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Experimental study of high-temperature CO2 foam flooding after hot-water injection in developing heavy oil reservoirs
Journal Pre-proof Experimental study of high-temperature CO2 foam flooding after hot-water injection in developing heavy oil reservoirs Peng Liu, Lanxiang Shi, Pengcheng Liu, Lei Li, Daode Hua PII:
S0920-4105(19)31018-6
DOI:
https://doi.org/10.1016/j.petrol.2019.106597
Reference:
PETROL 106597
To appear in:
Journal of Petroleum Science and Engineering
Received Date: 22 March 2019 Revised Date:
27 August 2019
Accepted Date: 14 October 2019
Please cite this article as: Liu, P., Shi, L., Liu, P., Li, L., Hua, D., Experimental study of high-temperature CO2 foam flooding after hot-water injection in developing heavy oil reservoirs, Journal of Petroleum Science and Engineering (2019), doi: https://doi.org/10.1016/j.petrol.2019.106597. This is a PDF file of an article that has undergone enhancements after acceptance, such as the addition of a cover page and metadata, and formatting for readability, but it is not yet the definitive version of record. This version will undergo additional copyediting, typesetting and review before it is published in its final form, but we are providing this version to give early visibility of the article. Please note that, during the production process, errors may be discovered which could affect the content, and all legal disclaimers that apply to the journal pertain. © 2019 Published by Elsevier B.V.
Experimental study of high-temperature CO2 foam flooding after
1
hot-water injection in developing heavy oil reservoirs
2
Peng Liua,b, Lanxiang Shi c, Pengcheng Liua, b,
3 4 5 6 7
1
Lei Li a,b, Daode Huaa,b
a
School of Energy Resources, China University of Geosciences, Beijing 100083, China
b
Key Laboratory of Marine Reservoir Evolution and Hydrocarbon Enrichment Mechanism, Ministry of Education, Beijing
100083, China c
Research Institute of Petroleum Exploration and Development, PetroChina, Beijing, 100083, China
8
ABSTRACT: Hot water flooding is one of the main strategies employed in the recovery of heavy oil. However,
9
the low viscosity of the injected hot water readily generates the formation of water channels in oil bearing
10
formations with high permeability, resulting in relatively low oil recovery. This study addresses this issue by
11
experimentally investigating the application of a CO2 foam injection process as a secondary strategy after hot
12
water injection. Six surfactants were evaluated for foam generation at temperatures in the range of 57-200°C in
13
a series of screening tests, including static foam tests, thermal stability testing, and resistance factor evaluation.
14
The optimum surfactant was accordingly selected for application in the CO2 foam injection process. The
15
addition of 0.04 wt% anionic polyacrylamide (HPAM) as a stabilizer in the selected surfactant produced a more
16
stable foam appropriate for use at a temperature of 80 °C or less. Oil displacement experiments were conducted
17
using both a high permeability sand pack and a low permeability sand pack simultaneously to investigate water
18
channel creation during hot water injection and the channel blockage resulting from the injected foam along with
19
the corresponding oil recovery enhancement. The experimental results indicate that hot water in the hot water
20
injection process flows readily through the high permeability sand pack and reduces the oil viscosity, which
21
results in an increased degree of water channeling of the high-permeability sand pack. The high-temperature CO2
22
foam generated under optimum conditions using the selected surfactant effectively blocks the water channeling
23
created during the preceding hot water injection process and significantly increases the oil displacement
24
efficiencies of both the low- and high-permeability sand packs. The results of this study demonstrate that the
1
Correspondence author.
E-mail address:[email protected] (P. Liu). 1
1
secondary injection of CO2 foam following hot water injection represents a promising heavy oil recovery strategy
2
for developing heavy oil reservoirs.
3
Keywords: Heavy oil reservoirs; CO2; Foam flooding; Hot water flooding; Enhanced oil recovery;
4
Heterogeneity
5
1. Introduction
6
Heavy oil is a highly viscous and high-density oil that forms a significant component in more than
7
two-thirds of the oil reserves worldwide (Meyer et al., 2007). The sensitivity of oil viscosity to temperature has
8
fostered the use of thermal recovery methods as the primary strategy employed in heavy oil recovery. Presently,
9
these methods mainly include hot water flooding, cyclic steam stimulation (CSS), steam flooding (SF), and
10
steam assisted gravity drainage (SAGD) (Butler et al., 1981; Liu et al., 2015; Hu et al.,2017). In addition, CO2,
11
natural gas, air, and flue gases were also used in the recovery of heavy oil. However, CO2 has gained more
12
attentions in this respect than the other gases in light of its miscible features (Li et al., 2017; Wang et
13
al.,2018;Phukan., 2019).
14
Among the above-discussed thermal recovery methods, hot water injection has received particular interest
15
both with and without an initial injection of unheated water as a proven and effective heavy oil recovery
16
method
17
2016; Rego et al, 2017). However, laboratory experiments, numerical simulations, and field applications have
18
revealed a number of problems associated with this method. Water breakthrough has been proved to be the
19
main problem for most reservoirs after decades of water flooding. Therefore, a larger number of studies have
20
conducted to investigate the enhance oil recovery technology after water and hot water flooding. Zhao and
21
Gates (2015) revealed through numerical simulation that the permeability distribution of heavy oil bearing
22
sediments and formations significantly influenced heavy oil recovery performance of the hot water flooding
23
process. The relatively low viscosity of the injected hot water was found to readily generate the formation of
24
water channels (i.e., water breakthrough) in higher permeability zones within the lower part of the reservoir
25
which reduces the great viscosity difference between the displacement fluid and heavy oil, however, water
that can extend the economic life of an oil field (Goodyear et al., 1996; Alajmi et al., 2014; Hascakir,
2
1
breakthrough easily happens, thereby serious reducing oil displacement and the resulting heavy oil recovery
2
efficiency.
3
Both laboratory experiments and field applications have verified that foam flooding can be an effective
4
method to enhance oil recovery. Wu et al. (2016) conducted a two-dimensional visually experiment to
5
investigate foam flowing characteristics and blocking mechanisms in porous media. With the injection of foam
6
after hot water flooding, the ultimate oil recovery was 67.54%, which was 31.30% higher than that of hot water
7
flooding. Wei et al. (2018) conducted a series of core flooding experiments to study the oil recovery
8
enhancement method for severe heterogeneous oil reservoirs. It was verified that CO2 foam has the advantage
9
of oil displacement in a higher heterogeneity formation and the oil recovery was sharply increased.
10
The main mechanisms of foam flooding for enhancing oil recovery is to decrease the mobility of drive gas
11
and water, and blocking the water channeling, thereby improve the sweep efficiency (Cao et al., 2012; Morte
12
and Hascakir, 2016; Yuan et al., 2018; Zhao et al.,2018). Xu et al. (2017) concluded that both the aerial and
13
vertical sweep efficiencies could be substantially improved by introducing foamed gases. This stems from the
14
improvement of the gas apparent viscosity and reduction in gas relative permeability.
15
The foam injection process has been evaluate using visualization and heavy oil bearing core flooding
16
experiments. Wang et al. (2017) conducted visualization experiments and core flooding experiments to evaluate
17
the performance of CO2 foam. They pointed out that the selection of surfactants is important for foam
18
performance under harsh reservoir conditions. Wu et al. (2016) conducted a two-dimensional visual experiment
19
to investigate the characteristics of foam flow. They also studied the blocking mechanisms using the visual
20
model. However, few experiments have been conducted using two sand packs with different permeability. In
21
general, foam is generated with the injection of surfactant and gases. However, foam is unstable and its stability
22
highly depends on the properties of foam agent (Nguyen et al., 2000). At present, surfactants are the most
23
commonly used foam agent. Screening out an appropriate surfactant for study and field application is a
24
necessary step. Many researchers have engaged in investigating foam agents which characterized with high
25
stability, good foamability, and high salinity tolerance (Chang and Grigg, 1999). Moreover, additives are 3
1
usually applied to enhance the foam by reducing its liquid-film drainage (Hernando et al., 2016). Emrani et al.
2
(2017) demonstrated that the surfactant concentration is essential in the choice of surfactants. Furthermore, they
3
demonstrated that surfactants may degreed at high temperature and high salinity environments.
4
This study experimentally investigates the application of a high-temperature CO2 foam injection process
5
as a secondary strategy after hot water injection for enhanced heavy oil recovery performance.
6
of anionic sulfonate surfactants obtained from different companies are preliminarily evaluated in solution with
7
either distilled water or synthetic brine to determine their potential for use in the foam injection process by
8
conducting various screening experiments, including analyses of static foam properties, thermal stability, and
9
resistance factors. Surfactant #6 is demonstrated to be the optimum foam agent for the proposed foam injection
10
process. Then, the oil displacement performance of surfactant #6 is evaluated by one-dimensional displacement
11
experiments conducted at 57°C or 200°C using a low-permeability sand pack and a high-permeability sand
12
pack simultaneously. Finally, the mechanisms by which the foam injection process enhances the heavy oil
13
recovery of hot water injection are determined. The results of this study demonstrate that high-temperature CO2
14
foam injection is a promising secondary strategy for enhancing the recovery of heavy oil after hot water
15
injection.
16
2. Experiments
17
2.1 Materials
First, six types
18
Brine. Table 1 lists the composition of the formation brine used in the experiments. The PH of the formation
19
brine was 7.3. In the experiments, synthetic brine was prepared according to the composition of the formation
20
brine. The concentration of total dissolved solids (TDS) was 6596.1mg/l.
21
Table. 1. Composition of the formation brine (Unit: mg/L). Ion
K+
Na+
Ca2+
Mg2+
Cl-
HCO3-
CO32-
SO42-
TDS
30.38
1637.57
46.79
22.39
226.28
4627.62
/
5.07
6596.1
Concentration (mg/L)
4
1
Oil. The heavy oil used in the experiments was collected from a typical deep and heavy oil reservoir in the
2
Liaohe oil field, China. Based on previous testing ( Shi et al., 2019), the oil has a density of 0.938 g/cm3. From
3
Fig. 1, at temperature 50 °C, the oil had a viscosity of 142 mPa·s.
Oil viscosity,mPa·s
1000
100
10
1 0
50
100
150
200
250
Temperature,°C
4 5
Fig. 1. Oil viscosity-versus temperature curve of the heavy oil employed in the experiments.
6
Surfactants and stabilizer. In this study, six kinds types of anionic sulfonate surfactants supplied by
7
different commercial companies were tested and evaluated. In addition, a polyacrylamide (HPAM) additive was
8
used as a stabilizer to enhance foam stability of the optimum selected surfactant determined from the screening
9
tests.
10
Sand packs. The length and diameter of the sand packs used in the experiments were 30 cm and 2.5 cm,
11
respectively. In the oil-displacement experiment, two sand packs with same size and different permeability were
12
used. The high permeability sand pack was composed of quartz sand with a mesh size of 80-100, while the low
13
permeability sand pack was composed of quartz sand with a mesh size of 140-160.
14
2.2 Screening experiments
15
The purpose of screening experiments is to preliminarily evaluate the provided surfactants’ foaming
16
potential and choose the proper surfactant for the oil with macroscopic method.
17
2.2.1 Static foam tests
18
The tested static properties including foamability and foam stability of the provided surfactants were 5
1
evaluated according to the foam height and foam half-life obtained at ambient temperature and atmospheric
2
pressure. Although static property tests do not explicitly evaluate the foamability and stability of surfactant
3
foams in porous media, they are efficient means of quickly screening surfactants.
4 5
1) Preparation. Solutions of each surfactant were made up by synthetic brine and distilled water respectively. The concentration of all the surfactant solutions was 0.5wt%.
6
2) Foam generation. Foam was generated by placing 500mL of each solution in measuring glasses and
7
stirring for 60s with a GJ-3S agitator at 9000 r/min. The generated foam was subsequently placed into a graduated
8
cylinder to measure the foam volume.
9
3) Half-life test. Foam half-life is defined as the time required for the foam height to decay to its original
10
value. Therefore, the foam heights were recorded with respect to time to determine the foam half-life.
11
2.2.2 Thermal stability tests
12 13
Thermal stability tests were conducted for the surfactants initially screened according to the static foam property test results. The test procedure is as follows.
14
1) Heating. Surfactant solutions had already been made up in the foam static tests. 50ml of each surfactant
15
solution was put into the oven under ambient atmosphere, and the solution was maintained at a temperature of
16
250 °C for 48h. to be heated for 48 hours.
17
2) Static foam property testing. The heated solutions were removed from the oven and cooled naturally to
18
the ambient temperature. Foam volume and half-life tests were conducted according to the procedures described
19
in the static foam tests.
20
2.2.3 Resistance factor tests
21
Resistance factor (RF) is defined as the ratio of the normalized pressure drop (pressure drop over total
22
flow rate) during foam displacement to that during single-phase water flow. which mirrors the foam block
23
ability directly (Boeije et al., 2017; Chou, 1991; Vikingstad et al., 2005). The RF is expressed as
24
∆
ܴ∆ = ܨೌ , ೢೌೝ
6
(1)
1 2
where ∆Pfoam is the normalized pressure drop during foam displacement, and ∆Pwater is the normalized pressure drop during water or brine flow.
3
The resistance factor in the presence of oil (RFoil) is used to evaluate the foam performance in the presense
4
of oil. It is defined as the ratio of the steady pressure drop during foam displacement to that during water
5
flooding at the same injection rate with the presence of remaining oil (Hosseini-Nasab, et al., 2018; Yang, et al.,
6
2019). The RFoil is expressed as ∆ೌ
ܴܨ = ∆
7
ೢೌೝ
,
(2)
8
where ∆Pfoamflooding is the normalized pressure drop during foam flooding, ∆Pwaterflooding is the normalized
9
pressure drop during waterflooding process. Core flooding experiment was carried out to test foam resistance
10 11 12
factor of the preliminary screened surfactants. The values of RF and RFoil for the surfactant solutions were evaluated by core flooding experiments, which are described as follows.
13
1) Apparatus: The apparatus employed for core flooding experiments is schematically illustrated in Fig. 2.
14
Two ISCO pumps were used to displace surfactant solution and water into the sand pack. Surfactant solution
15
was pumped into the steam generator to heat to the target temperature. To generate foam, the heated surfactant
16
solution was pumped into a foam generator along with CO2 gas fed via a gas mass flow controller. A foam
17
generator was used to generate foam was regulated using a six-way valve. The pressure after the sand pack was
18
recorded, and the volume of displaced water and foam was measured using a graduated cylinder. The entire
19
process was controlled and monitored using a computer and data acquisition system.
20 21 22
2) Procedure: The experimental procedures employed for evaluating sand pack porosity and permeability, and the RF values of the various surfactant foams consisted of the following steps.
Preparation. Prior to conducting the tests, sand was dried in an oven for 48 hours under ambient
23
atmosphere. Inner diameter and length of the sand packs were measured and the volume can be
24
calculated. Then, the sand was filled into the sand pack and compacted by a rubber hammer after it 7
1
cooled to the ambient temperature. In addition, primary selected surfactants were mixed with the
2
synthetic brine to prepare enough 0.5 wt% solutions. Both the low and high permeability sand packs
3
were employed in all subsequent testing.
4
Porosity measurement. Synthetic brine was pumped into the sand pack until it flowed continuously
5
from the outlet. The volume of the brine saturated the sand pack can be calculated, which is regarded
6
as the total pore volume (PV). As a result, the porosity was accordingly calculated by a previously
7
described means (Shi et al., 2019).
8
Permeability measurement. The sand pack was connected to the apparatus as shown in Fig. 2.
9
Distilled water was injected into the sand pack at constant rates of 1.0 1.5, or 2.0 mL/min until the
10
injection pressure was steady. The pressure drop was then measured and the absolute permeability
11
was calculated according to the Darcy’s law.
12
Resistance factor (RF) measurement. The backpressure was maintained at a constant value of 2.0
13
MPa, which is the target reservoir condition. Foam generated using synthetic brine and CO2 gas with
14
a varying gas to liquid ratio was then pumped the sand pack. The injection rate of hot water was kept
15
constant at 2ml/min until the pressure drop (∆Pwater) was remained steady. The temperature was
16
maintained at different values of 57 °C, 80 °C, 200 °C. Then same tests were conducted to the
17
surfactant solutions and the pressure drop (∆Pwater) was obtained. As a result, the corresponding RF
18
can be calculated according to the Eq. (1).
19
Resistance factor test in the presence of oil (RFoil). The sand pack was filled with oil and then
20
water flooding was conducted until the water cut was nearly 100%. The backpressure and
21
temperature were same to that conducted in the previous resistance factor tests. The pressure drop of
22
water flooding (∆Pwaterflooding) was measured. Then synthetic brine and CO2 gas were simultaneously
23
injected into the foam generator to generate foam and pumped into the sand pack, the pressure drop
24
of foam flooding (∆Pfoamflooding) was measured. The resistance factor in the presence of oil (RFoil) can
25
be calculated according to Eq. (2). 8
1 2
Fig. 2. Schematic of experimental setup for resistance factor test.
3
2.3 Oil displacement experiments
4
2.3.1 Apparatus
5
The apparatus employed for conducting oil displacement experiments is schematically illustrated in Fig. 3.
6
Two sand packs filled with different meshes sand were used in these experiments. Surfactant solution was
7
injected to steam generator to get the target temperature. It is noted that this apparatus is similar to the
8
apparatus shown in Fig. 2 , except that the injection system, includes heavy oil, and both high permeability and
9
low permeability sand packs prepared according to the procedure outlined in Subsection 2.2.3 are employed
10
simultaneously in conjunction with their own backpressure monitoring and liquid measurement components.
11
2.3.2 Procedures
12
The experimental procedures in the oil displacement experiments are given as follows.
13
1) Preparation. Sand packs were prepared as the procedures described in the resistance factor tests. The
14
difference is that two sand packs filled with different size sand were used in each experiment. Then porosity
15
and permeability tests for each sand pack were conducted according to the procedures described in the
16
resistance factor tests.
17
2) Oil saturated. The sand packs were parallel mounted into the thermal tank. Dehydrated oil was 9
1
injected into the sand pack. Only one sand pack was saturated with dehydrated oil at a time. The injected oil
2
volume was measured and the initial oil saturation for each sand pack was calculated. Then the temperature of
3
the enclosing oven was kept constant at 57 °C for 48 h.
4
3) Oil displacement. The backpressure of the sand packs was maintained at the target reservoir condition
5
of 2.0 MPa during all experiments Three phases of oil displacement were conducted, which included initial hot
6
water injection, foam injection with the optimum surfactant solution, and a final hot water injection process,
7
each of which was conducted until the water cut reached 98%. In the first phase, hot water was injected at a rate
8
of 3ml/min by an ISCO pump into the steam generator which heated the water to the target temperatures (57 or
9
200 °C). In the second phase of foam injection, the surfactant-brine solution and CO2 gas were co-injected with
10
the optimum liquid to gas ratio at a injection rate of 3.0 mL/min. The foam flooding process was terminated
11
until the average water cut reached 98.0 %. In the final phase, hot water injection was again conducted with the
12
equivalent parameters as the first phase. Meanwhile, the water and oil production for each sand pack were
13
recorded and the total oil production and water cut were measured. The inlet pressure and cumulative water
14
injection were also recorded.
15 16
Fig. 3. Schematic of experimental setup for oil displacement experiments.
17 10
1
3. Results and discussion
2
3.1 Screening experiments
3
The static foam property results including foam volume and foam half-life for all surfactants are shown
4
in Fig. 4 (A) and (B), respectively. Among the surfactant-distilled water solutions, we note from Fig.4 (A) that
5
foam volumes for surfactant #1, #5, and #6 is 605, 610, and 610 mL respectively, which is larger than those of
6
the others. For the foam propagated by surfactant-brine solutions, however, foam volume for surfactant #4, #5,
7
and #6 is larger than those of the others. Moreover, foam volume for surfactant #1, #2, and #3 sharply decrease
8
in solution with synthetic brine, while the foam volumes for surfactants #4 and #6 increase. 650
400 Solvent Solvent
(A)
Distilled water Synthetic brine
Solvent Solvent
(B)
Distilled water Synthetic brine
630
600 600 595 590
590
318
317
316
605
Half-life,s
Foam volume, ml
335
610
610
610
345
350
620
302
300
292 276
585 262 251
575
250
570
570
243 233
560
550
200 #1
9
#2
#3 #4 Surfactant
#5
#6
#1
#2
#3 #4 Surfactant
#5
#6
10
Fig. 4. Static foam property test results: (A) Foam volume; (B) Half-life.
11
With respect to half-lives of the generated foam shown in Fig. 4 (B), half-lives for most surfactants
12
sharply decrease in solution with synthetic brine except for surfactant #6. The foam volume and half-life results
13
demonstrate that brine generally has a significant effect on the static properties of the surfactants owing to the
14
salinity sensitivity of the surfactants. Accordingly, the collective results in Fig. 4 indicate that surfactant #4, #5,
15
and #6 have better salinity tolerance to salinity than all other surfactants evaluated, except for surfactant #6,
16
which actually provides improved static foam properties in solution with synthetic brine. Therefore, surfactants
17
#4, #5, and #6 were selected for further evaluation.
18
The results of thermal stability testing for surfactants #4, #5, and #6 in solution with synthetic brine are
19
listed in Table 2. After heating at 250 °C for 48 hours, the foam volumes for surfactants #4 and #6 were slightly 11
1
decreased, while the foam volume for surfactant #5 was unchanged. What’s more, foam volume for surfactant
2
#6 is the same to #5 after heating. Half-lives for all the surfactants become longer after heating. Half-life for
3
surfactant #6 is 350 s, which is the longest among the initial selected surfactants. Accordingly, we can conclude
4
that all the initially screened surfactants exhibited good thermal stability.
5
Table. 2. Thermal stability tests results for the selected surfactants in solution with synthetic brine. Unheated
Surfactant agent
Heated at 250°C for 48h
Foam volume (ml)
Half-life (s)
Foam volume (ml)
Half-life (s)
#4
610
262
585
306
#5
600
276
600
307
#6
620
345
600
350
6
As surfactant #6 showed the best foamability and stability according to the foam static and thermal
7
stability tests. It was considered to be the best candidate for further evaluation. Therefore, a kind of HPAM
8
stabilizer was added to its solution with concentration of 0.04 and 0.08 wt%, and the static foam properties were
9
also evaluated. As shown in Table 3, with the application of the HPAM, a sharp increase in foam half-life was
10
identified, while foam volume was slightly decreased. The sharp increase in foam half-life indicates that stable
11
foam formation stabilized by the HPAM additive. While the foam volume for the solutions with 0.04 and 0.08 wt%
12
HPAM were nearly equivalent, the foam half-life for the surfactant mixed with 0.08 wt% HPAM was about 540 s
13
greater than that obtained with 0.04 wt% HPAM. This suggests that an increasing HPAM concentration increases
14
the affinity of the stabilizer to the air/water interface.
15
Table. 3. Static foam property test results for surfactant #6 with and without the HPAM stabilizer.
Surfactant agent
Solvent: Distilled water
Solvent: Synthetic brine
Foam volume (ml)
Half-life (s)
Foam volume (ml)
Half-life (s)
#6
610
318
620
345
#6+0.04 wt% HPAM
540
1405
560
1380
#6+0.08 wt% HPAM
530
1968
550
1920
16
The values of RF obtained for surfactants #4, #5, and #6 in solution with brine under various temperatures
17
and gas-to-liquid ratio conditions are listed in Table 4. As shown in the table, the RF for all the evaluated 12
1
surfactants increases with the increase of temperature. However, for the surfactant solution mixed with
2
stabilizer, the RF decreases with the increase of temperature. The reason for this phenomenon is that the
3
polyacrylamide additive is easily decomposed at high temperature conditions. As a result, the polyacrylamide
4
additive was only used in the oil displacement experiments which was conducted at 57 °C.
5
Table. 4. Resistance factor tests results for the initially selected surfactants in solution with synthetic brine. Temperature
Gas to
(°C)
liquid ratio
57
80
200
#4
#5
#6
#6+0.04wt%HPAM
#6+0.08wt%HPAM
RF
RFoil
RF
RFoil
RF
RFoil
RF
RFoil
RF
RFoil
1:02
0.5
0.3
0.5
0.3
6.5
4.5
22.4
16.4
23.8
17.5
1:01
1.4
1
1.1
1
10.1
7.8
40.2
32.3
42.8
32.1
2:01
1.1
0.7
0.4
0.3
11.3
8.6
276
205
330
223
1:02
1.6
1.2
/
/
15.6
11.5
20.4
15.2
/
/
1:01
2.4
1.8
/
/
26.8
17.4
85.4
60.7
/
/
2:01
1.5
1
/
/
22.1
15.1
148
107.3
/
/
1:02
18.7
12.3
/
/
29.5
20.2
/
/
/
/
1:01
25.4
16.1
/
/
35.7
24.8
/
/
/
/
2:01
14.9
10.3
/
/
24.8
15.9
/
/
/
/
6
For surfactants #4 and #5, the value of RF obtained at the temperature of 57 and 80 °C for surfactant #4
7
and #5 are too small to block regions of high permeability. In contrast, the value of RF for surfactant #6 is much
8
larger, which is larger enough for blocking in high permeability regions. With the application of stabilizer, RF
9
for surfactant #6 increases sharply. For surfactant #6 at 80 and 200 °C, the optimal gas to liquid ratio is 1:1. At
10
temperature of 57 °C, the RF for surfactant #6 mixed with HPAM increase with gas to liquid ratio and the
11
concentration of HPAM. The RF shows a sharp increase when the gas to liquid ratio increase from 1:1 to 2:1.
12
With the gas to liquid ratio of 2:1, however, the RF is slightly increased when the concentration of HPAM
13
increased from 0.04 to 0.08 wt%. At the temperature of 200 °C, when the gas to liquid ratio is 1:1, the RF of
14
surfactant #6 is the largest. The resistance factor in the presence of oil (RFoil) were also tested for each surfactant.
15
Due to the presence of oil, the RFoil decreases which means oil has negative effect on the stability of foam.
16
However, surfactant #6 with 0.04 wt% HPAM addedshows the largest RFoil. As a result, surfactant #6 was
17
selected for further evaluation and 0.04 wt% HPAM was used as an additive in the 57 °C foam flooding. In 13
1
addition, the optimal gas to liquid ratio for foam flooding conducted at 57 and 200 °C was 2:1 and 1:1,
2
respectively.
3
3.2 Oil displacement experiments
4
The parameters of the sand packs used in the oil displacement experiments are listed in Table 5. From the
5
table, the permeability values of the high-permeability sand packs were greater than those of the
6
low-permeability sand packs by factors of approximately 3.4.
7
Table. 5. Parameters of the sand packs.
Experimental
Experimental temperature
Sand
Length
Inner diameter
Sand
Porosity
Permeability
No.
(°C)
pack
(cm)
(cm)
(mesh)
(%)
(mD)
1
57
A1
30
2.501
140-160
24.95
867.15
B1
30
2.500
80-100
27.12
2910.95
A2
30
2.498
140-160
24.73
858.06
B2
30
2.500
80-100
27.05
2896.23
2
200
8
Table 6 and Table 7 tabulate experimental results of oil displacement at 57 and 200 °C, respectively. As
9
shown in Table 6, after water flooding in the first experimental phase, the displacement efficiency of sand pack
10
A1 and B1 are 27.74 and 60.02%, respectively. The oil displacement efficiency of sand pack B1 is 32.28%
11
bigger than that of A1. However, the injected PV for sand pack A1 and B1 are 0.554 and 6.255, respectively. It
12
indicates that most of water was injected into the high permeable sand pack B1.
13
From Table 7, after the first phase of water flooding, the oil displacement efficiency of sand pack B2 is
14
58.53% than that of sand pack A2. Moreover, injected PV of sand pack A2 and B2 are 0.099 and 11.581,
15
respectively. From Fig. 5, water cut for both sand packs in experiment 1 rise quickly in the early stage of water
16
flooding, while water cut for sand pack A2 in experiment 2 is very low. The reason for this phenomenon is that
17
water breakthrough and channeling seriously decreased the sweep efficiency and most of the water flowed
18
through the higher permeable sand pack (sand pack B1).
19
Table. 6. Results of oil displacement experiment 1 (Temperature: 57 °C).
14
Experimental
Sand
Original oil
Remaining oil
Displacement
Enhanced displacement
Injected
phase
pack
saturation (%)
saturation (%)
efficiency (%)
efficiency (%)
PV
1. Water
A1
71.76
51.85
27.74
/
0.554
B1
66
26.39
60.02
/
6.255
Average
/
39.5
42.71
/
3.464
A1
51.85
39.64
44.76
17.02
0.656
B1
26.39
11.79
82.14
22.12
2.107
Average
/
26.17
62.05
19.34
1.273
A1
39.64
39.12
45.48
0.72
0.19
B1
11.79
7.42
88.76
6.62
6.816
Average
/
23.77
65.52
3.47
5.089
flooding
2. Foam flooding
3. Water flooding
1
Table. 7. Results of oil displacement experiment 2 (Temperature: 200 °C). Original oil
Displacement
Enhanced
efficiency
displacement
(%)
efficiency (%)
55.85
15.63
/
0.099
67.0
17.31
74.16
/
11.581
Average
/
35.29
47.01
/
3.38
A2
55.85
22.34
66.26
50.63
1.327
B2
17.31
15.93
76.22
2.06
1.532
Average
/
16.74
72.24
27.86
1.01
A2
22.34
19.22
70.9
4.76
2.163
B2
15.93
15.93
76.22
0.00
1.852
Average
/
15.09
74.87
2.49
1.35
Experimental
Sand
phase
pack
1.Water
A2
66.2
B2
flooding
2.Foam flooding
3.Water flooding
saturation (%)
Remaining oil saturation (%)
Injected PV
2
In summary, serious inconformity was observed in these experiments. After the first stage of each
3
experiment which conducted water flooding, the oil displacement efficiency shows a large difference. Oil
4
displacement of the sand pack with higher permeability is much bigger than the other one. The main reason for
5
the inconformity in the experiments is mainly caused by the permeability ratio of the sand packs, thus leads to
6
big difference in oil mobility which is defined as follows:
15
ߣ =
1
ఓ
,
(3)
2
Where ko andμo are oil permeability and oil viscosity, respectively.
3
Moreover, with the increase of the temperature of the injected water, the inconformity between the sand
4
packs become more serious. The main reason for this phenomenon is caused by the sharply decreased oil-water
5
viscosity ratio, which leads to larger oil-water mobility ratio. Oil-water mobility ratio is defined at the ratio of
6
oil and water mobility. The equation is expressed as
ߣ = ܯ /ߣ௪ = ቀఓ ቁ / ቀఓೢ ቁ,
7
ೢ
(4)
8
As the initial temperature of all these experiments was 57 °C, the oil-water viscosity ratio was 191.4, while
9
it sharply decreased to 15.76 at temperature of 200 °C. In experiment 2, water was injected into the higher
10
permeable sand pack B2 at first. With the injection of water, temperature of sand pack B2 increased and the oil
11
viscosity decreased sharply. As a result, almost all the injected water was flowed through sand pack B2 and sand
12
pack A2 was rarely displaced.
13
In the second experimental phase, with the conducting of foam flooding, water cut of all the sand packs
14
are sharply decreased (in Fig. 5 (A) and (B)). Oil displacement efficiency of sand pack A1 and B1 in experiment
15
1 are increased to 44.76% and 82.14%, respectively (in Table 6). The average displacement efficiency for
16
experiment 1 and 2 are increased by 19.34 and 27.86%, respectively (in Table 6 and 7).
17
From Table 7, the injected PV of sand pack A2 and B2 in the foam flooding stage is nearly the same, which
18
means solutions was almost evenly injected into these sand packs. In experiment 1, however, more than 76% of
19
the solutions was injected into the higher permeable sand pack B1. The experimental results show that, in the
20
presence of oil, foams haven been generated. The generated foam can block the sand pack with higher
21
permeability and the oil in the lower permeable sand pack is displaced, thus lead to higher sweep efficiency. It
22
mirrors the blocking mechanism in the development of reservoirs with sever heterogeneity. The injection of
23
foam is an effective enhance oil recovery method. In addition, CO2 core flooding experiments were conducted
24
in the previous studies by Shi et al. (2019). The results show that with the injection of CO2, oil displacement 16
efficiency was 52.7 and 74.7%, respectively. The improve of displacement efficiency of the low permeability
2
sand pack is partly caused by CO2 injection. However, the foam generated in experiment 1 is weaker than that
3
generated in experiment 2. The selected surfactant shows a well foamability and stability at the temperature of
4
200 °C. With the application of foam flooding, oil displacement efficiency for both the low and high permeable
5
sand packs are improved. 100
100
90
90
Displacement efficiency, %; Water cut, %
Displacement efficiency, %; Water cut, %
1
80 70 60
(A) 50 40 A-Displacement efficiency
30
A-Water cut B-Displacement efficiency
20
B-Water cut Total-Displacement efficiency
10
80 70 60 (B) 50 40 30
A-Displacement efficiency A-Water cut
20
B-Displacement efficiency B-Water cut
10
Total-Displacement efficiency
Total-Water cut
Total-Water cut
0
0 0
1
2
3
6 7 8
4
5
6
7
8
9
10
11
12
0
1
PV injected
2
3
4
5
6
7
8
PV injected
Fig. 5. Production curve at various temperature. (A) Temperature: 57 °C; (B) Temperature: 200 °C.
4. Conclusions
9
1) Based on a combined analysis of foam volumes, foam half-lives, thermal stabilities, and resistance
10
factors, surfactant #6 demonstrated the best foamability, foam stability, and thermal stability in solution with
11
synthetic brine at a temperature range of 57 -200°C. The addition of 0.04 wt% HPAM as a stabilizer produced a
12
more stable foam appropriate for use at temperatures of 80 °C or less.
13 14
2) In the hot water flooding process, the injected hot water flowed through the high-permeability sand pack and reduced the oil viscosity, which result in an increased degree of water channeling.
15
3) The high-temperature CO2 foam generated under optimum conditions using surfactant #6 effectively
16
blocked the water channeling created during the preceding hot water flooding, and significantly increased the
17
oil displacement efficiencies of both the high- and low-permeability sand packs.
18
4) The results of this study demonstrate that high- temperature CO2 foam flooding can be a promising 17
1
method to enhance oil recovery after hot water flooding.
2
Acknowledgements
3
The authors would like to acknowledge the financial support of the National Natural Science Foundation
4
of China (51774256), the Fundamental Research Funds for the Central Universities of China (2652018239),
5
and the Science and Technology Special Funds of China (2016ZX05016-006 and 2016ZX05012-003).
6
References
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Boeije, C.S., Bennetzen, M.V., Rossen, W.R., 2017. A methodology for screening surfactants for foam enhanced oil recovery in an oil-wet reservoir. SPE Res. Eval. Eng. 20(04), 795-808. Butler, R.M., Mcnab, G.S., Lo, H.Y., 1981. Theoretical studies on the gravity drainage of heavy oil during in-situ steam heating. Can. J. Chem. Eng. 59: 455-460. Chang, S.H, Grigg, R.B., 1999. Effects of foam quality and flow rate on CO2-foam behavior at reservoir conditions. SPE Res. Eval. Eng. 2(3), 248-254. Cao, Y., Liu, D., Zhang, Z., et al., 2012. Steam channeling control in the steam flooding of super heavy oil reservoirs, Shengli Oilfield. Pet. Explor. Dev. 39(6), 785-790. Chou, S.I., 1991. Conditions for generating foam in porous media. In: SPE 22628. Presented at SPE Annual Technical Conference and Exhibition, Dallas, Texas, 6-9 October.
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Emrani, A.S., Nasr-EI-Din, H.A., 2017. Stabilizing CO2 foam by use of nanoparticles. SPE J. 22(02), 494-504.
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Goodyear, S.G., Reynolds, C.B., Townsley, P.H., 1996. Hot water flooding for high permeability viscous oil fields. In: SPE 35373.
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Presented at the 1996 SPE/DOE Tenth Symposium on Improved Oil Recovery held in Tulsa OK, 21-24 April.
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Hascakir, B. 2016. How to select the right solvent for solvent-aided steam injection processes. J. Pet. Sci. Eng, 146, 746-751.
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Hernando, L., Bertin, H.J., Omari, A., et al., 2016. Polymer-enhanced foams for water profile control. In: SPE 179581. Presented
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at SPE Improved Oil Recovery Conference, Tulsa, Oklahoma, USA, 11-13 April. Hosseini-Nasab, S.M., Douarche, F., Simjoo, M., et al., 2018. Numerical simulation of foam flooding in porous media in the 18
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absence and presence of oleic phase. Fuel. 225, 655-662. Hu, L., Li, H. A., Babadagli, T., & Ahmadloo, M. 2017. Experimental investigation of combined electromagnetic heating and solvent-assisted gravity drainage for heavy oil recovery. J. Pet. Sci. Eng. 154, 589-601.
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Liu, P., Li, W., Shen, D., 2015. Experimental study and pilot test of urea- and urea-and-foam-assisted steam flooding in heavy oil
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reservoirs. J. Pet. Sci. Eng. 135, 291-298. Meyer, R.F. Attanasi E.D., Freeman, P.A., 2007. Heavy oil and natural bitumen resources in geological basins of world. Open-file report 2007-1084. Morte, M., & Hascakir, B. 2016. Estimation of pseudo-relative permeability curves through an analytical approach for steam assisted gravity drainage (SAGD) and solvent aided-steam assisted gravity drainage. J. Unconv.Oil Gas Resour. 16, 45-52.
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Nguyen, Q.P., Alexandrov, A.V., Zitha, P.L., et al., 2000. Experimental and modeling studies on foam in porous media: a review.
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Phukan, R., Gogoi, S.B., Tiwari, P., 2019. Alkaline-surfactant-alternated-gas/CO2 flooding: effects of key parameters. J. Pet. Sci. Eng. 173, 547-557. Rego, F.B., Botechia, V.E., Schiozer, D.J., 2017. Heavy oil recovery by polymer flooding and hot water injection using numerical simulation. J. Pet. Sci. Eng. 153, 187-196. Shi, L., Liu, P., Shen, D., et al. 2019. Improving heavy oil recovery using top driving CO2 assisted hot-water flooding method in deep and pressure-depleted reservoirs. J. Pet. Sci. Eng. 173, 922-931. Vikingstad, A.K., Skauge, A., Harald, H., et al., 2005. Foam–oil interactions analyzed by static foam tests. Colloids. Surf. A. Physicochem. Eng. Asp. 260, 189-198. Wang, C., Liu, P., Wang, F., Atadurdyyev, B., & Ovluyagulyyev, M. 2018. Experimental study on effects of CO2 and improving oil recovery for CO2 assisted SAGD in super-heavy-oil reservoirs. J. Pet. Sci. Eng. 165, 1073-1080. Wang, Y., Zhang, Y., Liu, Y., 2017. The stability study of CO2 foams at high pressure and high temperature. J. Pet. Sci. Eng. 154, 234-243. Wei, P., Pu, W., Sun, Y., et al., 2018. Oil recovery enhancement in low permeable and severe heterogeneous oil reservoirs via gas
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and foam flooding. J. Pet. Sci. Eng. 163, 340-348. Meyer, R.F. Attanasi E.D., Freeman, P.A., 2007. Heavy oil and natural bitumen resources in geological basins of world. Open-file report 2007-1084. Wu, Z., Liu, H., Pang, Z., et al., 2016. A visual investigation of enhanced heavy oil recovery by foam flooding after hot water injection. J. Pet. Sci. Eng. 147, 361-370. Xu. X., Saeedi, A., Liu, K., 2017. An experimental study of combined foam/surfactant polymer (SP) flooding for carbone dioxide-enhanced oil recovery (CO2-EOR). J. Pet. Sci. Eng. 149, 603-611. Yang, J., Wang, X., Peng, X., et al., 2019. Experimental studies on CO2 foam performance in the tight cores. J. Pet. Sci. Eng. 175 1136-1149. Yuan, Z., Liu, P., Gao, Y., et al., 2018. Experimental study on blocking mechanism of nitrogen foam for enhancing oil recovery in heavy oil reservoirs. Energy Sources, Part A: Recovery, Utilization, and Environmental Effects, 40(16), 1947-1955. Zhang, N., Yin, M., Wei, M., et al., 2019. Identification of CO2 sequestration opportunities: CO2 miscible flooding guidelines. Fuel. 241, 459-467.
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Zhao, D., Gates, I.D., 2015. On hot water flooding strategies for thin heavy oil reservoirs. Fuel. 153, 559-568.
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Zhao, Q., Li, Z., Wang, S., Lai, F., & Li, H.2018. Phase behavior measurements and modeling for N2/CO2/extra heavy oil mixtures
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20
Highlights
1
2
► Mechanisms of water breakthrough in the hot water flooding process was studied.
3
► A kind of surfactant with good foamability and stability was screened out to be a good candidate for high
4
temperature CO2 foam flooding.
5
► Mechanisms of improving oil recovery and blocking the water channel for high temperature CO2 foam
6
flooding were investigated.
7
► High temperature CO2 foam flooding was verified to be a following strategy after hot water flooding.
8
S0920-4105(19)31018-6
DOI:
https://doi.org/10.1016/j.petrol.2019.106597
Reference:
PETROL 106597
To appear in:
Journal of Petroleum Science and Engineering
Received Date: 22 March 2019 Revised Date:
27 August 2019
Accepted Date: 14 October 2019
Please cite this article as: Liu, P., Shi, L., Liu, P., Li, L., Hua, D., Experimental study of high-temperature CO2 foam flooding after hot-water injection in developing heavy oil reservoirs, Journal of Petroleum Science and Engineering (2019), doi: https://doi.org/10.1016/j.petrol.2019.106597. This is a PDF file of an article that has undergone enhancements after acceptance, such as the addition of a cover page and metadata, and formatting for readability, but it is not yet the definitive version of record. This version will undergo additional copyediting, typesetting and review before it is published in its final form, but we are providing this version to give early visibility of the article. Please note that, during the production process, errors may be discovered which could affect the content, and all legal disclaimers that apply to the journal pertain. © 2019 Published by Elsevier B.V.
Experimental study of high-temperature CO2 foam flooding after
1
hot-water injection in developing heavy oil reservoirs
2
Peng Liua,b, Lanxiang Shi c, Pengcheng Liua, b,
3 4 5 6 7
1
Lei Li a,b, Daode Huaa,b
a
School of Energy Resources, China University of Geosciences, Beijing 100083, China
b
Key Laboratory of Marine Reservoir Evolution and Hydrocarbon Enrichment Mechanism, Ministry of Education, Beijing
100083, China c
Research Institute of Petroleum Exploration and Development, PetroChina, Beijing, 100083, China
8
ABSTRACT: Hot water flooding is one of the main strategies employed in the recovery of heavy oil. However,
9
the low viscosity of the injected hot water readily generates the formation of water channels in oil bearing
10
formations with high permeability, resulting in relatively low oil recovery. This study addresses this issue by
11
experimentally investigating the application of a CO2 foam injection process as a secondary strategy after hot
12
water injection. Six surfactants were evaluated for foam generation at temperatures in the range of 57-200°C in
13
a series of screening tests, including static foam tests, thermal stability testing, and resistance factor evaluation.
14
The optimum surfactant was accordingly selected for application in the CO2 foam injection process. The
15
addition of 0.04 wt% anionic polyacrylamide (HPAM) as a stabilizer in the selected surfactant produced a more
16
stable foam appropriate for use at a temperature of 80 °C or less. Oil displacement experiments were conducted
17
using both a high permeability sand pack and a low permeability sand pack simultaneously to investigate water
18
channel creation during hot water injection and the channel blockage resulting from the injected foam along with
19
the corresponding oil recovery enhancement. The experimental results indicate that hot water in the hot water
20
injection process flows readily through the high permeability sand pack and reduces the oil viscosity, which
21
results in an increased degree of water channeling of the high-permeability sand pack. The high-temperature CO2
22
foam generated under optimum conditions using the selected surfactant effectively blocks the water channeling
23
created during the preceding hot water injection process and significantly increases the oil displacement
24
efficiencies of both the low- and high-permeability sand packs. The results of this study demonstrate that the
1
Correspondence author.
E-mail address:[email protected] (P. Liu). 1
1
secondary injection of CO2 foam following hot water injection represents a promising heavy oil recovery strategy
2
for developing heavy oil reservoirs.
3
Keywords: Heavy oil reservoirs; CO2; Foam flooding; Hot water flooding; Enhanced oil recovery;
4
Heterogeneity
5
1. Introduction
6
Heavy oil is a highly viscous and high-density oil that forms a significant component in more than
7
two-thirds of the oil reserves worldwide (Meyer et al., 2007). The sensitivity of oil viscosity to temperature has
8
fostered the use of thermal recovery methods as the primary strategy employed in heavy oil recovery. Presently,
9
these methods mainly include hot water flooding, cyclic steam stimulation (CSS), steam flooding (SF), and
10
steam assisted gravity drainage (SAGD) (Butler et al., 1981; Liu et al., 2015; Hu et al.,2017). In addition, CO2,
11
natural gas, air, and flue gases were also used in the recovery of heavy oil. However, CO2 has gained more
12
attentions in this respect than the other gases in light of its miscible features (Li et al., 2017; Wang et
13
al.,2018;Phukan., 2019).
14
Among the above-discussed thermal recovery methods, hot water injection has received particular interest
15
both with and without an initial injection of unheated water as a proven and effective heavy oil recovery
16
method
17
2016; Rego et al, 2017). However, laboratory experiments, numerical simulations, and field applications have
18
revealed a number of problems associated with this method. Water breakthrough has been proved to be the
19
main problem for most reservoirs after decades of water flooding. Therefore, a larger number of studies have
20
conducted to investigate the enhance oil recovery technology after water and hot water flooding. Zhao and
21
Gates (2015) revealed through numerical simulation that the permeability distribution of heavy oil bearing
22
sediments and formations significantly influenced heavy oil recovery performance of the hot water flooding
23
process. The relatively low viscosity of the injected hot water was found to readily generate the formation of
24
water channels (i.e., water breakthrough) in higher permeability zones within the lower part of the reservoir
25
which reduces the great viscosity difference between the displacement fluid and heavy oil, however, water
that can extend the economic life of an oil field (Goodyear et al., 1996; Alajmi et al., 2014; Hascakir,
2
1
breakthrough easily happens, thereby serious reducing oil displacement and the resulting heavy oil recovery
2
efficiency.
3
Both laboratory experiments and field applications have verified that foam flooding can be an effective
4
method to enhance oil recovery. Wu et al. (2016) conducted a two-dimensional visually experiment to
5
investigate foam flowing characteristics and blocking mechanisms in porous media. With the injection of foam
6
after hot water flooding, the ultimate oil recovery was 67.54%, which was 31.30% higher than that of hot water
7
flooding. Wei et al. (2018) conducted a series of core flooding experiments to study the oil recovery
8
enhancement method for severe heterogeneous oil reservoirs. It was verified that CO2 foam has the advantage
9
of oil displacement in a higher heterogeneity formation and the oil recovery was sharply increased.
10
The main mechanisms of foam flooding for enhancing oil recovery is to decrease the mobility of drive gas
11
and water, and blocking the water channeling, thereby improve the sweep efficiency (Cao et al., 2012; Morte
12
and Hascakir, 2016; Yuan et al., 2018; Zhao et al.,2018). Xu et al. (2017) concluded that both the aerial and
13
vertical sweep efficiencies could be substantially improved by introducing foamed gases. This stems from the
14
improvement of the gas apparent viscosity and reduction in gas relative permeability.
15
The foam injection process has been evaluate using visualization and heavy oil bearing core flooding
16
experiments. Wang et al. (2017) conducted visualization experiments and core flooding experiments to evaluate
17
the performance of CO2 foam. They pointed out that the selection of surfactants is important for foam
18
performance under harsh reservoir conditions. Wu et al. (2016) conducted a two-dimensional visual experiment
19
to investigate the characteristics of foam flow. They also studied the blocking mechanisms using the visual
20
model. However, few experiments have been conducted using two sand packs with different permeability. In
21
general, foam is generated with the injection of surfactant and gases. However, foam is unstable and its stability
22
highly depends on the properties of foam agent (Nguyen et al., 2000). At present, surfactants are the most
23
commonly used foam agent. Screening out an appropriate surfactant for study and field application is a
24
necessary step. Many researchers have engaged in investigating foam agents which characterized with high
25
stability, good foamability, and high salinity tolerance (Chang and Grigg, 1999). Moreover, additives are 3
1
usually applied to enhance the foam by reducing its liquid-film drainage (Hernando et al., 2016). Emrani et al.
2
(2017) demonstrated that the surfactant concentration is essential in the choice of surfactants. Furthermore, they
3
demonstrated that surfactants may degreed at high temperature and high salinity environments.
4
This study experimentally investigates the application of a high-temperature CO2 foam injection process
5
as a secondary strategy after hot water injection for enhanced heavy oil recovery performance.
6
of anionic sulfonate surfactants obtained from different companies are preliminarily evaluated in solution with
7
either distilled water or synthetic brine to determine their potential for use in the foam injection process by
8
conducting various screening experiments, including analyses of static foam properties, thermal stability, and
9
resistance factors. Surfactant #6 is demonstrated to be the optimum foam agent for the proposed foam injection
10
process. Then, the oil displacement performance of surfactant #6 is evaluated by one-dimensional displacement
11
experiments conducted at 57°C or 200°C using a low-permeability sand pack and a high-permeability sand
12
pack simultaneously. Finally, the mechanisms by which the foam injection process enhances the heavy oil
13
recovery of hot water injection are determined. The results of this study demonstrate that high-temperature CO2
14
foam injection is a promising secondary strategy for enhancing the recovery of heavy oil after hot water
15
injection.
16
2. Experiments
17
2.1 Materials
First, six types
18
Brine. Table 1 lists the composition of the formation brine used in the experiments. The PH of the formation
19
brine was 7.3. In the experiments, synthetic brine was prepared according to the composition of the formation
20
brine. The concentration of total dissolved solids (TDS) was 6596.1mg/l.
21
Table. 1. Composition of the formation brine (Unit: mg/L). Ion
K+
Na+
Ca2+
Mg2+
Cl-
HCO3-
CO32-
SO42-
TDS
30.38
1637.57
46.79
22.39
226.28
4627.62
/
5.07
6596.1
Concentration (mg/L)
4
1
Oil. The heavy oil used in the experiments was collected from a typical deep and heavy oil reservoir in the
2
Liaohe oil field, China. Based on previous testing ( Shi et al., 2019), the oil has a density of 0.938 g/cm3. From
3
Fig. 1, at temperature 50 °C, the oil had a viscosity of 142 mPa·s.
Oil viscosity,mPa·s
1000
100
10
1 0
50
100
150
200
250
Temperature,°C
4 5
Fig. 1. Oil viscosity-versus temperature curve of the heavy oil employed in the experiments.
6
Surfactants and stabilizer. In this study, six kinds types of anionic sulfonate surfactants supplied by
7
different commercial companies were tested and evaluated. In addition, a polyacrylamide (HPAM) additive was
8
used as a stabilizer to enhance foam stability of the optimum selected surfactant determined from the screening
9
tests.
10
Sand packs. The length and diameter of the sand packs used in the experiments were 30 cm and 2.5 cm,
11
respectively. In the oil-displacement experiment, two sand packs with same size and different permeability were
12
used. The high permeability sand pack was composed of quartz sand with a mesh size of 80-100, while the low
13
permeability sand pack was composed of quartz sand with a mesh size of 140-160.
14
2.2 Screening experiments
15
The purpose of screening experiments is to preliminarily evaluate the provided surfactants’ foaming
16
potential and choose the proper surfactant for the oil with macroscopic method.
17
2.2.1 Static foam tests
18
The tested static properties including foamability and foam stability of the provided surfactants were 5
1
evaluated according to the foam height and foam half-life obtained at ambient temperature and atmospheric
2
pressure. Although static property tests do not explicitly evaluate the foamability and stability of surfactant
3
foams in porous media, they are efficient means of quickly screening surfactants.
4 5
1) Preparation. Solutions of each surfactant were made up by synthetic brine and distilled water respectively. The concentration of all the surfactant solutions was 0.5wt%.
6
2) Foam generation. Foam was generated by placing 500mL of each solution in measuring glasses and
7
stirring for 60s with a GJ-3S agitator at 9000 r/min. The generated foam was subsequently placed into a graduated
8
cylinder to measure the foam volume.
9
3) Half-life test. Foam half-life is defined as the time required for the foam height to decay to its original
10
value. Therefore, the foam heights were recorded with respect to time to determine the foam half-life.
11
2.2.2 Thermal stability tests
12 13
Thermal stability tests were conducted for the surfactants initially screened according to the static foam property test results. The test procedure is as follows.
14
1) Heating. Surfactant solutions had already been made up in the foam static tests. 50ml of each surfactant
15
solution was put into the oven under ambient atmosphere, and the solution was maintained at a temperature of
16
250 °C for 48h. to be heated for 48 hours.
17
2) Static foam property testing. The heated solutions were removed from the oven and cooled naturally to
18
the ambient temperature. Foam volume and half-life tests were conducted according to the procedures described
19
in the static foam tests.
20
2.2.3 Resistance factor tests
21
Resistance factor (RF) is defined as the ratio of the normalized pressure drop (pressure drop over total
22
flow rate) during foam displacement to that during single-phase water flow. which mirrors the foam block
23
ability directly (Boeije et al., 2017; Chou, 1991; Vikingstad et al., 2005). The RF is expressed as
24
∆
ܴ∆ = ܨೌ , ೢೌೝ
6
(1)
1 2
where ∆Pfoam is the normalized pressure drop during foam displacement, and ∆Pwater is the normalized pressure drop during water or brine flow.
3
The resistance factor in the presence of oil (RFoil) is used to evaluate the foam performance in the presense
4
of oil. It is defined as the ratio of the steady pressure drop during foam displacement to that during water
5
flooding at the same injection rate with the presence of remaining oil (Hosseini-Nasab, et al., 2018; Yang, et al.,
6
2019). The RFoil is expressed as ∆ೌ
ܴܨ = ∆
7
ೢೌೝ
,
(2)
8
where ∆Pfoamflooding is the normalized pressure drop during foam flooding, ∆Pwaterflooding is the normalized
9
pressure drop during waterflooding process. Core flooding experiment was carried out to test foam resistance
10 11 12
factor of the preliminary screened surfactants. The values of RF and RFoil for the surfactant solutions were evaluated by core flooding experiments, which are described as follows.
13
1) Apparatus: The apparatus employed for core flooding experiments is schematically illustrated in Fig. 2.
14
Two ISCO pumps were used to displace surfactant solution and water into the sand pack. Surfactant solution
15
was pumped into the steam generator to heat to the target temperature. To generate foam, the heated surfactant
16
solution was pumped into a foam generator along with CO2 gas fed via a gas mass flow controller. A foam
17
generator was used to generate foam was regulated using a six-way valve. The pressure after the sand pack was
18
recorded, and the volume of displaced water and foam was measured using a graduated cylinder. The entire
19
process was controlled and monitored using a computer and data acquisition system.
20 21 22
2) Procedure: The experimental procedures employed for evaluating sand pack porosity and permeability, and the RF values of the various surfactant foams consisted of the following steps.
Preparation. Prior to conducting the tests, sand was dried in an oven for 48 hours under ambient
23
atmosphere. Inner diameter and length of the sand packs were measured and the volume can be
24
calculated. Then, the sand was filled into the sand pack and compacted by a rubber hammer after it 7
1
cooled to the ambient temperature. In addition, primary selected surfactants were mixed with the
2
synthetic brine to prepare enough 0.5 wt% solutions. Both the low and high permeability sand packs
3
were employed in all subsequent testing.
4
Porosity measurement. Synthetic brine was pumped into the sand pack until it flowed continuously
5
from the outlet. The volume of the brine saturated the sand pack can be calculated, which is regarded
6
as the total pore volume (PV). As a result, the porosity was accordingly calculated by a previously
7
described means (Shi et al., 2019).
8
Permeability measurement. The sand pack was connected to the apparatus as shown in Fig. 2.
9
Distilled water was injected into the sand pack at constant rates of 1.0 1.5, or 2.0 mL/min until the
10
injection pressure was steady. The pressure drop was then measured and the absolute permeability
11
was calculated according to the Darcy’s law.
12
Resistance factor (RF) measurement. The backpressure was maintained at a constant value of 2.0
13
MPa, which is the target reservoir condition. Foam generated using synthetic brine and CO2 gas with
14
a varying gas to liquid ratio was then pumped the sand pack. The injection rate of hot water was kept
15
constant at 2ml/min until the pressure drop (∆Pwater) was remained steady. The temperature was
16
maintained at different values of 57 °C, 80 °C, 200 °C. Then same tests were conducted to the
17
surfactant solutions and the pressure drop (∆Pwater) was obtained. As a result, the corresponding RF
18
can be calculated according to the Eq. (1).
19
Resistance factor test in the presence of oil (RFoil). The sand pack was filled with oil and then
20
water flooding was conducted until the water cut was nearly 100%. The backpressure and
21
temperature were same to that conducted in the previous resistance factor tests. The pressure drop of
22
water flooding (∆Pwaterflooding) was measured. Then synthetic brine and CO2 gas were simultaneously
23
injected into the foam generator to generate foam and pumped into the sand pack, the pressure drop
24
of foam flooding (∆Pfoamflooding) was measured. The resistance factor in the presence of oil (RFoil) can
25
be calculated according to Eq. (2). 8
1 2
Fig. 2. Schematic of experimental setup for resistance factor test.
3
2.3 Oil displacement experiments
4
2.3.1 Apparatus
5
The apparatus employed for conducting oil displacement experiments is schematically illustrated in Fig. 3.
6
Two sand packs filled with different meshes sand were used in these experiments. Surfactant solution was
7
injected to steam generator to get the target temperature. It is noted that this apparatus is similar to the
8
apparatus shown in Fig. 2 , except that the injection system, includes heavy oil, and both high permeability and
9
low permeability sand packs prepared according to the procedure outlined in Subsection 2.2.3 are employed
10
simultaneously in conjunction with their own backpressure monitoring and liquid measurement components.
11
2.3.2 Procedures
12
The experimental procedures in the oil displacement experiments are given as follows.
13
1) Preparation. Sand packs were prepared as the procedures described in the resistance factor tests. The
14
difference is that two sand packs filled with different size sand were used in each experiment. Then porosity
15
and permeability tests for each sand pack were conducted according to the procedures described in the
16
resistance factor tests.
17
2) Oil saturated. The sand packs were parallel mounted into the thermal tank. Dehydrated oil was 9
1
injected into the sand pack. Only one sand pack was saturated with dehydrated oil at a time. The injected oil
2
volume was measured and the initial oil saturation for each sand pack was calculated. Then the temperature of
3
the enclosing oven was kept constant at 57 °C for 48 h.
4
3) Oil displacement. The backpressure of the sand packs was maintained at the target reservoir condition
5
of 2.0 MPa during all experiments Three phases of oil displacement were conducted, which included initial hot
6
water injection, foam injection with the optimum surfactant solution, and a final hot water injection process,
7
each of which was conducted until the water cut reached 98%. In the first phase, hot water was injected at a rate
8
of 3ml/min by an ISCO pump into the steam generator which heated the water to the target temperatures (57 or
9
200 °C). In the second phase of foam injection, the surfactant-brine solution and CO2 gas were co-injected with
10
the optimum liquid to gas ratio at a injection rate of 3.0 mL/min. The foam flooding process was terminated
11
until the average water cut reached 98.0 %. In the final phase, hot water injection was again conducted with the
12
equivalent parameters as the first phase. Meanwhile, the water and oil production for each sand pack were
13
recorded and the total oil production and water cut were measured. The inlet pressure and cumulative water
14
injection were also recorded.
15 16
Fig. 3. Schematic of experimental setup for oil displacement experiments.
17 10
1
3. Results and discussion
2
3.1 Screening experiments
3
The static foam property results including foam volume and foam half-life for all surfactants are shown
4
in Fig. 4 (A) and (B), respectively. Among the surfactant-distilled water solutions, we note from Fig.4 (A) that
5
foam volumes for surfactant #1, #5, and #6 is 605, 610, and 610 mL respectively, which is larger than those of
6
the others. For the foam propagated by surfactant-brine solutions, however, foam volume for surfactant #4, #5,
7
and #6 is larger than those of the others. Moreover, foam volume for surfactant #1, #2, and #3 sharply decrease
8
in solution with synthetic brine, while the foam volumes for surfactants #4 and #6 increase. 650
400 Solvent Solvent
(A)
Distilled water Synthetic brine
Solvent Solvent
(B)
Distilled water Synthetic brine
630
600 600 595 590
590
318
317
316
605
Half-life,s
Foam volume, ml
335
610
610
610
345
350
620
302
300
292 276
585 262 251
575
250
570
570
243 233
560
550
200 #1
9
#2
#3 #4 Surfactant
#5
#6
#1
#2
#3 #4 Surfactant
#5
#6
10
Fig. 4. Static foam property test results: (A) Foam volume; (B) Half-life.
11
With respect to half-lives of the generated foam shown in Fig. 4 (B), half-lives for most surfactants
12
sharply decrease in solution with synthetic brine except for surfactant #6. The foam volume and half-life results
13
demonstrate that brine generally has a significant effect on the static properties of the surfactants owing to the
14
salinity sensitivity of the surfactants. Accordingly, the collective results in Fig. 4 indicate that surfactant #4, #5,
15
and #6 have better salinity tolerance to salinity than all other surfactants evaluated, except for surfactant #6,
16
which actually provides improved static foam properties in solution with synthetic brine. Therefore, surfactants
17
#4, #5, and #6 were selected for further evaluation.
18
The results of thermal stability testing for surfactants #4, #5, and #6 in solution with synthetic brine are
19
listed in Table 2. After heating at 250 °C for 48 hours, the foam volumes for surfactants #4 and #6 were slightly 11
1
decreased, while the foam volume for surfactant #5 was unchanged. What’s more, foam volume for surfactant
2
#6 is the same to #5 after heating. Half-lives for all the surfactants become longer after heating. Half-life for
3
surfactant #6 is 350 s, which is the longest among the initial selected surfactants. Accordingly, we can conclude
4
that all the initially screened surfactants exhibited good thermal stability.
5
Table. 2. Thermal stability tests results for the selected surfactants in solution with synthetic brine. Unheated
Surfactant agent
Heated at 250°C for 48h
Foam volume (ml)
Half-life (s)
Foam volume (ml)
Half-life (s)
#4
610
262
585
306
#5
600
276
600
307
#6
620
345
600
350
6
As surfactant #6 showed the best foamability and stability according to the foam static and thermal
7
stability tests. It was considered to be the best candidate for further evaluation. Therefore, a kind of HPAM
8
stabilizer was added to its solution with concentration of 0.04 and 0.08 wt%, and the static foam properties were
9
also evaluated. As shown in Table 3, with the application of the HPAM, a sharp increase in foam half-life was
10
identified, while foam volume was slightly decreased. The sharp increase in foam half-life indicates that stable
11
foam formation stabilized by the HPAM additive. While the foam volume for the solutions with 0.04 and 0.08 wt%
12
HPAM were nearly equivalent, the foam half-life for the surfactant mixed with 0.08 wt% HPAM was about 540 s
13
greater than that obtained with 0.04 wt% HPAM. This suggests that an increasing HPAM concentration increases
14
the affinity of the stabilizer to the air/water interface.
15
Table. 3. Static foam property test results for surfactant #6 with and without the HPAM stabilizer.
Surfactant agent
Solvent: Distilled water
Solvent: Synthetic brine
Foam volume (ml)
Half-life (s)
Foam volume (ml)
Half-life (s)
#6
610
318
620
345
#6+0.04 wt% HPAM
540
1405
560
1380
#6+0.08 wt% HPAM
530
1968
550
1920
16
The values of RF obtained for surfactants #4, #5, and #6 in solution with brine under various temperatures
17
and gas-to-liquid ratio conditions are listed in Table 4. As shown in the table, the RF for all the evaluated 12
1
surfactants increases with the increase of temperature. However, for the surfactant solution mixed with
2
stabilizer, the RF decreases with the increase of temperature. The reason for this phenomenon is that the
3
polyacrylamide additive is easily decomposed at high temperature conditions. As a result, the polyacrylamide
4
additive was only used in the oil displacement experiments which was conducted at 57 °C.
5
Table. 4. Resistance factor tests results for the initially selected surfactants in solution with synthetic brine. Temperature
Gas to
(°C)
liquid ratio
57
80
200
#4
#5
#6
#6+0.04wt%HPAM
#6+0.08wt%HPAM
RF
RFoil
RF
RFoil
RF
RFoil
RF
RFoil
RF
RFoil
1:02
0.5
0.3
0.5
0.3
6.5
4.5
22.4
16.4
23.8
17.5
1:01
1.4
1
1.1
1
10.1
7.8
40.2
32.3
42.8
32.1
2:01
1.1
0.7
0.4
0.3
11.3
8.6
276
205
330
223
1:02
1.6
1.2
/
/
15.6
11.5
20.4
15.2
/
/
1:01
2.4
1.8
/
/
26.8
17.4
85.4
60.7
/
/
2:01
1.5
1
/
/
22.1
15.1
148
107.3
/
/
1:02
18.7
12.3
/
/
29.5
20.2
/
/
/
/
1:01
25.4
16.1
/
/
35.7
24.8
/
/
/
/
2:01
14.9
10.3
/
/
24.8
15.9
/
/
/
/
6
For surfactants #4 and #5, the value of RF obtained at the temperature of 57 and 80 °C for surfactant #4
7
and #5 are too small to block regions of high permeability. In contrast, the value of RF for surfactant #6 is much
8
larger, which is larger enough for blocking in high permeability regions. With the application of stabilizer, RF
9
for surfactant #6 increases sharply. For surfactant #6 at 80 and 200 °C, the optimal gas to liquid ratio is 1:1. At
10
temperature of 57 °C, the RF for surfactant #6 mixed with HPAM increase with gas to liquid ratio and the
11
concentration of HPAM. The RF shows a sharp increase when the gas to liquid ratio increase from 1:1 to 2:1.
12
With the gas to liquid ratio of 2:1, however, the RF is slightly increased when the concentration of HPAM
13
increased from 0.04 to 0.08 wt%. At the temperature of 200 °C, when the gas to liquid ratio is 1:1, the RF of
14
surfactant #6 is the largest. The resistance factor in the presence of oil (RFoil) were also tested for each surfactant.
15
Due to the presence of oil, the RFoil decreases which means oil has negative effect on the stability of foam.
16
However, surfactant #6 with 0.04 wt% HPAM addedshows the largest RFoil. As a result, surfactant #6 was
17
selected for further evaluation and 0.04 wt% HPAM was used as an additive in the 57 °C foam flooding. In 13
1
addition, the optimal gas to liquid ratio for foam flooding conducted at 57 and 200 °C was 2:1 and 1:1,
2
respectively.
3
3.2 Oil displacement experiments
4
The parameters of the sand packs used in the oil displacement experiments are listed in Table 5. From the
5
table, the permeability values of the high-permeability sand packs were greater than those of the
6
low-permeability sand packs by factors of approximately 3.4.
7
Table. 5. Parameters of the sand packs.
Experimental
Experimental temperature
Sand
Length
Inner diameter
Sand
Porosity
Permeability
No.
(°C)
pack
(cm)
(cm)
(mesh)
(%)
(mD)
1
57
A1
30
2.501
140-160
24.95
867.15
B1
30
2.500
80-100
27.12
2910.95
A2
30
2.498
140-160
24.73
858.06
B2
30
2.500
80-100
27.05
2896.23
2
200
8
Table 6 and Table 7 tabulate experimental results of oil displacement at 57 and 200 °C, respectively. As
9
shown in Table 6, after water flooding in the first experimental phase, the displacement efficiency of sand pack
10
A1 and B1 are 27.74 and 60.02%, respectively. The oil displacement efficiency of sand pack B1 is 32.28%
11
bigger than that of A1. However, the injected PV for sand pack A1 and B1 are 0.554 and 6.255, respectively. It
12
indicates that most of water was injected into the high permeable sand pack B1.
13
From Table 7, after the first phase of water flooding, the oil displacement efficiency of sand pack B2 is
14
58.53% than that of sand pack A2. Moreover, injected PV of sand pack A2 and B2 are 0.099 and 11.581,
15
respectively. From Fig. 5, water cut for both sand packs in experiment 1 rise quickly in the early stage of water
16
flooding, while water cut for sand pack A2 in experiment 2 is very low. The reason for this phenomenon is that
17
water breakthrough and channeling seriously decreased the sweep efficiency and most of the water flowed
18
through the higher permeable sand pack (sand pack B1).
19
Table. 6. Results of oil displacement experiment 1 (Temperature: 57 °C).
14
Experimental
Sand
Original oil
Remaining oil
Displacement
Enhanced displacement
Injected
phase
pack
saturation (%)
saturation (%)
efficiency (%)
efficiency (%)
PV
1. Water
A1
71.76
51.85
27.74
/
0.554
B1
66
26.39
60.02
/
6.255
Average
/
39.5
42.71
/
3.464
A1
51.85
39.64
44.76
17.02
0.656
B1
26.39
11.79
82.14
22.12
2.107
Average
/
26.17
62.05
19.34
1.273
A1
39.64
39.12
45.48
0.72
0.19
B1
11.79
7.42
88.76
6.62
6.816
Average
/
23.77
65.52
3.47
5.089
flooding
2. Foam flooding
3. Water flooding
1
Table. 7. Results of oil displacement experiment 2 (Temperature: 200 °C). Original oil
Displacement
Enhanced
efficiency
displacement
(%)
efficiency (%)
55.85
15.63
/
0.099
67.0
17.31
74.16
/
11.581
Average
/
35.29
47.01
/
3.38
A2
55.85
22.34
66.26
50.63
1.327
B2
17.31
15.93
76.22
2.06
1.532
Average
/
16.74
72.24
27.86
1.01
A2
22.34
19.22
70.9
4.76
2.163
B2
15.93
15.93
76.22
0.00
1.852
Average
/
15.09
74.87
2.49
1.35
Experimental
Sand
phase
pack
1.Water
A2
66.2
B2
flooding
2.Foam flooding
3.Water flooding
saturation (%)
Remaining oil saturation (%)
Injected PV
2
In summary, serious inconformity was observed in these experiments. After the first stage of each
3
experiment which conducted water flooding, the oil displacement efficiency shows a large difference. Oil
4
displacement of the sand pack with higher permeability is much bigger than the other one. The main reason for
5
the inconformity in the experiments is mainly caused by the permeability ratio of the sand packs, thus leads to
6
big difference in oil mobility which is defined as follows:
15
ߣ =
1
ఓ
,
(3)
2
Where ko andμo are oil permeability and oil viscosity, respectively.
3
Moreover, with the increase of the temperature of the injected water, the inconformity between the sand
4
packs become more serious. The main reason for this phenomenon is caused by the sharply decreased oil-water
5
viscosity ratio, which leads to larger oil-water mobility ratio. Oil-water mobility ratio is defined at the ratio of
6
oil and water mobility. The equation is expressed as
ߣ = ܯ /ߣ௪ = ቀఓ ቁ / ቀఓೢ ቁ,
7
ೢ
(4)
8
As the initial temperature of all these experiments was 57 °C, the oil-water viscosity ratio was 191.4, while
9
it sharply decreased to 15.76 at temperature of 200 °C. In experiment 2, water was injected into the higher
10
permeable sand pack B2 at first. With the injection of water, temperature of sand pack B2 increased and the oil
11
viscosity decreased sharply. As a result, almost all the injected water was flowed through sand pack B2 and sand
12
pack A2 was rarely displaced.
13
In the second experimental phase, with the conducting of foam flooding, water cut of all the sand packs
14
are sharply decreased (in Fig. 5 (A) and (B)). Oil displacement efficiency of sand pack A1 and B1 in experiment
15
1 are increased to 44.76% and 82.14%, respectively (in Table 6). The average displacement efficiency for
16
experiment 1 and 2 are increased by 19.34 and 27.86%, respectively (in Table 6 and 7).
17
From Table 7, the injected PV of sand pack A2 and B2 in the foam flooding stage is nearly the same, which
18
means solutions was almost evenly injected into these sand packs. In experiment 1, however, more than 76% of
19
the solutions was injected into the higher permeable sand pack B1. The experimental results show that, in the
20
presence of oil, foams haven been generated. The generated foam can block the sand pack with higher
21
permeability and the oil in the lower permeable sand pack is displaced, thus lead to higher sweep efficiency. It
22
mirrors the blocking mechanism in the development of reservoirs with sever heterogeneity. The injection of
23
foam is an effective enhance oil recovery method. In addition, CO2 core flooding experiments were conducted
24
in the previous studies by Shi et al. (2019). The results show that with the injection of CO2, oil displacement 16
efficiency was 52.7 and 74.7%, respectively. The improve of displacement efficiency of the low permeability
2
sand pack is partly caused by CO2 injection. However, the foam generated in experiment 1 is weaker than that
3
generated in experiment 2. The selected surfactant shows a well foamability and stability at the temperature of
4
200 °C. With the application of foam flooding, oil displacement efficiency for both the low and high permeable
5
sand packs are improved. 100
100
90
90
Displacement efficiency, %; Water cut, %
Displacement efficiency, %; Water cut, %
1
80 70 60
(A) 50 40 A-Displacement efficiency
30
A-Water cut B-Displacement efficiency
20
B-Water cut Total-Displacement efficiency
10
80 70 60 (B) 50 40 30
A-Displacement efficiency A-Water cut
20
B-Displacement efficiency B-Water cut
10
Total-Displacement efficiency
Total-Water cut
Total-Water cut
0
0 0
1
2
3
6 7 8
4
5
6
7
8
9
10
11
12
0
1
PV injected
2
3
4
5
6
7
8
PV injected
Fig. 5. Production curve at various temperature. (A) Temperature: 57 °C; (B) Temperature: 200 °C.
4. Conclusions
9
1) Based on a combined analysis of foam volumes, foam half-lives, thermal stabilities, and resistance
10
factors, surfactant #6 demonstrated the best foamability, foam stability, and thermal stability in solution with
11
synthetic brine at a temperature range of 57 -200°C. The addition of 0.04 wt% HPAM as a stabilizer produced a
12
more stable foam appropriate for use at temperatures of 80 °C or less.
13 14
2) In the hot water flooding process, the injected hot water flowed through the high-permeability sand pack and reduced the oil viscosity, which result in an increased degree of water channeling.
15
3) The high-temperature CO2 foam generated under optimum conditions using surfactant #6 effectively
16
blocked the water channeling created during the preceding hot water flooding, and significantly increased the
17
oil displacement efficiencies of both the high- and low-permeability sand packs.
18
4) The results of this study demonstrate that high- temperature CO2 foam flooding can be a promising 17
1
method to enhance oil recovery after hot water flooding.
2
Acknowledgements
3
The authors would like to acknowledge the financial support of the National Natural Science Foundation
4
of China (51774256), the Fundamental Research Funds for the Central Universities of China (2652018239),
5
and the Science and Technology Special Funds of China (2016ZX05016-006 and 2016ZX05012-003).
6
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Highlights
1
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► Mechanisms of water breakthrough in the hot water flooding process was studied.
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► A kind of surfactant with good foamability and stability was screened out to be a good candidate for high
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temperature CO2 foam flooding.
5
► Mechanisms of improving oil recovery and blocking the water channel for high temperature CO2 foam
6
flooding were investigated.
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► High temperature CO2 foam flooding was verified to be a following strategy after hot water flooding.
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