Tongchun Hao1, Liguo Zhong1, Jianbin Liu1, Hongyu Sun1, Tianyin Zhu1, Hailong Zhang2, Shaojie Wu2. 1. Unconventional Petroleum Research Institute, China University of Petroleum Beijing, 102249 Beijing City, China. 2. Downhole Operation Branch of Daqing Oilfield Co., LTD, 163458 Daqing, Hei Longjiang Province, China.
Abstract
According to numerous laboratory experiments and field applications, polymer flooding can effectively modify the liquid absorption profile and increase the sweep efficiency, thereby enhancing the oil recovery. However, long-term injection of polymers decreases the effective permeability of the reservoir and plugs the formation pores, resulting in irreversible reservoir damage. In the development process, polymer types and concentrations must be selected according to the reservoir to avoid problems such as plugging of the formation pores. This study was aimed at clarifying the degree of plugging and the injection limit of the reservoir when a salt-resistant polymer (SRP) is used in production processes of the Daqing Oilfield. To this end, oil displacement experiments, dynamic and static adsorption experiments, and SEM observations were performed using representative reservoir fluid and core samples. The static adsorption of "medium-molecular" SRP reached equilibrium after 36 h, and the saturated adsorption capacity was 3.56 mg/g, which was approximately 2-5 times the dynamic adsorption capacity. For medium-molecular SRP, with a molecular mass of 7 million, the lower limit of the core permeability was 20-40 mD. When the permeability was less than 100 mD, the SRP concentration injected into the core could not exceed 900 mg/L. The oil displacement capacity of SRP decreased owing to the macromolecular hydration radius and the strong aggregation effect of SRP. Polymer adsorption and the retention of sand-carrying critically decreased water permeability. This study provides insights into SRP flooding under different geological conditions in the Daqing Oilfield and can help clarify the molecular mass and concentration of polymers with changes in the reservoir conditions.
According to numerous laboratory experiments and field applications, polymer flooding can effectively modify the liquid absorption profile and increase the sweep efficiency, thereby enhancing the oil recovery. However, long-term injection of polymers decreases the effective permeability of the reservoir and plugs the formation pores, resulting in irreversible reservoir damage. In the development process, polymer types and concentrations must be selected according to the reservoir to avoid problems such as plugging of the formation pores. This study was aimed at clarifying the degree of plugging and the injection limit of the reservoir when a salt-resistant polymer (SRP) is used in production processes of the Daqing Oilfield. To this end, oil displacement experiments, dynamic and static adsorption experiments, and SEM observations were performed using representative reservoir fluid and core samples. The static adsorption of "medium-molecular" SRP reached equilibrium after 36 h, and the saturated adsorption capacity was 3.56 mg/g, which was approximately 2-5 times the dynamic adsorption capacity. For medium-molecular SRP, with a molecular mass of 7 million, the lower limit of the core permeability was 20-40 mD. When the permeability was less than 100 mD, the SRP concentration injected into the core could not exceed 900 mg/L. The oil displacement capacity of SRP decreased owing to the macromolecular hydration radius and the strong aggregation effect of SRP. Polymer adsorption and the retention of sand-carrying critically decreased water permeability. This study provides insights into SRP flooding under different geological conditions in the Daqing Oilfield and can help clarify the molecular mass and concentration of polymers with changes in the reservoir conditions.
The
development of oil resources is influenced by a variety of
elements, such as the oil and gas reserves, types of oil and gas,
geological conditions, and development stage.[1] Water can be injected into the formation as an inexpensive and simple
flooding agent to replenish the formation energy and push crude oil
through piston action. However, reservoirs are heterogenous, and high-permeability
reservoirs exhibit low seepage resistance. The high-permeability layer
absorbs more liquid than the medium and low permeability layers under
the same injection pressure. This phenomenon gradually intensifies
with the injection time until the injection of water in the high-permeability
layer is inefficient or even ineffective.[2] The recovery of water flooding depends on the swept volume and oil
displacement efficiency. The oil recovery and oil displacement efficiency
can be increased at a certain swept volume. Consequently, most oil
fields introduce chemical reagents to lower the permeability of the
high-permeability layer and enhance the oil displacement efficiency
to increase the oil recovery.[3] Polymer
flooding, as a representative EOR technique, is extensively employed
in many oilfields, owing to its wide range of material sources, easy
synthetic methods, high oil displacement efficiency, and low cost.[4,5] Following injection, the polymer can selectively seal the high-permeability
zone and lower its permeability. At a constant injection rate, the
injection pressure increases throughout the well, increasing the adsorption
differential pressure and liquid absorption volume in the medium-
and low-permeability zones. This framework is typically appropriate
for reservoirs with high oil saturation and medium heterogeneity.
China conducted field testing of polymer flooding in the oilfields
of Daqing, Dagang,[6] Liaohe,[7] and Shengli[8] and obtained exceptional
stimulation results. However, after the polymer enters the low- and
medium-permeability layers, it remains in those layers, thereby increasing
the permeability resistance.[9] The increase
in permeability resistance is substantially greater than that of the
high-permeability layer for the same injection volume. The injection
pressure increases with the amount of adsorbed polymer in the reservoir.[10−12] To prevent polymer loss owing to reservoir fractures, the injection
pressure must be lower than the fracturing pressure. Consequently,
in the case of continuous polymer injection, once the injection pressure
exceeds the top limit, the adsorption pressure difference in each
layer at the injection end progressively decreases, and the injectivity
of the polymer injection well gradually diminishes and even approaches
zero. For example, in the case of the Daqing Oilfield, the reservoir
permeability is usually less than 200 mD. The injection rate of most
polymer injection wells was lower than the injection allocation rate
for several years and decreased significantly after production (Figure ), increasing the
cost of polymer flooding and decreasing the economic effect of polymer
flooding to enhance oil recovery. Although nanoparticles can be mixed
with polymers to alleviate this problem, large-scale roll-out remains
a distant possibility.[13,14]
Figure 1
Decrease in the injectivity of polymer
injection wells in the Daqing
Oilfield.
Decrease in the injectivity of polymer
injection wells in the Daqing
Oilfield.The decrease in the polymer injectivity
can be primarily attributed
to polymer obstruction in pipelines and formation during polymer flooding.[15−17] The location and mechanism of plugging in the polymer flooding process
have been examined to increase the polymer flooding efficiency and
design a polymer flooding reservoir plugging system. Clogging may
occur in the polymer flooding process owing to several reasons. “Fisheye”
scaling may occur near the well area of the polymer injection well
because of the low solubility of the dry polymer powder or deviation
in the construction means.[18−20] Adsorption and trapping of injected
polymers in the reservoir, particularly at tiny pore openings, can
limit the reservoir permeability.[21−24] The water used to manufacture
the polymer may be incompatible with formation water, resulting in
inorganic scaling. Moreover, the polymer may be stranded in the oil
layer winding, generating large obstruction and limiting the progress
of polymer flooding. SRB bacteria in water can proliferate using polymers
as an energy source, resulting in bacterial obstruction and inorganic
scale blockage if the injected water quality is not adequately high.[25−27] The existing studies mainly focused on theoretically analyzing the
mechanism of plugging formation. However, the compatibility of polymer
and reservoir conditions is a key factor influencing the occurrence
of plugging in the polymer flooding process in oil fields.[28−30] Consequently, it is crucial to investigate the injectivity of the
polymer utilized in each oil field under the appropriate reservoir
geological circumstances and polymer compatibility with the formation
conditions and degree of plugging.[31]This study was aimed at clarifying the degree of reservoir plugging
and the injection limit for the case in which a salt-resistant polymer
(SRP) is used in the Daqing Oilfield. To this end, the injection ability
of SRPs with different molecular weights and concentrations for different
types of cores and permeability conditions was simulated by displacement
experiments. The main factors influencing the adsorption capacity
of the SRP were determined by measuring the adsorption retention of
polymers in porous media in dynamic and static conditions. The mechanism
of the decrease in the polymer injection ability was analyzed from
the aspects of the polymer molecular size, aggregation state, and
adsorption. This research can provide a basis for the optimal molecular
weight and concentration of polymers for the SRP flooding of reservoirs
in the Daqing Oilfield and theoretical guidance for the study of plugging
systems.
Experimental Materials and Methods
Materials
The
polymer solution used in this study was
a “medium-molecular” SRP with a molecular mass of 700
× 104. The polymer structure is shown in Figure . The polymer is
a product provided by the Daqing Oilfield and has a commercial application
value. Moreover, the high-molecular partially hydrolyzed polyacrylamide
(PHPAM) with a molecular mass of 14 × 104 and ultrahigh-molecular
PHPAM with a molecular mass of 25 × 104 were used.
The sand sample was a natural core sand sample from the Gaotaizi Reservoir
(more than 40 mesh). Crude oil with a viscosity of 6.0 mPa·s
was derived from the Daqing Gaotaizi oilfield. The water samples included
samples of clean injection water and deeply treated sewage from the
Daqing Oilfield. Tables , 2 summarize the water quality analysis results.
The sizes of the artificial and natural cores are 25 × 100 mm
and 25 × 100 mm (70–100 mm), respectively. The reservoir
temperature in the Daqing Oilfield is approximately 45 °C; therefore,
the experimental temperature was set as 45 °C.
Figure 2
Molecular structure of
the salt-resistant polymer.
Table 1
Water Quality Analysis of Clean Water
ions
Ca2+
Mg2+
Cl–
HCO3–
CO32
SO42–
K+ + Na+
total
concentration
(mg/L)
45.69
29.18
124.11
512.5
0
5.76
168.82
886.06
Table 2
Water Quality Analysis of Deeply Treated
Sewage Samples
ions
Ca2+
Mg2+
Cl–
HCO3–
CO32
SO42–
K+ + Na+
total
concentration (mg/L)
20.07
6.08
999.69
2020.37
103.22
6.0
1378.51
4533.91
Molecular structure of
the salt-resistant polymer.
Methods
Preparation
of Polymer Solution
The medium-molecular
SRP solution was sheared with clear water to prepare a 5000 mg/L polymer
mother solution, and the shear duration was measured at a viscosity
retention rate of 60%. The other two polymer solutions were sheared
at the same rate and the same duration. Subsequently, a 75-mesh filter
was used to filter the polymer solution. Finally, the oilfield effluent
was used to dilute the polymer mother solution to the target concentration
of 900 mg/L.
Polymer Flooding Experiment
The
changes in the pressure
of artificial cores with different permeability levels during water
flooding, polymer flooding, and subsequent water flooding were measured
through an indoor core simulation experiment at a polymer solution
concentration of 900 mg/L, and the resistance coefficient and residual
resistance coefficient were calculated. The following steps were adopted:Device connection:
using the appropriate
method, connect the flooding device, pressure detection device, and
generated-liquid collection device; check for air and liquid leakage
at each point; and verify that no leaking point exists.Core vacuuming: after drying, weigh
the core and attach it to the vacuuming apparatus. Initiate the timer
when the vacuum gauge on the vacuum pump decreases to less than 0.098
MPa, and vacuum the core constantly. For an artificial homogenous
long core and a natural core, the vacuuming time must be 8 h and at
least 5 h, respectively.Water saturation: seal the outlet end
of the valve, connect the inlet end of the valve to the acid burette,
slowly inject saturated water into the core, gradually open the outlet
end of the valve, and swiftly close the valve when water flows out.
Track the amount of injected water.Water permeability measurement: vary
the flooding rates, inject the simulated formation water into the
core at a consistent rate, record the stable pressure difference,
and use Darcy’s law to compute the effective core permeability.Crude oil saturation: replace
the core
with simulated oil until the water yield is zero and record the amount
of saturated oil at this point.Water injection: inject water at a
steady rate, shift the core to the desired water production rate,
and record the injection pressure, oil production rate, and liquid
production rate.Polymer
injection: perform a constant
speed injection of 6.0 PV polymer solution. Monitor the injection
pressure, oil production rate, and liquid production rate, and obtain
samples of the generated fluid at regular intervals to determine the
polymer content.Subsequent
water flooding: continue
to infuse 6.0 PV water at a steady pace and record the injection pressure,
oil production rate, and liquid production rate.The resistance coefficient and residual resistance coefficient
are technical indicators that specify the quantity of polymer retained
in a porous medium. These parameters can be mathematically represented
as follows:where FR is the resistance coefficient; FRR is the residual resistance coefficient; ΔP1 is the difference in the water drive pressure;
ΔP2 is the difference in the polymer
flooding
pressure; and ΔP3 is the differential
pressure in the subsequent water flooding.The FR and FRR test flow and experimental
equipment are illustrated in Figure . The experimental
equipment included advection pumps, pressure sensors, core grippers,
hand pumps, and intermediate vessels. Parts other than the advection
pump and the hand pump were maintained at a temperature at 45 °C
in a constant temperature box. The system error of the experiment
included the instrument error of the injection pump, intermediate
vessel, and pressure gauge, and the same set of experimental equipment
was used in the experimental process to minimize the influence of
the system error on the experimental results. The characteristics
of artificial cores used in various core permeability studies are
listed in Table .
Figure 3
Schematic
of core flooding experimental equipment and process.
Table 3
Design Scheme of the Polymer Core
Flooding Experiment
polymer
core
molecular mass (×104)
viscosity (mPa s)
concentration (mg/L)
pore
volume
porosity (%)
permeability (mD)
type
700
52.6
600
8.05
16.4
45.2
artificial
core
10.94
22.3
94.6
11.82
24.1
296
900
6.87
14.0
22.5
7.85
16.0
40.9
9.96
20.3
62.7
11.68
23.8
110.6
12.02
24.5
310.5
11.43
23.3
108.3
natural
core
12.90
26.3
315.2
13.69
27.9
489.6
1200
8.05
16.4
43.5
artificial
core
10.84
22.1
85.2
12.71
25.9
284
1400
24.7
900
6.92
14.1
19.5
7.95
16.2
42.4
10.79
22.0
69.2
11.38
23.2
103.8
2500
36.2
7.16
14.6
24.8
8.10
16.5
45.7
10.40
21.2
65.9
12.12
24.7
114.2
Schematic
of core flooding experimental equipment and process.The system errors of this experiment included instrument
errors
such as those of the injection pumps, intermediate containers, and
pressure gauges. The same set of experimental equipment was used in
the experiment to minimize the influence of system errors on the experimental
results.
Polymer Adsorption Experiment
The
physicochemical interaction
between the polymer and formation rock and fluid is critical in the
effective implementation of polymer flooding and chemical flooding
with the polymer as the principal agent. Static and dynamic adsorption
tests were performed based on the polymer adsorption theory. The adsorption
behavior of the SRP solution on the natural core and dynamic retention
characteristics in porous media were investigated, and the adsorption
process and variables influencing the polymer solution were examined.
Static Adsorption
Experimental Procedure
Certain amounts of
core sand and the
polymer solution were added to a tapered bottle with a plug, and the
overall weight of the conical bottle was recoded.For a certain period, the conical bottle
was placed in an incubator at 45 °C. The conical flask was oscillated
at regular intervals to ensure that the adsorbent was completely immersed
in the solution.The
solution was shaken in the conical
container and poured into the centrifugal tube. The samples were centrifuged
for 30 min at 3000–4000 rpm. Subsequently, using the absorbance
method, the polymer concentration in the clear liquid was measured
three times, and the results were averaged.
Variation in the Adsorption Capacity of the Polymer Solution
with Time
The reservoir temperature (45 °C) in the Gaotaizi
polymer flooding test region was simulated, and the adsorption capacity
at various adsorption durations was determined using a natural core
under a constant liquid–solid ratio. The durations of the trial
were 12, 24, 36, and 48 h.
Static Adsorption of Polymer Solutions at
Different Liquid–Solid
Ratios
The reservoir temperature (45 °C) was simulated
in the Daqing polymer flooding test area, natural cores were used
to assess the static adsorption capacity at various liquid–solid
ratios, and the corresponding liquid–solid ratio was determined
at a steady adsorption capacity. The liquid to solid ratios were 3,
5, 10, 15, and 20 mg/L, with a standing time of 36 h.
Static Adsorption
of Polymer Solutions with Different Concentrations
The static
adsorption capacity of three polymer solutions with
concentrations of 300, 600, 900, 1200, and 1500 mg/L was measured
using natural cores at a temperature of 45 °C.
Dynamic Adsorption
Experimental
Method
The sand-filled tube core with
a diameter of 2.5 cm and length of 10 cm was dried and weighed to
saturate the formation water, and the permeability of the formation
water was measured. The polymer solution was injected at a flow rate
of 1 mL/min, and the produced polymer concentration was measured until
it was equal to that of the injected polymer. The formation water
was injected at a constant rate, and samples were collected from the
core outlet until no polymer was detected in the core-produced fluid.Using the material balance approach, the quantity of the polymer
retained in the formation was estimated using eq .where Q is
the polymer retained in the core, μg/g; ρ0 is
the injected polymer solution concentration, mg/L; V0 is the cumulative volume of the injected polymer solution,
mL; ρ is the polymer concentration
of the ith outflow sample at the core outlet, mg/L; V is the volume of the ith
outflow sample, mL; n is the number of outflow samples
collected at the core outlet; and W is the core dry
mass, g. The error in the polymer dynamic and static adsorption experiment
was mainly the mass measurement error. The electronic balance used
in the experiment was accurate to 10–4 mg, which
satisfied the experimental requirements.The error in the polymer
dynamic and static adsorption experiment
was mainly the mass measurement error. The electronic balance used
in the experiment was accurate to 10–4 mg, which
satisfied the experimental requirements.
Experimental Design
The reservoir temperature (45 °C)
in the Gaotaizi polymer flooding test region was simulated. Natural
cores with permeabilities of 100, 300, and 500 mD were used to perform
flooding tests with the medium-molecular SRP with a polymer solution
concentration of 900 mg/L. The dynamic adsorption capacity was investigated
at various adsorption periods.
Results and Discussion
Polymer
Flooding Experiment
Formation Permeability
Artificial
Core
Flooding experiments were conducted
using artificial cores with different permeabilities, and the polymer
concentration was 900 mg/L. Figure shows the change in the pressure at the injection
end recorded during the experiment. Since the polymer injection, the
pressure at the injection end rapidly increased, and after the injection
of approximately 2 PV of polymer, the pressure increase rate at the
injection end decreased and stabilized. This phenomenon occurred owing
to the high viscosity of the polymer solution, which generated high
resistance when it flowed in the pores. When the polymer solution
first appeared from the outlet end, it occupied the high-permeability
pores in the core. As the polymer solution continuously enters the
low-permeability pores, the pressure at the injection end gradually
increases until the polymer solution occupies all the pores. After
subsequent water flooding was initiated, the pressure at the injection
end rapidly decreased. After 1 PV of water was injected, the pressure
at the injection end gradually decreased and stabilized. However,
the polymer molecules were adsorbed on the surface of the sand particles,
resulting in a higher pressure at the injection end after subsequent
water flooding than that during the previous water flooding.
Figure 4
Injection pressure
curves of different polymers in cores with different
permeabilities.
Injection pressure
curves of different polymers in cores with different
permeabilities.The calculated resistance coefficient
(FR), residual resistance
coefficient (FRR), and decrease in the core permeability for each
group of experiments are presented in Table . The FR of the medium-molecular SRP is larger
than that of the high-molecular PHPAM but smaller than that of the
ultrahigh-molecular PHPAM. Under the same permeability conditions,
the resistance coefficient was not proportional to the molecular weight
of the polymer but proportional to the apparent viscosity in the porous
medium. This phenomenon occurred because during the flow of the polymer,
the stretching effect was dominant, resulting in an increased apparent
viscosity and FR. Table indicates that the FRR of the SRP ranged between 8 and 12, whereas
that of the PHPAM was less than 10. Under the same permeability conditions,
the FRR of the medium-molecular SRP was higher than that of the high-molecular
PHPAM and ultrahigh-molecular PHPAM. In other words, the retention
capacity of the SRP was higher than that of the PHPAM. Experiments
demonstrated that polymer adsorption and retention in the core was
irreversible, thereby decreasing the core permeability. The core permeability
decreased by 92.0% when the 40.9 mD core was displaced by the medium-molecular
SRP solution, and the displacement of the 22.5 mD core led to core
plugging. Therefore, the lower limit of the permeability of the medium-molecular
SRP solution-flooded core was 20–40 mD. In general, when choosing
the SRP, the formation permeability must be determined in accordance
with the polymer solution; otherwise, the formation may be irreversibly
damaged.
Table 4
FR and FRR after Polymer Solution Flooding (Cp = 900 mg/L)
polymer
viscosity (mPa s, 10 s–1)
permeability (×10–3 μm2)
resistance coefficient (FR)
residual resistance
coefficient (FRR)
decrease in the permeability (%)
medium-molecular SRP
52.6
22.5
blocking
blocking
100
40.9
50.1
12.4
92.0
62.7
38.3
11.2
91.4
110.6
24.6
9.8
89.7
310.5
20.5
8.2
87.8
high-molecular PHPAM
24.7
19.5
blocking
blocking
100
42.4
40.1
7.2
86.2
69.2
35.6
5.7
83.2
103.8
22.4
4.9
80.6
ultrahigh-molecular PHPAM
36.2
24.8
blocking
blocking
100
45.7
blocking
blocking
100
65.9
50.3
10.0
90.1
114.2
33.0
7.6
86.7
Natural Core
High-permeability and
medium–low
permeability channels coexist in natural cores, and the degree of
mineral cementation is not uniform, which renders the pore structure
complex. Therefore, core flooding experiments must be performed using
natural cores with different permeability values. Figure shows the variation in the
injection end pressure in the displacement experiment based on natural
cores. The calculated resistance coefficient, residual resistance
coefficient, and decrease in the permeability are presented in Table . No obvious blockage
occurred during the flooding process; however, after subsequent water
flooding, core permeability decreased by more than 90%. The resistance
coefficient and the residual resistance coefficient were two and three
times larger than those of the artificial core with the same level
of permeability, respectively. This finding indicated that the complex
hole roar conditions in the natural core increased the difficulty
of polymer injection, and SRP was more likely to be retained in the
natural core.
Figure 5
Medium-molecular SRP flooding with different permeability
natural
core injection pressures.
Table 5
FR and FRR of Natural Core Displaced by Medium-Molecular
SRP (Cp = 0.9 g/L)
polymer
viscosity (mPa·s, 10 s–1)
permeability (×10–3 μm2)
resistance coefficient (FR)
residual resistance coefficient (FRR)
decrease in the permeability
(%)
medium-molecular
SRP
52.6
108.3
66.8
33.8
97.0
315.2
44.7
22.6
95.5
489.6
26.8
13.2
92.5
Medium-molecular SRP flooding with different permeability
natural
core injection pressures.
Polymer
Concentration
The polymer concentration considerably
influences the perceived viscosity of the polymer. SRP flooding simulation
studies with various quantities of medium-molecular SRP were performed.
The FR, FRR, and decrease in the permeability for core flooding with different
polymer concentrations and permeabilities are shown in Table and Figure . The intermolecular entanglement intensified
as the polymer concentration increased, and the network topology became
more compact. The injection pressure increased during the flooding
process, and a larger amount of polymer remained in the rock. Increasing
the polymer intermolecular force increased the adsorption but did
not lead to obstruction.
Table 6
FR and FRR of the Long Core Displaced by the Medium-Molecular
SRP
permeability level (mD)
polymer concentration
(mg/L)
permeability (×10–3 μm2)
EOR (%)
resistance coefficient (FR)
residual resistance coefficient
(FRR)
decrease
in the permeability (%)
300
600
296
8.80
9.36
4.1
75.60
900
310.5
14.60
20.5
8.2
87.80
1200
284
19.20
31.7
11.6
91.38
100
600
94
6.50
20.8
9.0
88.90
900
110.6
8.80
24.6
9.8
89.70
1200
85.2
10.30
33.1
13.1
92.40
50
600
45
4.30
38.2
12.0
91.69
900
40.9
5.90
50.1
12.4
92.00
1200
43.5
7.50
55.8
15.2
93.42
Figure 6
FR and FRR of polymer flooding of cores with different permeabilities.
FR and FRR of polymer flooding of cores with different permeabilities.The FR and FRR values of the 300
and 100 mD cores were only slightly different,
but those of the 50 mD low-permeability cores were considerably greater
than those of the 100 and 300 mD high-permeability cores. Decreasing
the polymer concentration did not considerably decrease the injection
pressure of polymers in low-permeability formations, although the
polymer viscosity decreased. In addition to the influencing factors,
specifically, the polymer adsorption and high viscosity, the consistency
between the polymer molecular size and the rock pore size (particularly,
the pore throat) considerably influenced polymer molecular retention.In general, decreasing the polymer solution concentration can decrease
the injection pressure of polymer flooding, which influences the microscopic
oil displacement efficiency of polymer flooding. Consequently, to
achieve the highest oil flooding efficiency, a suitable polymer concentration
must be used. The suitable polymer concentration of cores with varying
permeability can be preliminarily calculated using Figure . When the permeability is
less than 100 mD, the SRP concentration injected into the core must
not be greater than 900 mg/L; otherwise, the injectivity would considerably
decrease.
Polymer Adsorption Experiment
Static Adsorption
The
Adsorption Capacity of the Polymer Solution Changes with
Time
The outcome of the static adsorption capacity assessment
of polymers is the maximum adsorption capacity after adsorption equilibrium.
SRP with a concentration of 900 mg/L was utilized to measure the adsorption
capacity measurement at different periods to evaluate the adsorption
equilibrium time of SRP with varying molecular weights. Table and Figure show the experimental outcomes. At the start
of the experiment, the static adsorption capacity of the three polymers
steadily increased. The static adsorption capacity of the three polymers
was steady when the standing time exceeded 36 h; therefore, the adsorption
equilibrium time of the SRP was determined to be 36 h.
Table 7
Polymer Solution Standing for Different
Time Adsorption Capacities
polymer
time (h)
absorbance
concentration loss (mg/L)
adsorption quality (mg)
sand quality (g)
adsorption capacity
(mg/g)
medium-molecular
SRP
12.00
0.37
151.00
6.04
4.00
1.51
24.00
0.35
225.00
9.00
4.00
2.25
36.00
0.35
328.13
13.13
4.00
3.28
48.00
0.34
356.25
14.25
4.00
3.56
high-molecular
PHPAM
12.00
0.48
71.05
2.84
4.00
0.71
24.00
0.45
153.00
6.12
4.00
1.53
36.00
0.40
260.53
10.42
4.00
2.61
48.00
0.39
276.32
11.05
4.00
2.76
ultrahigh-molecular
PHPAM
12.00
0.44
48.57
1.94
4.00
0.49
24.00
0.39
172.00
6.88
4.00
1.72
36.00
0.35
267.14
10.69
4.00
2.67
48.00
0.33
288.00
11.52
4.00
2.88
Figure 7
Temporal variation in
the adsorption capacity of polymers with
different molecular weights and concentration of 900 mg/L.
Temporal variation in
the adsorption capacity of polymers with
different molecular weights and concentration of 900 mg/L.
Static Adsorption of Polymer Solutions at
Different Liquid–Solid
Ratios
Figure presents the static adsorption values of polymer solutions at various
liquid–solid ratios. In the static adsorption experiment, the
polymer adsorption capacity increased with the liquid–solid
ratio. The adsorption capacity of polymers with a low and high liquid–solid
ratios significantly decreased. As the liquid–solid ratio increased,
the static adsorption capacity progressively increased and stabilized.
When a suitable polymer solution was used, the static adsorption capacity
of the sand particles was limited by their surface area.
Figure 8
Polymer adsorption
capacity at different liquid–solid ratios.
Polymer adsorption
capacity at different liquid–solid ratios.
Static Adsorption of Polymer Solutions with Different Concentrations
Table presents
the statistical experimental data of polymer solutions with different
concentrations after standing for 36 h, and Figure shows the isothermal static adsorption curve
of polymer solutions with different concentrations. When the polymer
concentration increased from 300 to 900 mg/L, the static adsorption
capacity of the polymer increased. When the polymer concentration
exceeded 900 mg/L, because of the limitation of the solid–liquid
ratio, the static adsorption amount saturated and did not increase
with the polymer concentration. At different concentrations, the adsorption
capacity of the medium-molecular ASPAM was greater than that of high-molecular
and ultrahigh-molecular PHPAM. This phenomenon occurred because the
molecular chain of medium-molecular ASPAM was shorter than those of
the other two polymers and could thus enter the finer pore roar and
be adsorbed in the pores. The adsorption loss of the polymer could
be decreased by decreasing the polymer solution concentration, and
the injection pressure of the polymer solution could be decreased.
However, the effect of decreasing the concentration on the viscosity
of the polymer entering the reservoir must be considered.
Table 8
Static Adsorption Capacity of Polymer
Solutions with Different Concentrations
polymer
initial concentration (mg/L)
absorbance
concentration
loss (mg/L)
adsorption quality (mg)
sand quality (g)
adsorption capacity (mg/g)
medium-molecular SRP
300.00
0.23
131.25
5.25
4.00
1.31
600.00
0.30
204.17
8.17
4.00
2.04
900.00
0.35
328.13
13.13
4.00
3.28
1200.00
0.43
350.00
14.00
4.00
3.50
1500.00
0.51
357.29
14.29
4.00
3.57
high-molecular PHPAM
300.00
0.22
138.95
5.56
4.00
1.39
600.00
0.34
173.68
6.95
4.00
1.74
900.00
0.45
260.53
10.42
4.00
2.61
1200.00
0.57
295.26
11.81
4.00
2.95
1500.00
0.69
303.95
12.16
4.00
3.04
ultrahigh-molecular PHPAM
300.00
0.19
47.14
1.89
4.00
0.47
600.00
0.29
157.14
6.29
4.00
1.57
900.00
0.39
267.14
10.69
4.00
2.67
1200.00
0.51
298.57
11.94
4.00
2.99
1500.00
0.65
314.29
12.57
4.00
3.14
Figure 9
Static adsorption
capacity of the polymer solution (36 h).
Static adsorption
capacity of the polymer solution (36 h).
Dynamic Adsorption
The dynamic adsorption capacity
test results of the polymer solution are shown in Table . Table shows that the static adsorption capacity
of the medium-molecular SRP is approximately 2–5 times that
of the dynamic adsorption capacity. This phenomenon could be attributed
to the fluid shearing effect in the dynamic adsorption. The chains
are shorter, and the intertwining phenomenon weakens. Consequently,
the adsorption capacity is less than that in the static adsorption.
Sameer Al-Hajri highlighted the large difference in the static and
dynamic adsorption amounts of various polymers in the core.[9] For a given type and concentration of the polymer
solution, lower core permeability corresponds to a smaller pore size
and larger dynamic adsorption capacity. Because the molecular structure
of the polymer does not change, the polymer adsorption capacity on
the surface of the medium does not change, although the spatial structure
formed by its entanglement increases the adsorption layer thickness.
The external force balance is the main factor affecting the dynamic
adsorption capacity. The small size of the pore throat increases the
entanglement force between the SRP molecules in the pores, which leads
to the thickening of the adsorption layer.
Table 9
Dynamic
Adsorption Capacity of Medium-Molecular
SRP (Cp = 900 mg/L)
polymer
permeability
(10–3 μm2)
polymer
concentration (mg/L)
injection polymer volume
(mL)
core quality
(g)
adsorption
capacity
(mg/g)
injection
Production
medium-molecular SRP
107.9
900
462.42
238.2
87.1
1.20
328.6
900
506.25
186.0
73.9
0.99
507.9
900
562.50
166.7
72.7
0.77
The polymer solution retention varies with the rock permeability,
polymer type, concentration, and displacement rate.[32] Manichand and Seright reported that polymer retention values
exceeding 0.2 mg/g may influence the oil displacement rate and economics
of the polymer flooding process.[33] Therefore,
this experiment demonstrated that the use of SRP was not economical.
Analysis of the Mechanism of Decrease in the Polymer Injection–Production
Capacity
Polymer Molecular Size
The degree of matching between
the polymer molecular size and the core pore size is a key factor
influencing the polymer injectivity. According to Flory’s theory
of polymer solutions, the cyclotron radius (or hydraulic radius) of
polymer molecules in the polymer solution can be calculated using
the following formula:[34,35]where [η] is the characteristic
viscosity of the polymer in an aqueous solution, mL/g; M is the molecular mass of the polymer, ×104; and
α is a constant, α = (10/3)πNξ3, which is approximately 4.22 × 1024.The characteristic parameters of several polymers used in the experiment
are listed in Table . The medium-molecular SRP exhibited a large molecular cyclotron
radius of 0.19 μm, and the core permeability decreased when
the thickness of the polymer hydration adsorption layer increased.
For high platform cores with an average permeability of 100 mD, the
permeability decreased by 43.7%. Moreover, the same thickness of the
polymer adsorption layer had different effects on the decrease in
the core permeability with different permeabilities, especially for
low permeability cores (permeability less than 50–100 mD).
Table 10
Characteristic Parameters of the
Experimental Polymer
polymer
molecular mass (×104)
intrinsic
viscosity
(dL/g)
molecular
cyclotron
radius (μm)
decrease
in the permeability
50 mD
100 mD
200 mD
500 mD
medium-molecular SRP
700
40.4
0.19
56.8%
43.7%
32.2%
19.7%
high-molecular
PHPAM
1400
33.6
0.22
59.2%
46.3%
34.3%
21.7%
ultrahigh-molecular PHPAM
2500
48.0
0.31
70.5%
58.3%
45.4%
33.2%
Polymer Aggregation State
At present, polymer solutions
for oil flooding represent subconcentrated solution systems, and their
application concentrations range between those of dilute polymer solutions
and concentrated solutions. The intermolecular interactions of PHPAM
and other common polymers are mainly physical entanglement, while
the intermolecular interactions of the SRP include fan forces, hydrogen
bonds, and intermolecular associations in addition to intramolecular
friction. The SRP solution viscosity is superior to that of ordinary
polymers because of strong intermolecular interactions. Figure shows the SEM
images of the SRP and PHPAM solutions. Figure a,c show the initial sample of 900 mg/L
medium-molecular SRP and high-molecular PHPAM, respectively. The SRP
molecules exhibit considerable aggregation, and the aggregate size
of the polymer groups can reach 5–10 μm, significantly
exceeding the pore radius of the rock. However, normal polymers do
not exhibit significant aggregation, and the polymer molecules are
evenly distributed. Figure b,c show samples of the 900 mg/L medium-molecular SRP and
ordinary polymer after shearing, respectively. After shear action,
the polymer group is destroyed, the order is weakened, and the entanglement
and aggregation of polymer molecules are enhanced. However, the cementation
remains high. In contrast, the polymer molecules become more disordered
after shearing and cannot maintain their basic morphology. Therefore,
the viscosity of the SRP is significantly higher than that of the
PHPAM after high-strength mechanical shearing, which also influences
the seepage characteristics of the solution in porous media.
Figure 10
Effect of
shearing on polymer morphology. (a) Initial sample of
SRP; (b) Sample of SRP after shearing; (c) Initial sample of PHPAM;
(d) Sample of PHPAM after shearing.
Effect of
shearing on polymer morphology. (a) Initial sample of
SRP; (b) Sample of SRP after shearing; (c) Initial sample of PHPAM;
(d) Sample of PHPAM after shearing.
Influence of Polymer Adsorption on the Polymer Injectivity
The polymers are characterized by a high molecular weight and long
chain morphology. These chains contain many polar groups that attach
the rock surface through van der Waals forces and hydrogen bonding
available on the pole.[33] This phenomenon
decreases the number of polymer molecules in the polymer solution,
which decreases the polymer solution concentration and increases the
entropy of the polymer solution. Conversely, the entropy reduction
is due to the loss of polymer freedom upon adsorption on the surface.[9] Essentially, polymers occupy adsorption sites
on the rock surface. Consequently, a larger amount of surface area
is available for polymer molecules, corresponding to a higher level
of adsorption.The adsorption of polymers in the porous media
of hydrophilic rocks can decrease the selectivity of rock permeability.
The decrease in permeability caused by polymer adsorption can be explained
by the “geometric” effect, that is, the decrease in
the pore and throat size caused by the polymer adsorption layer changing
the size of the porous medium (restricting the pore throat). When
the core permeability is lower than 20 mD and the thickness of the
polymer adsorption layer is greater than 0.5 μm, the core is
completely blocked. Because polymer adsorption is irreversible, severe
adsorption can occur.[36,37] If the adsorbed polymer occupies
a large pore volume, it is difficult to recover a substantial amount
of oil. In addition, the formation permeability decreases, resulting
in lower recovery.Figure a shows
the original state of the surface of the natural core, and Figure b shows the surface
state of the natural core after polymer flooding. SRP is a highly
viscous fluid. When SRP passes through the natural core, the polymer
is not only adsorbed on the pore surface of the rock but also connects
the two sides of the pore. Consequently, a polymer molecular network
is formed in the pore, and the pore space is divided into smaller
intervals. Moreover, because of the loose cementation of the core,
the fine sand particles formed after the broken core are carried by
the polymer until they block the middle or outlet end of the core,[38,39] resulting in a significant decrease in the size of the hole roar. Figure schematically
illustrates the adsorption, bridging, and sand-carrying effects of
the polymer blockage.
Figure 11
Physical drawing of the polymer adsorption plug. (a) Original
state
of the surface of the natural core; (b) surface state of the natural
core after polymer flooding.
Figure 12
Schematic
of the polymer adsorption blocking mechanism.
Physical drawing of the polymer adsorption plug. (a) Original
state
of the surface of the natural core; (b) surface state of the natural
core after polymer flooding.Schematic
of the polymer adsorption blocking mechanism.
Conclusions
According to the polymer flooding
experiments, the lower limit of permeability of the cores displaced
by the medium-molecular SRP solution is 20–40 mD. SRP exhibits
higher injectability and adsorption retention than those of the PHPAM.The resistance coefficient
and the
residual resistance coefficient in the natural core flooding experiment
are approximately two and three times those of the artificial core
for a given permeability.For cores with permeabilities greater
than 100 mD, the SRP concentration can be more than 900 mg/L. However,
for cores with low permeabilities of approximately 50 mD, the SRP
concentration must be less than 900 mg/L.According to polymer adsorption experiments,
the static adsorption amounts of the three polymers are steady when
the standing time exceeds 36 h. The liquid–solid ratio is a
key factor that influences the upper limit of the static adsorption
capacity of the SRP. When the SRP concentration is 900 mg/L, the static
adsorption amount (3.56 mg/g) is high and approximately 2–5
times the dynamic adsorption amount.The injection capacity of the SRP
decreases owing to the following reasons: the molecular gyration radius
of the SRP is 0.19 μm, and the permeability can be decreased
by 43.7% for Daqing Oilfield with an average permeability of 100 mD.
Moreover, considerable aggregation occurs, and the size of the aggregated
polymer group can reach 5–10 μm, considerably exceeding
the pore radius of the rock. The SRP exhibits a high shear resistance,
maintains a high bonding strength, and is not easily damaged. Moreover,
the polymer carries fine sand particles, which block the middle or
outlet end of the core, resulting in a significant decrease in the
size of the pore roar.
Figure 1
Figure 2
Figure 3
Figure 4
Figure 5
Figure 6
Figure 7
Figure 8
Figure 9
Figure 10
Figure 11
Figure 12