf. solution)


Surf. solution)


Surf. solution)


Surf. solution)


Surf. solution)


Surf. solution)


Surf. solution)


Surf. solution)


Surf. solution)


Surf. solution)


Surf. solution)


Surf. solution)


Surf. solution)

20 T2 (0.01%) Y39 Displacement

(Surfactant only)


(Surfactant only)


(Surfactant only)


(Surfactant only)


(Surfactant only)


(Surfactant only)

Table 3 (continued)

Exp. no. Surfactant type

and concentration

Core no. Experiment


(Surfactant only)

27 T8 (0.1%) with

TC1 (5%)

Y1 Displacement

(Surfactant only)


flush (modified waterflooding), the recovery perfor-

mance was the lowest (most likely due to retention of

the surfactant).

4. Discussion

The selection of the surfactant concentration is a

critical issue in terms of an effective (higher recov-

Table 4

Displacement recovery performances of different surfactant types

and concentrations

Surfactant type

and conc.

Recovery

(% OOIP)

Experiment

T4 (0.01%) 7.4 Displacement (Water+Surf. solution)








T8 (0.1%) with

TC1 (5%)

4.2 Displacement (Water+Surf. solution)

T7 (1%) 4.2 Displacement (Water+Surf. solution)




T11 (1%) 0 Displacement (Water+Surf. solution)

T12 (0.1%) 0 Displacement (Water+Surf. solution)


T10 (1%) 0 Displacement (Water+Surf. solution)



T8 (0.1%) with

TC1 (5%)

74.8 Displacement (Surfactant only)

T4 (0.1%) 73.5 Displacement (Surfactant only)







0

2

4

6

8

10

12

14

16

18

20

Y6

0 -

T2

- 0

.1%

Y58 -

T8 -

0.1

% +

TC

1 -

5%

Y5

6 -

T2

- 0

.01

%

Y3

2 -

T4

- 0

.1%

Y5

5 -

Bri

ne

Y2

4 -

T1

- 0

.1%

Y2

8 -

T7

- 0

.1%

Y4

2 -

T1

1 -

0.2

%

Y3

4 -

T1

- 0

.5%

Experiments in ascending order

Oil R

eco

very

, %

OO

IP

Fig. 9. A summary of the capillary (static) imbibition experiments: comparison of the recoveries.


ery) and cost efficient process. It was observed that

the change in the IFT is the main issue in the

recovery process, especially for the tertiary applica-

tion of surfactant solution (preceded by waterflood-

ing). Also, the tertiary recovery due to surfactant

injection depends on the surfactant type rather than

the previous history of waterflooding (or the amount

recovered by the waterflooding). Two surfactant

concentration values were applied for three surfac-

tant types: T8, T7, and T1. It is interesting to note

that the higher concentration (lower IFT) did not

necessarily yield higher recovery. For example, for

surfactant T1, 0.5% concentration (IFT=0.45 mN/m)

resulted in a higher recovery (6.6% of OOIP) than

that of 0.1% (IFT=1.1 mN/m and 4.9% of OOIP).

But the difference in the IFTs values is trivial. The

same could be said for T7. For surfactant type T8,

however, higher concentration (0.1%) yielded higher

recovery (5.1% of OOIP) than that of (4.9% of

OOIP) lower concentration (0.01%).

For secondary recovery (modified waterflooding),

the sweep efficiency (or better penetration of the injec-

tant) is more critical. This observation is valid for

viscous displacement in the reservoir matrix. If the

fractures dominate the flow, the recovery mechanism

will change. In this case the same surfactant solution

may not yield the same performance and it was ob-

served that the response of the same surfactant solution

to dynamic and static (capillary) displacement might

differ. Thus, the selection of the proper surfactant type

and even concentration becomes crucial depending on

the recovery mechanism expected.

One of the issues that was not investigated in this

study was the adsorption of the surfactants. The recov-

ery performances, however, imply that considerable

adsorption might have taken place in some of the

cases. Another issue that still remained unanswered is

the effect of NaCl concentration on the surfactant dis-

placement process. The original reservoir fluid was

used to repeat some IFT measurements to investigate

the effects of its salinity on IFT, if it is used as an

injectant. No significant change on IFT measurements

was observed when formation water was used instead

of brine. But the salinity is expected to affect the

surfactant stability and adsorption thereby the recovery

performance.

5. Conclusions

1. Injection of surfactant solution into a fully water-

flooded core (tertiary recovery) resulted in addi-

Table 5

Selection of the best performing surfactants different types of displacement experiments


tional recovery up to 7.4% of OOIP. Average re-

coveries of 19 waterfloods (unmodified) and 8 sur-

factant solution (modified waterflooding) were

found to be 75.1% and 69.9% of OOIP, respective-

ly. Thus, using surfactant solution as a secondary

recovery injectant (modified waterflooding) cannot

be recommended as an efficient process in terms of

both cost and recovery.

2. Surfactant injection is not preferable over water-

flooding for the untouched portion of the reservoir

where the rock matrix dominates the flow (unfrac-

tured portions). For the untouched fractured zones

of the chalk reservoir, starting the project with the

surfactant injection (modified waterflooding) rather

than waterflooding (unmodified) is more effective.

The cost efficiency of the process also needs fur-

ther analysis.

3. To use a surfactant solution for tertiary recovery

(after unmodified waterflooding), surfactant con-

centration and type and, thus IFT are important

factors. In case of using the surfactant solution

for secondary recovery (modified waterflooding)

purpose, sweep efficiency is more important than

the reduction in IFT. The addition of a chemical

(mutual solvent in Table 1) had a positive effect on

the penetration and displacement efficiency during

dynamic displacement efficiency. In fact, surfactant

type T8 with the mutual solvent yielded the highest

secondary recovery (modified waterflooding).

4. Based on observations made in this study, it is

difficult to classify the surfactant types as good

or bad. For example, the best performances were

obtained with T1, T4, and T7 and they are anio-

nic+non-ionic blend, cationic, and non-ionic, re-

spectively. T10, T11, and T12 yielded the lowest

recovery performances and they also comprise of

all three types: cationic, non-ionic, and anionic,

respectively.


Acknowledgments

We would like to thank the Ministry of Oil and Gas,

Oman for the permission to publish this paper. This

study was supported by an internal grant from Sultan

Qaboos University (SQU) (IG/ENG/PMRE/99/01) and

a project from Petroleum Development Oman (PDO)

(CR/ENG/PMRE/01/12). We gratefully acknowledge

this support.

We greatly benefited from the discussion sessions

with Said Al-Abri, Dan Rayes, William I. Ferguson,

Iain Blair, Chris Mijnssen, Amran Al-Marhubi, and

Mohammed Al-Lawatia (PDO) at different phases of

the project. We are also thankful to Brian Thomson

(PDO) for the preparation of the core plugs used in the

experiments and Nayar Afzal (SQU) for the assistance

during the lab work.

Lastly, we wish to express our gratitude to Erkan

Fidan and Matt Ohler (Halliburton Worldwide) for

providing some of the surfactants used in the experi-

ments. Detailed information on the use of the surfac-

tants given by Erkan Fidan was so helpful in leading

us to the right direction during the experimental study.

This paper is an enhanced version of SPE 78352

that was presented at the 2002 SPE EUROPEC,

Aberdeen, UK, Oct. 29–31.

References

Al-Lawati, S., Saleh, S., 1996. Oil recovery in fractured oil reser-

voirs by low IFT imbibition process. SPE 36688, SPE Annual

Tech. Conf. and Exh. Denver, CO, Oct. 6–9.

Alveskog, P.L., Holt, T., Torsaeter, O., 1998. The effect of surfactant

concentration on the Amott wettability index and residual oil

saturation. J. Pet. Sci. Eng. 20, 247–252.

Austad, T., Milter, J., 1997. Spontaneous imbibition of water into

low permeable chalk at different wettabilities using surfactants.

SPE 37236, SPE Int. Symp. On Oilfield Chemistry, Houston,

TX, Feb. 18–21.

Austad, T., et al., 1998. Chemical flooding of oil reservoirs 8:

spontaneous oil expulsion from oil- and water-wet low-per-

meable chalk material by imbibition of aqueous surfactant

solutions. Colloids Surf., A Physicochem. Eng. Asp. 137,

117.

Babadagli, T., 2001. Scaling of capillary co-current and counter-

current capillary imbibition for surfactant and polymer injection

in naturally fractured reservoirs. SPEJ, 465–478 (December).

Babadagli, T., 2002. Dynamics of capillary imbibition when surfac-

tant, polymer and hot water are used as aqueous phase.

J. Colloid Interface Sci. 246 (1), 203–213.

Babadagli, T., 2003. Selection of proper enhanced oil recovery

fluid for efficient matrix recovery in fractured oil reser-

voirs. Colloids Surf., A Physicochem. Eng. Asp. 223 (1–3),

57–175.

Babadagli, T., Al-Bemani, A., Boukadi, F., 1999. Analysis of

capillary imbibition recovery considering the simultaneous

effects of gravity, low IFT, and boundary conditions. SPE

57321, SPE Asia Pacific Improved Oil Recovery Conference,

Kuala Lumpur, Malaysia, Oct. 25–26.

Bae, J.H., 1985. Glenn Pool surfactant-flood expansion project: a

technical summary. SPE Reserv. Eng., 123 (May).

Bae, J.H., Petrick, C.B., 1986. Glenn Pool surfactant flood pilot test:

comparison of laboratory and observation-well data. SPE

Reserv. Eng., 593 (November).

Bae, J.H., Syed, E.U., 1986. Glenn Pool surfactant flood pilot tests:

part II-field operations. SPE 15551, SPE 61st Annual Technical

Conference and Exhibition, New Orleans, LA, October 5–8.

Barua, J., Prescott, T., Haldorsen, H.H., 1986. Financial and tech-

nical decision making for surfactant flooding. SPE 15074, SPE

56th Calif. Reg. Meet., Oakland, CA, April, pp. 2–4.

Baviere, M., Glenat, P.P., Plazanet, V., Labrid, J., 1994. Improve-

ment of the efficiency /cost ratio of chemical EOR processes by

using surfactants, polymers, and alkalis in combination. SPE/

DOE 27821, SPE Ninth Symposium on Imp. Oil Rec., Tulsa,

OK, April 17–20.

Blaskovich, F.T., Thurber, S.S., Echois, D.P., Al-Hinai, K.B.M.,

1985. Reservoir management of the Yibal field in north

Oman: a simulation approach. SPE 13716, SPE Middle East

Oil Tech. Conf. and Exh., Bahrain, March 11–14.

Bos, C.F.M., 1989. Planning of an appraisal/development program

for the complex Khuff carbonate reservoir in the Yibal Field,

north Oman. SPE 17988, SPE Middle East Oil Tech. Conf. and

Exh., Bahrain, March 11–14.

Boneau, D.F., Clampitt, R.L., 1977. A surfactant system for the oil-

wet sandstone of the north Burbank unit. JPT, 501 (May).

Chen, H.L., Lucas, L.R., Nogaret, L.A.D., Yang, H.D., Kenyon,

D.E., 2000. Laboratory monitoring of surfactant imbibition

using computerized tomography. SPE 59006, SPE Int. Petr.

Conf. and Exh., Veracruz, Mexico, Feb., pp. 1–3.

Clark, S.R., Pitts, M.J., Smith, S.M., 1988. Design and application

of an alkaline-surfactant-polymer recovery system to the west

Kiehl field. SPE 17538, SPE Rocky Mountain Regional Meet-

ing held in Casper, WY, May 11–13.

Eckford, P., 1999. Justifying a full field rationalisation: preparing

the Yibal field for the next 30 years. SPE 53226, SPE Middle

East Oil Tech. Conf. and Exh. Bahrain, Feb. 20–23.

Flumerfelt, R.W., Li, X., Cox, J.C., Hsu, W.F., 1993. A cyclic

surfactant-based imbibition/solution gas drive process for low-

permeability, fractured reservoirs. SPE 26373, SPE Ann. Tech.

Conf. and Exh. Houston, TX, Oct., pp. 3–6.

Grant, A.J., 1981. Large scale waterflooding in the Yibal Shuaiba

chalk reservoir, Oman: field performance and simulation stud-

ies. SPE 9587, SPE Middle East Oil Tech. Conf. and Exh.

Bahrain, March 9–12.

Hong, S.A., Bae, J.H., 1990. Field experiment of lignosulfonate

preflushing for surfactant adsorption reduction. SPE Reserv.

Eng., 467 (November).


Hurd, B.G., 1976. Adsorption and transport of chemical species in

laboratory surfactant waterflooding experiments. SPE 5818, SPE

Improved Oil Recovery Symposium, Tulsa, OK, March 22–24.

Jakobsen, S.R., Hovland, F., 1994. Surfactant flooding: technical

and economical conditions to succeed. SPE 27824, SPE/DOE

Ninth Symp. on Imp. Oil Rec., Tulsa, OK, April, pp. 17–20.

Keijzer, P.P.M., de Vries, A.S., 1990. Imbibition of surfactant solu-

tions. SPE 20222, SPE/DOE 7th Symp. on Enhanced Oil Re-

covery, Tulsa, OK, April, pp. 22–25.

Kuhlman, M.I., Lau, H.C., Falls, A.H., 2000. Surfactant criteria for

successful carbon dioxide foam in sandstone reservoirs. SPE

Reserv. Evalu. Eng., 35 (February).

Lawson, J.B., 1978. The adsorption of non-ionic and anionic sur-

factants of sandstone and carbonate. SPE 7052, SPE Fifth

Symp. on Imp. Oil Rec., Tulsa, OK, April 16–19.

Lawson, J.B., Dilgren, R.E., 1978. Adsorption of sodium alkyl aryl

sulfonates on sandstone. SPEJ, 75 (February).

Lewis, S.J., Verkruyse, L.A., Salter, S.J., 1986. Selection of non-

ionic surfactants for minimized adsorption and maximized sol-

ubilization. SPE/DOE 14910, SPE Fifth Symp. on Enh. Oil Rec,

Tulsa, OK, April 20–23.

Litsey, L.R., MacBride, W.L., Al-Hinai, K.M., Dismukes, N.B.,

1986. Shuaiba reservoir geological study, Yibal field, Oman.

JPT, 651 (June).

Maerker, J.M., Gale, W.W., 1992. Surfactant flood process design

for Loudon. SPE Reserv. Eng., 36 (February).

Mannhardt, K., Schramm, L.L., Novosad, J.J., 1990. Effect of rock

type and brine composition on adsorption of two foam-forming

surfactants. SPE 20463, SPE 65th Annual Technical Conference

and Exhibition, New Orleans, LA, September 23–26.

Michels, A.M., Djojosoeparto, R.S., Haas, H., Mattern, R.B., van

der Weg, P.B., Schulte, W.M., 1996. Enhanced waterflooding

design with dilute surfactant concentrations for North Sea con-

ditions. SPE Reserv. Eng., 189 (Aug.).

Milter, J., Austad, T., 1996. Chemical flooding of oil reservoirs 6:

evaluation of the mechanism for oil expulsion by spontaneous

imbibition of brine with and without surfactant in water-wet,

low-permeable, chalk material. Colloids Surf., A Physicochem.

Eng. Asp. 113, 269.

Mugheiry, M.A., Al-Barwany, A., Al-Abry, Y., Lozano, J., Al-

Lawati, M., 2001. A pragmatic approach to injection manage-

ment of a large water flood in the largest field in Oman. SPE

68068, Middle East Oil Tech. Conf. and Exh. held in Bahrain,

March 17–20.

Ramirez, W.F., Friedman, F., Denoyelle, L.C., Shuler, P.J., 1980.

Adsorption and interfacial tension dynamics of surfactants in

porous media. SPE 9280, SPE 55th Annual Fall Technical

Conference and Exhibition, Dallas, Texas, September 21–24.

Saad, N., Pope, G.A., Sepehrnoori, K., 1989. Simulation of Big

Muddy surfactant pilot. SPE Reserv. Eng., 24 (February).

Salager, J.L., Morgan, J.C., Schechter, R.S., Wade, W.H., Vasquez,

E., 1979a. Optimum formulation of surfactant/water/oil systems

for minimum interfacial tension or phase behavior. SPEJ, 107

(April).

Salager, J.L., Bourrel, M., Schechter, R.S., Wade, W.H., 1979b.

Mixing rules for optimum phase behavior formulations of sur-

factant/oil/water systems. SPEJ, 271 (October).

Spinler, E.A., 2000. Enhancement of oil recovery using a low

concentration of surfactant to improve spontaneous and forced

imbibition in chalk. SPE 59290, SPE/DOE Imp. Oil. Rec.

Symp., Tulsa, OK, April, pp. 3–5.

Stournas, S., 1983. Brine-resistant sulfonate surfactants for en-

hanced oil recovery. SPE 11773, SPE International Sympo-

sium on Oilfield and Geothermal Chemistry, Denver, CO.,

June 1–3.

Tabatabai, A., Gonzalez, M.V., Harwell, J.H., Scamehorn, J.F.,

1991. Reducing surfactant adsorption on carbonate reservoirs.

SPE 24105 Unsolicited.

Tsau, J.S., Syahputra, A.E., Grigg, R.B., 2000. Economic evaluation

of surfactant adsorption in CO2 foam application. SPE 59365,

SPE/DOE Improved Oil Recovery Symposium, Tulsa, OK,

April 3–5.

A laboratory feasibility study of dilute surfactant injection for the Yibal field, Oman

Documents

Transcript of A laboratory feasibility study of dilute surfactant injection for the Yibal field, Oman