Subscriber access provided by EDINBURGH UNIVERSITY LIBRARY | @ http://www.lib.ed.ac.uk
Fossil Fuels
A Novel Chemical Flooding System Based on Dispersed Particle Gel Coupling In-depth Profile Control and High Efficient Oil Displacement Yifei Liu, Chenwei Zou, Daiyu Zhou, Hui Li, Mingwei Gao, guang zhao, and Caili Dai Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.9b00243 • Publication Date (Web): 13 Mar 2019 Downloaded from http://pubs.acs.org on March 21, 2019
Just Accepted “Just Accepted” manuscripts have been peer-reviewed and accepted for publication. They are posted online prior to technical editing, formatting for publication and author proofing. The American Chemical Society provides “Just Accepted” as a service to the research community to expedite the dissemination of scientific material as soon as possible after acceptance. “Just Accepted” manuscripts appear in full in PDF format accompanied by an HTML abstract. “Just Accepted” manuscripts have been fully peer reviewed, but should not be considered the official version of record. They are citable by the Digital Object Identifier (DOI®). “Just Accepted” is an optional service offered to authors. Therefore, the “Just Accepted” Web site may not include all articles that will be published in the journal. After a manuscript is technically edited and formatted, it will be removed from the “Just Accepted” Web site and published as an ASAP article. Note that technical editing may introduce minor changes to the manuscript text and/or graphics which could affect content, and all legal disclaimers and ethical guidelines that apply to the journal pertain. ACS cannot be held responsible for errors or consequences arising from the use of information contained in these “Just Accepted” manuscripts.
is published by the American Chemical Society. 1155 Sixteenth Street N.W., Washington, DC 20036 Published by American Chemical Society. Copyright © American Chemical Society. However, no copyright claim is made to original U.S. Government works, or works produced by employees of any Commonwealth realm Crown government in the course of their duties.
Page 1 of 32 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 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Energy & Fuels
1
A Novel Chemical Flooding System Based on Dispersed Particle Gel
2
Coupling In-depth Profile Control and High Efficient Oil Displacement
3
Yifei Liua, b, Chenwei Zoua, Daiyu Zhouc, Hui Lid, Mingwei Gaoa, Guang Zhaoa,, Caili Daia,
4
a
5
China), Qingdao, Shandong 266580, People’s Republic of China.
6
b
7
United States
8
c
9
Republic of China.
School of Petroleum Engineering, State Key Laboratory of Heavy Oil, China University of Petroleum (East
Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, Austin, Texas 78712,
Exploration & Development Research Institute, Tarim Oilfield Company, Kuerle, Xinjiang 841000, People’s
10
d
11
Tanggu, Tianjin 300452, People’s Republic of China.
Bohai Oilfield Research Institute, China National Offshore Oil Corporation (CNOOC), Limited, Tianjin Branch,
Guang
Zhao
Email:
[email protected] Tel: +86-532-86981183
Caili
Dai
E-mail:
[email protected] Tel: +86-532-86981829
Fax: +86-532-86981161
ACS Paragon Plus Environment 1
Energy & Fuels 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 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
1
Page 2 of 32
Abstract
2
In order to achieve both in-depth profile control and high efficient oil displacement, a novel
3
heterogeneous combination flooding system (HCFS) composed of dispersed particle gel (DPG) and
4
dodecyl dimethyl sulfo-propyl betaine (DDSB) was proposed and prepared. According to the in-depth
5
profile control property and interfacial tension reduction capacity, the compositions of HCFS were
6
optimized as 20-30 wt.% DPG and 0.4-0.5 wt.% DDSB. The prepared HCFS was with good wettability
7
alteration ability and emulsifying capacity. Results of double-layer heterogeneous core flooding tests
8
showed that the enhanced oil recovery (EOR) result was great in the HCFS flooding stage and the
9
subsequent water flooding stage, which was up to 31%. Moreover, on account of synergistic action of
10
the soft granular profile control agent (DPG) and high efficient oil displacing surfactant (DDSB), the
11
EOR result of HCFS flooding (31.04%) was much better than that of single DPG flooding (21.14%) or
12
DDSB flooding (8.49%). Furthermore, the synergistic EOR mechanism by HCFS treatment was
13
proposed based on microscopic visualization experiment. In the HCFS flooding stage, DPG particles
14
migrate to the depth and block the dominate channels by accumulating in pore throats, meanwhile, the
15
HCFS efficiently strips the residual oil in high permeability channels. During the subsequent water
16
flooding process, the injected water is diverted to low permeability zones with high oil saturation
17
because of the in-depth profile control effect of DPG. What’s more, the surfactant diffuses to the high
18
oil saturation zones with subsequently injected water, which significantly improved the oil displacement
19
efficiency of subsequent water flooding. Therefore, HCFS can greatly improve oil recovery by the
20
synergism of increasing swept volume and enhanced oil displacement efficiency.
21
ACS Paragon Plus Environment 2
Page 3 of 32 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 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
1
Energy & Fuels
1. Introduction
2
Crude oil is the most important energy resource and chemical raw material, its demand has
3
continuously grown in recent decades. Among the oil field development treatments, water flooding is
4
the most commonly used technology because of the low cost and easy operation.1, 2 However, almost
5
all reservoirs are heterogeneous, which means that there are many different permeability layers in the
6
reservoir or dominant channels exist in the same layer. With the increase of water injection period, the
7
injected water is more likely to break through the high permeability layer owing to the difference of
8
flow resistance. Massive oil-bearing areas cannot be swept, especially those with low permeability.
9
Moreover, because of the low oil displacement efficiency of injected water, there are still a great deal
10
of residual oil in the area that has been swept. As a result, there is about 65%~77% crude oil still
11
remaining underground because of the limitation of the sweep volume and oil displacement efficiency.3,
12
4
13
In recent decades, profile control was proposed to improve the swept volume, which has shown clear
14
effect.5 Many profile control methods have been developed to improve the heterogeneity of reservoir,
15
such as polymer flooding, gel treatment, foam injection, etc.6-9 Among them, gel formed by polymers
16
and crosslinking agents has been proved to be a cost-effective method and widely applied for enhanced
17
oil recovery. It can seal high permeability layers and divert the subsequent injected water into low
18
permeability layers with high oil saturation.10 However, the gelation performances of gel systems are
19
easily affected by shearing, adsorption, dilution effect and other physical & chemical factors, leading to
20
an unguaranteed result.11-13
21
In order to overcome the above inherent drawbacks, preformed gel systems prepared in surface ACS Paragon Plus Environment 3
Energy & Fuels 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 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Page 4 of 32
1
facilities have been proposed and investigated.14 Many studies reported that preformed particle gels
2
(PPG) and micron-size polyacrylamide microsphere (MPEM) can effectively adjust reservoir profile
3
and improve oil recovery in heterogeneous reservoirs.15-18 However, PPG particles are restricted to its
4
millimeter size, which are not suitable for reservoirs with permeability lower than several Darcies. And
5
MPEM products have the characteristics of raw material toxicity and complex preparation process.
6
Therefore, an improved preformed gel system, termed as dispersed particle gels (DPG), was developed
7
and applied to profile control.19-22 It has a series of remarkable properties, such as easy preparation,
8
controllable size (from nanometer to millimeter), environmentally friendly, high-temperature and high-
9
salinity resistance, etc.
10
According to published research, DPG can effectively improve the sweep efficiency by means of in-
11
depth migration and plugging of dominant channels. Nevertheless, large amount of oil still remained in
12
the swept arears because of the large adhesion power of crude oil to sands.23 Thus, the ultimate recovery
13
cannot be maximized only by increasing the sweep efficiency through DPG, especially in the
14
hydrophobic reservoirs. In order to achieve the maximum ultimate recovery, surfactant was introduced
15
into the DPG system to improve the oil displacement efficiency.24-26
16
In this paper, a novel heterogeneous combination flooding system (HCFS) composed of DPG and
17
surfactant is proposed and designed. The DPG product is prepared by the high-speed shearing method
18
using a colloid mill.27 In addition, dodecyl dimethyl sulfo-propyl betaine (DDSB) is selected as the
19
surfactant to prepare the HCFS, which is because the surfactant exhibits many advantages, such as low
20
toxicity, high oil-water interfacial activity at low concentrations, resistance to hard water, etc.28, 29 The
21
suitable concentration ranges of DPG and DDSB are optimized by double-layer heterogeneous core ACS Paragon Plus Environment 4
Page 5 of 32 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 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Energy & Fuels
1
flooding tests and interfacial tension tests, respectively. Then the optimal composition of the HCFS is
2
determined by comprehensive considering the in-depth profile control effect and interfacial tension
3
reduction ability. Further, the wettability alteration abilities, emulsifying capacities and EOR properties
4
of different flooding systems (HCFS, DPG, DDSB) are systemically evaluated and compared. What’s
5
more, the visual simulation experiment is conducted to visually investigate the oil displacement and
6
EOR characteristics of HCFS. At last, based on the above studies, the synergetic mechanism for
7
enhanced oil recovery of the HCFS is proposed. The current work provides a new method for enhanced
8
oil recovery by in-depth profile control with high efficient oil displacing, which can be a candidate with
9
great potentials for field application.
10
2. Experimental section
11
2.1 Materials
12
The non-ionic polyacrylamide (PAM) with a relative average molecular of 1.0×107 and hydrolysis
13
degree of 3.0 % was provided by Hengju Chemical Industry Co., Ltd., China. Hexamethylenetetramine
14
(HMTA) and hydroquinone (HQ) provided by Demei Oilfield High-Tech Co., Ltd., China were used as
15
the crosslinking agents to prepare the bulk gel with the PAM. Dodecyl dimethyl sulfo-propyl betaine
16
(DDSB) with effective concentration of 40% supplied by Demei Oilfield High-Tech Co., Ltd., China
17
was used as the surfactant because of its high interfacial activity and good temperature & salt tolerance.
18
The molecular structure of DDSB is shown in Fig. 1.
19 20
Figure 1. Molecular structure of surfactant DDSB. ACS Paragon Plus Environment 5
Energy & Fuels 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 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Page 6 of 32
1
The crude oil and formation brine were collected from Tarim Oilfield (Xinjiang, China). Solids, water
2
and solution gas was removed from the crude oil and impurities were filtered from the water before
3
experiments. The viscosity of degassed crude is 2.23 mPa·s at 90 ℃ and its density is 872 kg/m3. The
4
density of formation brine is 1,140 kg/m3, and the ion components is shown in Table 1.
5
Table 1. Ion content and salinity of the formation brine Ions
Na+ and K+
Ca2+ and Mg2+
CO32-
HCO3-
SO42-
Cl-
Concentration (mg/L)
73439
7992
345
760
298
126454
Total salinity (mg/L) 6
209288
2.2 Methods
7
2.2.1 Preparation of DPG product
8
The DPG products were prepared through the high speed shearing method reported by Dai et al.27 In
9
short, the first step is the preparation of the bulk gel with good salt tolerance and high temperature
10
resistance. Based on previous studies, the bulk gel was composed of 0.6 wt% PAM, 0.3 wt% HTAM
11
and 0.3 wt% HQ.30 Next, the bulk gel and formation brine were put into the colloid mill simultaneously.
12
Then DPG product was obtained after high speed shearing process. The concentration of the DPG
13
product was determined by the mass mixing ratio of bulk gel and formation brine, and the size
14
distribution of DPG particles could be controlled by the shear rate and shear time.
15
2.2.2 Core flooding test
16
Double-layer heterogeneous core, which simulated the heterogeneity of reservoir more realistically
17
than conventional heterogeneous parallel sand packs, was chosen for the core flooding tests.21 The size
18
of the double-layer heterogeneous core was 300 mm (length) × 45 mm (width) × 45 mm (height), as
19
shown in Fig. 2. The pore volume of the double-layer heterogeneous core was about 138.7 mL, whereas
20
the volume of saturated oil was about 116.2 mL, and the oil saturation was about 83.79 %. The high ACS Paragon Plus Environment 6
Page 7 of 32 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 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Energy & Fuels
1
permeability layer was with a permeability of 1.0 μm2 and a porosity of 23.7 % and the low permeability
2
layer was with a permeability of 0.2 μm2 and a porosity of 22.4%.
3 4
Figure 2. Schematic diagram of core flooding test and double-layer heterogeneous core.
5
The schematic of the experimental setup for core flooding tests is shown in Fig. 2. The experiments
6
were conducted according to the following procedures. (1) The cores were dried and weighted after
7
being washed by ultrasonic for about 1 minutes. (2) The cores were saturated with crude oil by the
8
pressurized method in a vacuum condition using a vacuum pressurized saturation device. Then the
9
saturated cores were weighted again and the saturated oil volumes and initial oil saturations were
10
calculated based on the difference of weights. (3) Put a core in core holder, and then keep the core holder
11
in a thermostat for 24 hours. After that, inject formation brine with a constant rate of 1.0 mL/min until
12
the water-cut reached 98%. (4) 0.5 PV (PV represents pore volume of the high permeability layer) of
13
chemical slug was injected into the core with the same pump rate. (5) The core was kept in a thermostat
14
for 5 days, and subsequent water flooding was conducted at a constant rate of 1 mL/min until the water-
15
cut reached 98% again. The whole core flooding experiment process was conducted at 90 °C, and the
16
volume of produced oil, volume of produced water and pressure changes were continuously recorded.
ACS Paragon Plus Environment 7
Energy & Fuels 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 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Page 8 of 32
1
2.2.3 Interfacial tension measurement
2
In this paper, the oil-water interfacial tension was measured at 90 ℃ using a TX-500C spinning drop
3
tensiometer (CNG Corporation, USA). About 0.5 μL crude oil was injected into a standard quartz tube
4
filled with chemical flooding system. When the tube was rotated at a constant high speed, the oil droplet
5
was pulled into a cylindrical shape.31 Because the diameter of the cylindrical oil droplets was related to
6
the interfacial tension, the oil-water interfacial tension was calculated using the following Eq. (1).
7
σ=
5π2 4
∆𝜌
( )f( ) D3
L
3
D
n
(1)
8
In the equation, σ is the oil-water interfacial tension (mN/m), Δρ is the density difference between oil
9
phase and water phase (g/cm3), n is the refractive index of water phase, f (L/D) is the correction factor,
10
L is the length of oil droplet (mm), D is the measured droplet width (mm), f (L/D) = 1 when (L/D) is
11
more than 4.
12
2.2.4 Contact angle measurement
13
The wettability was evaluated by measuring the contact angles formed between an oil drop and a core
14
surface before and after the chemical flooding system treatment. Before the experiment, the core slices
15
were left in deionized (DI) water bath for 12 hours at 90 °C and were dried for 24 hours at 100 °C. Then
16
core slices were saturated with crude oil through the pressurized method in a vacuum condition. The
17
prepared core slice was placed in the sample cell and the bottom surface was leveled, and the chemical
18
flooding system was pour into the sample cell until the core slice was submerged. A certain volume of
19
oil drop was injected under the bottom surface using a syringe with a curved needle, and pictures of oil
20
drop were recorded continuously over the next 24 hours.32, 33 The contact angle between oil, chemical
21
flooding system, and core surface was calculated with a professional built-in software. The schematic ACS Paragon Plus Environment 8
Page 9 of 32 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 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
1
Energy & Fuels
of experimental device is show in Fig. 3, and the experiment process was conducted at 90 °C.
2 3
Figure 3. Schematic diagram of the apparatus used to measure the contact angle.
4
2.2.5 Evaluation of emulsifying capacity
5
The emulsion was prepared by mechanical stirring emulsification. Firstly, 5 mL of chemical flooding
6
system were added to a graduated test tube and 5 mL of crude oil were carefully transferred to the top
7
of that. Then both of them were stirred using Digital Ultra-Turrax homogenizer (IKN Co., Ltd.,
8
Germany) with stirring rate of 5 000 rpm for 10 min at 90°C.32 To investigate the emulsion stability,
9
the separated water ratio, which was the ratio of separated water volume to the original water volume
10
in the emulsion, was calculated continuously at 90 °C. The status of stable emulsion was observed and
11
photographed using a microscope (Leica Co., Ltd., Germany).
12
2.2.6 Microscopic visualization test
13
To investigate the microscopic displacement mechanism of the chemical flooding system, the glass-
14
etched micromodel was used to observe the behavior of flooding system flowed through porous media
15
and the distribution of residual oil. As shown in Fig. 4, the 40 mm (length) × 40 mm (width) glass-
16
etched micromodel has three regions with different permeabilities. In the preparation process, the
17
micromodel was first saturated by formation brine. Then oil was constantly injected into the water-wet ACS Paragon Plus Environment 9
Energy & Fuels 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 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Page 10 of 32
1
micromodel until no more water was displaced out to simulate the initial oil saturation. The micromodel
2
was aged for 5 days. The displacement experimental process is as follows. (1) water flooding until the
3
oil production was negligible. (2) inject the chemical flooding system. (3) subsequent water flooding.
4
During this experiment, the micromodel pictures at different stages were recorded, and the oil
5
saturations of the micromodel pictures for different stages were obtained by grayscale recognition
6
method. The experiment was conducted at 90 °C.
7 8 9 10
Figure 4. Schematic diagram of visual simulation experiment and etched-glass micromodel. 3. Results and discussion 3.1 Basic physical properties of DPG
11
The prepared DPG products were suspension liquids with densities of about 1.0 g/cm3. The viscosities
12
of DPG products were about 5-15 mPa·s depending on the used concentrations. In order to be suitable
13
for formations with different permeabilities, the DPG products could be prepared with different size
14
distributions by adjusting the preparation parameters, such as shear rate and shear time. The effects of
15
shear rate and shear time on average particle size of DPG were studied by preparing the DPG products
16
with different preparation parameters. The results are shown in Fig. 5.
17
ACS Paragon Plus Environment 10
Page 11 of 32 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 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Energy & Fuels
1 2
Figure 5. Effects of preparation parameters on average particle size of DPG products.
3
(a) Effect of shear rate. (b) Effect of shear time.
4
Fig. 5(a) shows the effect of shear rate on the average particle size, and the shear times were fixed to
5
10 minutes. Fig. 5(b) shows the effect of shear time on the average particle size, and the shear rates
6
were fixed to 8,000 rpm. It can be seen that the average particle size decreased from 10.88 μm to 1.42
7
μm as the shear rate increased. In addition, shear time adjusted the average particle size similarly to
8
shear rate, although not as significant as the shear rate. Therefore, the average particle size of DPG
9
products can be controlled by varying the shear rate and shear time of the colloid mill. For example, the
10
size distribution and SEM micrograph of the DPG product prepared with a shear rate of 10,000 rpm for
11
10 min are shown in Fig. 6. It can be seen that the prepared DPG products were regular spheres having
12
sizes of about 2.0 μm. In addition, the size distribution of the prepared DPG product shows that the
13
particle size mainly distributed within the range of 1.0-7.0 μm, and the average particle size was 2.3
14
μm, which was in good agreement with the SEM micrograph.
15
ACS Paragon Plus Environment 11
Energy & Fuels 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 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Page 12 of 32
1 2
Figure 6. Microstructure characterization and morphology of DPG sample.
3
(a) Size distribution of the DPG particles. (b) SEM micrograph of the DPG particles.
4
According to previous study, the oil recovery is optimal when the DPG particle size matches well
5
with the reservoir permeability. The matching relationship between DPG and reservoir permeability is
6
represented by the matching factor (ψ), which is shown in Eq. (2). Based on series of physical simulation
7
experiments, the matching factor (ψ) is optimized from 0.21 to 0.29.21, 35
9 10
72𝑘 ―0.5
( )
8
𝛹=𝑑
𝜙
(2)
In the equation, d is the average particle size of DPG (μm), k is the absolute permeability (μm2), ϕ is the porosity.
11
In this study, the permeability and porosity of high permeability layer in the target reservoir are about
12
1.0 μm2 and 23.7%, respectively. According to the above discussion, the optimal average DPG particle
13
size range calculated by Eq. (2) is from 3.7 μm to 5.1 μm. Thus, the DPG product with an average
14
particle size of about 4.0 μm, which was prepared by shearing 10 minutes with 6000 rpm, was selected
15
and used in the following experiments of this study.
ACS Paragon Plus Environment 12
Page 13 of 32 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 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
1
Energy & Fuels
3.2 The design of heterogeneous combination flooding system (HCFS)
2
3.2.1 The optimization of DPG concentration
3
The migration depth and plugging capacity of DPG particles in high permeability layer of reservoir
4
are key factors influencing the improved sweep efficiency of subsequently water flooding, which
5
determines the ultimate oil recovery after treatment. Moreover, the concentration of DPG directly
6
determines the migration and plugging capacity when the DPG particle size is fixed. Thus, core flooding
7
tests were carried out to evaluate the injection capability, plugging capacity and enhanced oil recovery
8
property of DPG for concentration optimization. 0.5 PV of DPG with concentrations of 10 wt.%, 20
9
wt.%, 30 wt.%, 40 wt.%, 50 wt.% was injected into double-layer heterogeneous core after initial water
10
flooding, respectively. After being maintained for 5 days at 90 ℃, the double-layer heterogeneous core
11
was displaced by subsequently injected water until the water-cut reached 98% again. Fig. 7(a) shows
12
the changes of the injection pressure (ΔP) with respect to injection volume, and the histogram in Fig.
13
7(b) shows the oil recovery results of the cores treated with different DPG concentrations.
14 15
Figure 7. Pressure and recovery characteristics of cores treated with different DPG concentrations. (a)
16
Variation of injection pressure with injection volume for different DPG concentrations. (b) Enhanced
17
oil recoveries at different stages of the cores treated with different DPG concentrations. ACS Paragon Plus Environment 13
Energy & Fuels 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 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Page 14 of 32
1
(1) When the DPG concentration was high (≥ 40 wt.%), the injection pressure rose obviously during
2
the DPG injection stage. What’s more, during the subsequent water flooding process, the injection
3
pressure showed a sharper growth and a higher peak. However, the pressure decreased rapidly after it
4
reached the peak. The above results indicated that DPG with higher concentration strongly blocked the
5
front of core, which leaded to the sharper growth and higher peak of pressure during the subsequent
6
water flooding stage. However, DPG with higher concentration showed poor injection and migration
7
capacity, which resulted in short effective plugging distance in the porous media. The short effective
8
plugging distance made the water diverted to low permeability layer flow back to high permeability
9
layer prematurely, which was the reason for the rapid decrease of pressure during the subsequent water
10
flooding.
11
Further analysis of enhanced oil recovery results from Fig. 7(b). During the stage of DPG injection
12
and subsequent water flooding, the increment of oil recovery was significantly lower when the DPG
13
concentration was high (40 wt.% and 50 wt.%). Because only the front of high permeability layer was
14
effectively blocked, subsequently injected water wouldn’t be able to widely sweep the low-permeability
15
layer with rich remaining oil but flowed back to the high permeability layer that had been swept
16
previously by initial injected water.
17
All above results and analysis proved that the DPG product with a high concentration was more likely
18
to accumulate in the front of porous media, which resulted in a limited effective plugging distance.
19
Because of the backflow of subsequently injected water into the high permeability layer, the improving
20
sweep efficiency and enhanced oil recovery results were worse.
21
(2) When the injected DPG was with a medium concentration (20 wt.% or 30 wt.%), the injection ACS Paragon Plus Environment 14
Page 15 of 32 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 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Energy & Fuels
1
pressure rose moderately during the DPG injection stage. Moreover, during the subsequent water
2
flooding period, the pressure gradually increased to the peak and maintained a high value for a long
3
time, which showed a “high pressure platform”. The high pressure platform indicated that the DPG
4
particles could migrate to the in-depth region of porous media and made a long distance of effective
5
plugging to the high permeability layer. The effective in-depth plugging to high permeability layer by
6
DPG particles diverted the subsequently injected water to the unswept low permeability layer with high
7
remaining oil saturation. Thus, the enhanced oil recoveries were optimal (above 24 % of recoverable
8
reserves) when the double-layer heterogeneous cores were treated by DPG with a medium concentration
9
(20 wt.% and 30 wt.%), as shown in Fig. 7(b).
10
(3) When the DPG concentration is low (10 wt.%), the pressure increased slower and the pressure
11
peak was significantly lower than the others. Although there was also a “high pressure platform” in the
12
subsequent water flooding stage, the platform period was short and not obvious. This is because the
13
accumulation of DPG particles with low concentration in the pore throats of high permeability layer
14
was unsubstantial and unstable. The plugging effect of DPG to high permeability layer was worse,
15
which resulted in a poor profile control effect during the subsequent water flooding period. Large
16
amount of subsequently injected water still flowed through the high permeability layer that had been
17
swept previously by initial water flooding because of the weak plugging of DPG with low concentration,
18
and the improved sweep efficiency of subsequent water flooding was not good enough. Thus, the
19
enhanced oil recovery was lower when the double-layer heterogeneous core was treated by DPG with
20
a low concentration (10 wt.%), as shown in Fig. 7(b).
21
In conclusion, the medium concentration of injected DPG ensured that the DPG particles could ACS Paragon Plus Environment 15
Energy & Fuels 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 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Page 16 of 32
1
migrate to the in-depth region of high permeability layer and block the dominant channels more
2
effectively, and the enhanced oil recovery was optimal. Based on the above discussion, the
3
concentration of DPG was optimized as 20 %-30 %.
4
3.2.2 The optimization of surfactant concentration
5
The concentration of DDSB surfactant determines the oil displacement performance of HCFS. Thus,
6
the concentration of DDSB was optimized by measuring the interfacial tensions (IFT) between HCFS
7
and crude oil. In these experiments, the HCFS was prepared with different concentrations of DDSB and
8
DPG. The IFT results are shown in Fig. 8. With increase of DDSB concentration from 0.05 wt.% to
9
0.50 wt.%, the IFT curves began to decrease significantly and then gradually became stable, which were
10
similar to L-curves. This result was because of the dynamic adsorption and adsorption equilibrium of
11
surfactant molecules on the oil-water interface.36 It was noteworthy that the IFT values increased with
12
the addition of DPG. Compared with the flooding system prepared with a lower DPG concentration, the
13
flooding system needed to be prepared with a higher DDSB concentration for reaching the same IFT
14
value. This might be due to the adsorption of surfactant molecules on the DPG particles. In addition,
15
DPG particles might occupy the adsorption positions and reduce the adsorption density of surfactant
16
molecules on the oil-water interface, which resulted in higher IFT values. Although DPG particles had
17
a negative effect on the IFT reduction capacity of the HCFS, the IFT could still be reduced to the value
18
lower than 0.1 mN/m when the concentration of DDSB was higher than 0.4 wt.%. And the flooding
19
system reducing the IFT to the values lower than 0.1 mN/m can significantly improve oil displacement
20
efficiency.34
ACS Paragon Plus Environment 16
Page 17 of 32 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 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Energy & Fuels
1 2
Figure 8. Interfacial tensions between different flooding systems and crude oil
3
In view of all the above conclusions, the HCFS should include 20-30 wt.% DPG and 0.4-0.5 wt.%
4
DDSB. The designed HCFS can not only maximize the sweep efficiency but also greatly improve the
5
oil displacement efficiency.
6
3.3 The performances of heterogeneous combination flooding system
7
In order to investigate the comprehensive performances of the designed HCFS, studies on wettability
8
alteration ability, emulsifying capacity and enhanced oil recovery property were carried out.
9
Furthermore, the synergistic mechanisms of HCFS for enhancing oil recovery was proposed by
10
analyzing the results of macroscopic double-layer core flooding experiments and micromodel
11
displacement experiments.
12
3.3.1 Wettability alteration ability
13
Oil-wet surface of reservoir rock is an adverse effect leading to low oil recovery. Oil attached to the
14
oil-wet surface is difficult to be stripped and displaced by conventional water flooding. Thus, an
15
excellent flooding system should be able to obviously turn the oil-wet surface into a water-wet surface,
16
which is beneficial to the peeling of crude oil from the rock surface during subsequent water flooding ACS Paragon Plus Environment 17
Energy & Fuels 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 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Page 18 of 32
1
stage. The contact angle measurements can reflect the wettability of rock surface. To study the
2
wettability alteration ability of flooding systems, oil-wet core slices were treated in 0.4 wt.% DDSB
3
surfactant solution, 20 wt.% DPG product and the designed HCFS (composed of 20 wt.% DPG and 0.4
4
wt.% DDSB), respectively. As shown in Fig. 9(a), rock surfaces without flooding system treatment
5
show strong hydrophobicity and contact angle is 20.7°. This is because the active molecules derived
6
from saturated crude oil were adsorbed on the natural sandstone and made its surface be oil-wet. After
7
DDSB surfactant treatment, the contact angle increased to 141.6° and the oil-wet core surface was
8
altered to be water-wet, which has a positive effect on pulling oil drop and increasing oil displacement
9
efficiency. Fig. 9(b) demonstrates that the wettability of the oil-wet core surface wouldn’t be reversed
10
when the core slice was treated only by DPG. Whereas, the contact angle changed from 22.9° to 135.1°
11
after the core slice was treated by the HCFS, and the wettability of core surface changed from oil-wet
12
to water-wet, as shown in Fig. 9(c). This was because the surfactant molecules in the DDSB solution
13
and HCFS adsorbed on the rock surface, and exposed the hydrophilic groups. The above results prove
14
that the HCFS has the same remarkable effect on wettability alteration as the DDSB surfactant, which
15
means the HCFS can strip crude oil from rock surface effectively.
16
ACS Paragon Plus Environment 18
Page 19 of 32 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 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Energy & Fuels
1
Figure 9. Comparison of the wettability alteration capacity of (a) DDSB surfactant solution (b) single
2
DPG and (c) heterogeneous combination flooding system.
3
3.3.2 emulsifying capacity
4
Emulsification occurs when the flooding system and crude oil are mixed in the porous media. The
5
formed emulsion can improve the liquidity of residual oil and have an effect of mobility control and
6
profile control, thereby improving the sweeping volume and oil displacement efficiency. To study the
7
emulsifying capacity of HCFS and stability of the formed emulsion, a series of comparative experiments
8
were carried out. The experimental flooding systems were 20 wt.% DPG product, 0.4 wt.% DDSB
9
solution and the designed HCFS (composed of 20 wt.% DPG and 0.4 wt.% DDSB), respectively. In the
10
evaluation tests of emulsifying capacity, the separation water ratios and the microscopic morphologies
11
of emulsions were recorded, as shown in Fig. 10. The curve (a) demonstrated that the emulsion prepared
12
by single DPG product was extremely unstable, and the emulsion was rapidly demulsified into oil phase
13
and water phase. The curves (b)-(c) showed that the emulsifying capacities and stabilities of the
14
emulsions formed by the DDSB and the HCFS were similar. In addition, it can be seen that the water
15
separation rate of the emulsion prepared by the HCFS rose slower than that of the emulsion prepared
16
by the DDSB, though the ultimate separated water ratios of emulsions prepared by the two flooding
17
systems were almost the same. This was because the DPG particles in HCFS strengthened the oil-water
18
interfacial film. Moreover, the viscosity of HCFS also slowed down the convergence of emulsion drops.
19
The above results show that the designed HCFS has excellent emulsifying capacity for enhanced oil
20
recovery.
ACS Paragon Plus Environment 19
Energy & Fuels 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 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Page 20 of 32
1 2
Figure 10. The separated water ratio curves and microphotographs of different emulsion.
3
3.3.3 Enhanced oil recovery performance
4
To investigate the enhanced oil recovery performance of HCFS, comparative experiments of oil
5
displacement were carried out using 0.4 wt.% DDSB, 20 wt.% DPG and the designed HCFS (composed
6
of 20 wt.% DPG and 0.4 wt.% DDSB), respectively. The double-layer heterogeneous core was displaced
7
by water flooding firstly to simulate mature oilfields with high water-cut. Then, 0.5 PV of chemical
8
flooding system was injected and subsequent water flooding was conducted after the core was aged for
9
5 days at 90 ℃. The changes of water-cut and oil recovery were shown in Fig. 11.
ACS Paragon Plus Environment 20
Page 21 of 32 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 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Energy & Fuels
1 2
Figure 11. Comparison of enhanced oil recovery properties of different flooding systems. (a) Schematic
3
illustration after initial water flooding, (b) Schematic illustration of single surfactant flooding, (c)
4
Variation of water-cut and oil recovery with injection volume, (d) Schematic illustration of single DPG
5
flooding, (e) Variation of water-cut and oil recovery with injection volume, (f) Schematic illustration
6
of HPC flooding, (g) Variation of water-cut and oil recovery with injection volume
7
(1) When the double-layer heterogeneous core was only treated by 0.4 wt.% DDSB, the enhanced oil
8
recovery was insignificant (only 8.49%). This was because the injected DDSB solution and the ACS Paragon Plus Environment 21
Energy & Fuels 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 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Page 22 of 32
1
subsequently injected water just flowed through the dominate channel, which had been swept previously
2
by initial water flooding, without extra resistance. As shown in Fig. 11(b) and (c), only the residual oil
3
in dominate channel and small amount of oil near the dominate channel were displaced owing to the
4
reduction of interfacial tension and the wettability alteration.
5
(2) When the double-layer heterogeneous core was treated by 20 wt.% DPG, the increment of oil
6
recovery was higher than that of DDSB flooding, which was 24.14%. As shown in Fig. 11(d) and 11(e),
7
the injected DPG particles could block the dominate channel in high permeability layer, and the
8
subsequently injected water was diverted into areas that hadn’t be swept previously. Large amount of
9
oil in the previously unswept areas was displaced because of the improving sweep efficiency of DPG,
10
which leaded to a better enhanced oil recovery result. However, there was still some oil remaining in
11
the swept areas due to the large adhesion power of crude oil to sands.23 Thus, the ultimate recovery
12
couldn’t be maximized only by increasing the sweep efficiency through DPG.
13
(3) When the double-layer heterogeneous core was treated by the HCFS composed of 20 wt.% DPG
14
and 0.40 wt.% DDSB, the increment of oil recovery was the highest in the three comparative
15
experiments, which was 31.04%. As shown in Fig. 11(f) and 11(g), the HCFS was with dual functions
16
of in-depth profile control and efficient oil displacement. During the chemical injection process, the
17
HCFS was injected into the dominant channel formed by initial water flooding, and the residual oil in
18
dominate channel was displaced because of the active components in the HCFS. What’s more, during
19
the subsequent water flooding process, the injected water was diverted into the previously unswept areas
20
owing to the profile control effect of DPG. Meanwhile, the surfactant molecules in HCFS diffused to
21
the high oil saturation areas with subsequently injected water, and significantly improved the oil ACS Paragon Plus Environment 22
Page 23 of 32 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 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Energy & Fuels
1
displacement efficiency of subsequent water flooding. Thus, the designed HCFS composed of profile
2
control agent (DPG) and high efficient oil displacing surfactant (DDSB) could maximally improve oil
3
recovery by the synergism of increasing swept volume and enhanced oil displacement efficiency.
4
3.3.4 The oil displacement of HCFS in etched-glass micromodel
5
To visually investigate the oil displacement and EOR characteristics of HCFS, the visual simulation
6
experiment was conducted. The glass-etched micromodel has three regions, one high permeability zone
7
exists along the diagonal direction, and low permeability zones are located on sides of the high
8
permeability zone. The permeability ratio between the high and low permeability zone is about 5:1.
9
As shown in Fig. 12, the images of oil-water distribution in the micromodel were photographed by
10
microscope. Fig. 12(a) showed the initial oil saturation in the micromodel. Fig. 12(b) showed that water
11
breakthrough channel appeared after initial water flooding, and few oil in low permeability areas could
12
be displaced, which was consistent with the development status of most water flooding reservoirs with
13
high water cut. Subsequently, the HCFS was injected into the micromodel. During the injection process,
14
the HCFS flowed into the high permeability zone firstly. As the injection proceeded, some of the
15
injected HCFS spread into the low permeability zone owing to the accumulation of DPG particles in
16
pore throats of high permeability zone. The residual oil in the high permeability zone and certain amount
17
of oil in the low permeability zones were displaced, as shown in Fig. 12(c). Fig. 12(d) showed that after
18
subsequent water flooding, most oil in the micromodel was displaced because of the synergism of
19
improving sweep efficiency and high efficient oil displacement.
ACS Paragon Plus Environment 23
Energy & Fuels 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 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Page 24 of 32
1 2
Figure 12. Micromodel pictures at different stage of oil displacement. (a) Original state, (b) Initial
3
water flooding, (c) HCFS injection, (d) Subsequent water flooding
4
To analyze oil recoveries of different zones in the micromodel during different flooding periods, the
5
image processing software was used to extract and calculate the number of black pixels representing
6
the residual oil, and the results are shown in Table 2. It can be seen that after the initial water flooding,
7
about 75% oil in the high permeability zone was displaced, whereas only about 30-40% oil in the low
8
permeability zones was displaced, and the total oil recovery after initial water flooding was about 52%.
9
During the HCFS injection period, the sweep efficiency was improved owing to the plugging effect of
10
DPG particles to pore throats in high permeability zone, meanwhile, the oil in the swept zones was
11
displaced more efficiently because of the activity of DDSB molecules. It can be seen from Table 2 that
12
after the HCFS flooding process, nearly 90% of oil in the high permeability zone was displaced,
13
meanwhile, the oil recovery of low permeability zones increased from 30-40% to 70-80%. During the ACS Paragon Plus Environment 24
Page 25 of 32 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 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Energy & Fuels
1
subsequent water flooding process, the injected water mainly flowed through the low permeability zones
2
because of the profile control effect of HCFS, and the oil recovery of low permeability zones was further
3
improved. On the other hand, by HCFS flooding and subsequent water flooding, the total enhanced oil
4
recovery for the micromodel was 36.42%, whereas the increments of oil recoveries for the high
5
permeability zone and the two low permeability zones were 16.23, 48.93% and 45.99%, respectively.
6
Thus, the enhancement of oil recovery was mainly contributed by the oil displaced form low
7
permeability zones.
8
9
Table 2. The oil recovery in different zones after different flooding processes. stage
Initial water flooding
HCFS flooding
Subsequent water flooding
Increment
High permeability zone
76.32%
88.12%
92.55%
16.23%
low permeability zone (bottom left)
33.41%
75.36%
82.35%
48.93%
low permeability zone (top right)
42.66%
80.70%
88.65%
45.99%
Total
51.57%
81.60%
87.99%
36.42%
3.4 The synergistic mechanism for enhanced oil recovery by the HCFS
10
Based on the above results and discussions of core flooding comparative experiments and visual
11
simulation experiment, the synergistic EOR mechanism by the HCFS treatment is proposed, as shown
12
in Fig. 13. After long-term water flooding in oilfields, the water breakthrough forms in high
13
permeability layer, which results in low sweep efficiency and high remaining oil saturation in unswept
14
low permeability zones. The water flooding become ineffective. The residual oil in dominant channel
15
and the remaining oil in unswept zones can’t be displaced out any more, as shown in Fig. 13(a). During
16
the HCFS flooding process, the residual oil in dominant channel is efficiently displaced owing to the
17
reduction of interfacial tension, the wettability alteration and emulsification, as shown in Fig. 13(b).
18
During the subsequent water flooding process, the water is diverted to the previously unswept low ACS Paragon Plus Environment 25
Energy & Fuels 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 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Page 26 of 32
1
permeability zones with high remaining oil saturation because of the plugging of DPG particles to pore
2
throats of dominant channel. Meanwhile, the surfactant molecules in HCFS diffuse to the high oil
3
saturation areas with subsequently injected water, and significantly improve the oil displacement
4
efficiency of subsequent water flooding. Thus, the residual oil in dominant channel and the remaining
5
oil in unswept zones can be efficiently displaced by HCFS flooding and subsequent water flooding, as
6
shown in Fig. 13(c). The oil recovery is greatly improved by the synergism of increasing swept volume
7
and enhanced oil displacement efficiency.
8 9
Figure 13. Schematic illustration of enhanced oil recovery mechanisms by the HCFS. (a) water
10
breakthrough forms in high permeability layer, (b) HCFS injection, (c) subsequent water flooding
11
4. Conclusions
12
In this paper, a novel heterogeneous combination flooding system (HCFS) composed of dispersed
13
particle gel (DPG) and dodecyl dimethyl sulfo-propyl betaine (DDSB) was proposed and designed. The ACS Paragon Plus Environment 26
Page 27 of 32 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 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Energy & Fuels
1
composition of the HCFS was optimized by comprehensive considering the in-depth profile control
2
effect and interfacial tension reduction ability. The wettability alteration abilities, emulsifying capacities
3
and EOR properties of different flooding systems were systematically evaluated and compared. What’s
4
more, to visually investigate the oil displacement and EOR characteristics of HCFS, the visual
5
simulation experiment was conducted. At last, the synergistic EOR mechanism by the HCFS treatment
6
was proposed based on the above studies. The major conclusions are summarized as follows.
7
The compositions of HCFS were optimized as 20-30 wt.% DPG and 0.4-0.5 wt.% DDSB by
8
comprehensive considering the profile control effect and interfacial tension reduction ability. The
9
prepared HCFS showed good in-depth profile control property and could reduce the oil-water
10 11
interfacial tension value to lower than 0.1 mN/m.
The prepared HCFS showed good wettability alteration ability and emulsifying capacity. The
12
HCFS was with the same remarkable effect on wettability alteration as the DDSB surfactant.
13
Meanwhile, the HCFS showed a better emulsifying capacity than the single DPG or DDSB.
14
The EOR result of HCFS flooding (31.04%) was much better than that of single DPG flooding
15
(21.14%) or DDSB flooding (8.49%) because of the synergistic action of the soft granular profile
16
control agent (DPG) and high efficient oil displacing surfactant (DDSB).
17
The designed HCFS composed of DPG and DDSB can greatly improve oil recovery by the
18
synergism of increasing swept volume and enhanced oil displacement efficiency. On account of
19
synergistic action of DPG and DDSB, the residual oil in dominant channel and the remaining oil
20
in unswept zones will be efficiently displaced by HCFS flooding and subsequent water flooding.
ACS Paragon Plus Environment 27
Energy & Fuels 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 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
1
Page 28 of 32
Acknowledgments
2
The work was supported by the National Key Basic Research Program (No. 2015CB250904), the
3
National Science Fund for Distinguished Young Scholars (51425406), the Chang Jiang Scholars
4
Program (T2014152), and the Climb Taishan Scholar Program in Shandong Province (tspd20161004).
5
The authors express their appreciation to technical reviewers for their constructive comments.
6
References
7
(1) Hermansen, H.; Landa, G. H.; Sylte, J. E.; Thomas, L. K. Experiences after 10 years of waterflooding
8
the Ekofisk Field, Norway. J. Petrol. Sci. Eng. 2000, 26 (1), 11-8.
9
(2) Tang, G. Q.; Morrow, N. R. Salinity, Temperature, Oil Composition, and Oil Recovery by
10
Waterflooding. SPE Reserv. Eng. 1997, 12 (4), 269-76.
11
(3) Liu, Y.; Bai, B.; Wang, Y. Applied Technologies and Prospects of Conformance Control Treatments
12
in China. Oil Gas Sci. Technol. 2010, 65 (6), 859-78.
13
(4) Zhang, Y.; Gao, M.; You, Q.; Fan, H.; Li, W.; Liu, Y.; Fang, J.; Zhao, G.; Jin. Z.; Dai, C. Smart
14
mobility control agent for enhanced oil recovery during CO2 flooding in ultra-low permeability
15
reservoirs. Fuel 2019, 241, 442-450.
16
(5) Sydansk, R. D.; Southwell, G. P. More Than 12 Years’ Experience With a Successful Conformance-
17
Control Polymer Gel Technology. Presented at SPE/AAPG Western Regional Meeting; Long Beach,
18
California, 19-22 June, 2000; SPE Paper 62561.
19
(6) Zhang, C.; Li, Z.; Li, S.; Lv, Q.; Wang, P.; Liu, J.; Liu, J. Enhancing Sodium Bis(2-ethylhexyl)
20
Sulfosuccinate Injectivity for CO2 Foam Formation in Low-Permeability Cores: Dissolving in CO2 with
21
Ethanol. Energy & Fuels 2018, 32 (5), 5846-5856. ACS Paragon Plus Environment 28
Page 29 of 32 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 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Energy & Fuels
1
(7) Wang, D.; Han. P.; Shao. Z.; Hou. W.; Seright. R. S. Sweep-Improvement Options for the Daqing
2
Oil Field. SPE Reserv. Eval. Eng. 2006, 11 (1), 18-26.
3
(8) Frampton, H.; Morgan, J. C.; Cheung, S. K.; Munson, L.; Chang, K. T.; Williams, D. Development
4
of a Novel Waterflood Conformance Control System. Presented at SPE/DOE Symposium on Improved
5
Oil Recovery; Tulsa, Oklahoma, 17-21 April, 2004; SPE Paper 89391.
6
(9) You, Q.; Wen, Q.; Fang, J.; Guo, M.; Zhang, Q.; Dai, C. Experimental study on lateral flooding for
7
enhanced oil recovery in bottom-water reservoir with high water cut. J. Petrol. Sci. Eng. 2019, 174,
8
747-756.
9
(10) Dai, C.; Zhao, G.; You, Q.; Zhao, M. A study on environment‐friendly polymer gel for water
10
shut‐off treatments in low‐temperature reservoirs. J. Appl. Polym. Sci. 2014, 131 (8), 631-44.
11
(11) Yang, H.; Kang, W.; Wu, H.; Yu, Y.; Zhu, Z.; Wang, P.; Zhang, X.; Sarsenbekuly, B. Stability,
12
rheological property and oil-displacement mechanism of a dispersed low-elastic microsphere system
13
for enhanced oil recovery. Rsc. Adv. 2017, 7 (14), 8118-30.
14
(12) Sengupta, B.; Sharma, V. P.; Udayabhanu, G. Gelation studies of an organically cross-linked
15
polyacrylamide water shut-off gel system at different temperatures and pH. J. Petrol. Sci. Eng. 2012,
16
81 (1), 145-50.
17
(13) Moradi, A. A review of thermally stable gels for fluid diversion in petroleum production. J. Petrol.
18
Sci. Eng. 2000, 26 (1), 1-10.
19
(14) Cozic, C.; Rousseau, D.; Tabary, R. Novel Insights Into Microgel Systems for Water Control. SPE
20
Prod. Oper. 2009, 24 (4), 590-601.
21
(15) Elsharafi, M. O.; Bai, B. Influence of strong preformed particle gels on low permeable formations ACS Paragon Plus Environment 29
Energy & Fuels 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 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Page 30 of 32
1
in mature reservoirs. Petrol. Sci. 2016, 13 (1), 77-90.
2
(16) Sang, Q.; Li, Y.; Yu, L.; Li, Z.; Dong, M. Enhanced oil recovery by branched-preformed particle
3
gel injection in parallel-sandpack models. Fuel 2014, 136, 295-306.
4
(17) Yao, C.; Lei, G.; Gao, X.; Li, L. Controllable preparation, rheology, and plugging property of
5
micron‐grade polyacrylamide microspheres as a novel profile control and flooding agent. J. Appl. Polym.
6
Sci. 2013, 130 (2), 1124-30.
7
(18) Yao, C.; Lei, G.; Cathles, L. M.; Steenhuis, T. S. Pore-scale investigation of micron-size
8
polyacrylamide elastic microspheres (MPEMs) transport and retention in saturated porous media.
9
Environ. Sci. Technol. 2014, 48 (9), 5329.
10
(19) Liu, Y.; Dai, C.; Wang, K.; Zhao, M.; Gao, M.; Yang, Z.; Fang, J.; Wu, Y. Investigation on
11
Preparation and Profile Control Mechanisms of the Dispersed Particle Gels (DPG) Formed from Phenol-
12
Formaldehyde Cross-linked Polymer Gel. Ind. Eng. Chem. Res. 2016, 55 (22), 6284-92.
13
(20) Dai, C.; Zou, C.; Liu, Y.; You, Q.; Tong, Y.; Wu, C.; Shan, C. Matching principle and in-depth
14
profile control mechanism between elastic dispersed particle gel and pore throat. Acta. Petrol. Sin. 2018,
15
39 (4), 427-34. (in Chinese)
16
(21) Dai, C.; Liu, Y.; Zou, C.; You, Q.; Yang, S.; Zhao, M.; Gao, M.; Wu, Y.; Sun, Y. Investigation on
17
matching relationship between dispersed particle gel (DPG) and reservoir pore-throats for in-depth
18
profile control. Fuel 2017, 207, 109-20.
19
(22) Zhao, G.; Li, J.; Gu, C.; Li, L.; Sun, Y.; Dai, C. Dispersed Particle Gel-Strengthened
20
Polymer/Surfactant as a Novel Combination Flooding System for Enhanced Oil Recovery. Energy
21
Fuels 2018, 32 (11), 11317-11327. ACS Paragon Plus Environment 30
Page 31 of 32 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 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Energy & Fuels
1
(23) Muhammed, F. A. Study and pilot test on a novel EOR method-coupling PPG conformance control
2
and surfactant flooding. Diss. Missouri University of Science and Technology, 2014.
3
(24) Cao, X.; Guo, L.; Wang, H.; Wei, C.; Liu, Y. The Study and Pilot on Heterogeneous Combination
4
Flooding System for High Recovery Percent of Reservoirs After Polymer Flooding. Presented at 22nd
5
World Petroleum Congress; Istanbul, Turkey, 9-13 July, 2017; WPC-22-0505.
6
(25) Su, Y. C.; Wu, W. X. Research on Characteristics of Combination Flooding System and Oil
7
Displacement Efficiency. Adv. Mater. Res. 2012, 391, 1047-1050.
8
(26) Si, L. V.; Bo, H. C. Well-pattern investigation and selection by surfactant-polymer flooding
9
performance in heterogeneous reservoir consisting of interbedded low-permeability layer. Korean J.
10
Chem. Eng. 2016, 33 (12), 1-9.
11
(27) Dai, C.; Zhao, G.; Zhao, M.; You, Q. Preparation of dispersed particle gel (DPG) through a simple
12
high speed shearing method. Molecules 2012, 17 (12), 14484-9.
13
(28) Li, N.; Zhang, G.; Ge, J.; Luchao, J.; Jianqiang, Z.; Baodong, D.; Pei, H. Adsorption behavior of
14
betaine-type surfactant on quartz sand. Energy & Fuels 2011, 25 (10), 4430-4437.
15
(29) Liu, G.; Gu, D.; Liu, H., Ding, W., Luan, H., Lou, Y. Thermodynamic properties of micellization
16
of Sulfobetaine-type Zwitterionic Gemini Surfactants in aqueous solutions-A free energy perturbation
17
study. Journal of colloid and interface science 2012, 375 (1), 148-153.
18
(30) Liu, Y.; Dai, C.; Wang, K.; Zou, C.; Gao, M.; Fang, Y.; Zhao, M.; Wu, Y.; You, Q. Study on a
19
Novel Cross-Linked Polymer Gel Strengthened with Silica Nanoparticles. Energy Fuels 2017, 31 (9),
20
9152-9161.
21
(31) Pei, H.; Zhang, G.; Ge, J.; Jin, L.; Ding, L. Study on the variation of dynamic interfacial tension in ACS Paragon Plus Environment 31
Energy & Fuels 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 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Page 32 of 32
1
the process of alkaline flooding for heavy oil. Fuel 2013, 104, 372-378.
2
(32) Ge, J.; Wang, Y. Surfactant Enhanced Oil Recovery in a High Temperature and High Salinity
3
Carbonate Reservoir. J. Surfactants Deterg. 2015, 18 (6), 1043-1050.
4
(33) You, Q.; Wang, H.; Zhang, Y.; Liu, Y.; Fang, J.; Dai, C. Experimental study on spontaneous
5
imbibition of recycled fracturing flow-back fluid to enhance oil recovery in low permeability sandstone
6
reservoirs. J. Petrol. Sci. Eng. 2018, 166, 375-380.
7
(34) Rondón-González, M.; Sadtler, V.; Marchal, P.; Choplin, L.; Salager, J. L. Emulsion Catastrophic
8
Inversion from Abnormal to Normal Morphology. 7. Emulsion Evolution Produced by Continuous
9
Stirring To Generate a Very High Internal Phase Ratio Emulsion. Ind. Eng. Chem. Res. 2008, 47 (7),
10
2314-2319.
11
(35) Mauran, S.; Rigaud, L.; Coudevylle, O. Application of the Carman-Kozeny Correlation to a High-
12
Porosity and Anisotropic Consolidated Medium: The Compressed Expanded Natural Graphite.
13
Transport Porous Med. 2001, 43 (2), 355-376.
14
(36) Kamal, M. S.; Hussein, I. A.; Sultan, A. S. Review on Surfactant Flooding: Phase Behavior,
15
Retention, IFT, and Field Applications. Energy Fuels 2017, 31 (8), 7701-7720.
ACS Paragon Plus Environment 32
