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Study on the influence of the viscosity reducer solution on percolation capacity of thin oil in ultra-low permeability reservoir

  • Chen Baoyu , Zhang Jicheng ORCID logo EMAIL logo , Ma Wenguo ORCID logo , Wang Yueqi , Liu Xuan and Pan Tianchen
Published/Copyright: November 3, 2025
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Open Chemistry
From the journal Open Chemistry Volume 23 Issue 1

Abstract

It is a new field to improve oil recovery by reducing the viscosity of thin oil in low permeability reservoir, which has a breakthrough significance for the development of low permeability oilfield. But, the oil increase effect of viscosity reducer (VR) solution on thin oil lacks the experimental data and theory support. The viscosity of ground degassed crude oil from the thin oil reservoir is 26.4 mPa s at 72°C. The feasibility of the application of VR solution in thin oil reservoir was analyzed through the experiment and test of viscosity reducing ability, percolation capacity, and displacement effect of VR solution. The oil–water ratio is 5:5, the VR concentration (C VR) of oil–water dispersion (OWD) solution is 0.1%, and the viscosity reduction rate of VR solution reaches 92.4%. The maximum instantaneous injection pressure (P max) of the VR solution injected with the C VR of 0.1% is the lowest, which is 6.60 MPa, the P max decreases by 0.83 MPa than the P max in the basic water flooding experiment, the injection pressure in stable stage (P min) decreases by 0.80 MPa. When the bound water saturation ( s wi ) of core is 41.1%, the VR solution is directly injected before water flooding, from the initial stage of water flooding, the water content ( f w ) at the producing end tends to rise more slowly than that at the producing end of water flooding, the final recovery rate (E R,final) is the highest, 42.5%, the residual oil saturation is only 33.9%. The decrease in P max and the increase in E R,final indicate that the injection of VR solution can improve the percolation capacity of crude oil, and the method of reducing thin oil viscosity can be applied to the development of special permeable thin oil fields.

Keywords: thin oil; ultra-low permeability reservoir; viscosity reducer; percolation capacity; water content; water saturation

Nomenclature

VR

viscosity reducer

OWD

oil–water dispersion solution

SB

simulated brine

TOW

treated oilfield wastewater

C VR

VR concentration of solution, %

K g

gas permeability, ×10−3 μm2

K w

water permeability, ×10−3 μm2

PV

pore volume multiple

Φ

porosity, %

s oi

originality oil saturation bound water saturation, %

s wi

bound water saturation, %

s or

remaining oil saturation, %

P max

maximum instantaneous injection pressure, MPa

P min

injection pressure in stable stage, MPa

f w

water content, %

E R,Water flooding

recovery rate of water flooding stage, %

E R,final

final recovery rate, %

∆E R

increment of the final recovery rate than the recovery rate of water flooding stage, %

1 Introduction

The development of low-permeability oil and gas resources has become the main part of oil and gas resources production, these kinds of resources, about 8.0% of the world and 46.0% of China, are stored in low-permeability oil and gas reservoirs [1]. At the same time, among the new oil and gas resources, low-permeability reservoirs account for 60.0–70.0%, the oil and gas development of low-permeability resources has a great significance to the world energy security [2]. Low permeability reservoir has poor physical properties and complex pore structure. Zhang et al. indicated that the dual-phase flow of oil/water in the low permeability reservoir is non-Darcy flow. The seepage resistance is large during water flooding development, resulting in slow pressure conduction [3,4].

There are many factors that affect oil–water flow ability, including oil–water relative permeability, fluid viscosity, wettability, capillary force, and so on. Based on the experimental and computational observations, Fulcher Jr indicated that the oil relative permeability is a function of the interfacial tension and the viscosity variables individually rather than a function of the capillary number. The brine relative permeability behaved as a function of the capillary number [5]. Nevmerzhitskiy, using integral equation method, studied a one-dimensional isothermal problem of single-phase non-Darcy flow in plane radial flow with constant bottom hole pressure. The analytical solution of the relationship between the threshold pressure gradient and flow rate is established in low permeability reservoir [6]. However, the definite relationship between reservoir parameters of low permeability reservoir and the threshold pressure gradient has not been established, and different low permeability reservoirs need to be tested separately to determine the threshold pressure gradient. Zhao et al. assumed that under the condition of single permeability and water content in the seepage process, the pseudo-starting pressure gradient of each phase of the two-phase low-speed non-Darcy seepage was equal, and established a method for evaluating the oil–water flow ability of the low permeability reservoir including the starting pressure. At the same time, based on the data of oil–water two-phase capillary pressure curve converted from the mercury removal curve of ultra-low permeability rock sample, the capillary pressure in the water content range studied in the flow ability is generally less than 0.1 MPa, which is far lower than the displacement pressure difference in the ultra-low permeability displacement experiment. Therefore, the model used to study ultra-low permeability core displacement can ignore the capillary pressure [7].

The development of low permeability reservoir is limited by the upper limit of injection pressure and the threshold pressure gradient. Fracturing technology can increase the seepage area of low permeability reservoir, increase the suction capacity of low permeability reservoir, and reduce the injection pressure [8]. Reducing the viscosity of injected fluid and reducing the resistance of fluid flow in the reservoir can reduce the pressure gradient of low permeability reservoir and ensure the effective injection and flow of fluid. In low permeability reservoirs, CO2 injection can effectively improve the displacement effect under constant injection pressure. However, due to the influence of structural factors, the effect of CO2 injection in real reservoirs will be reduced compared with that in laboratory simulation experiments [9]. Few researchers studied the effect of surfactant velocity on displacement effect for ultra-low permeability reservoirs of heavy oil with high viscosity, and concluded that in order to achieve a better effect of reducing pressure and increasing injection, it is necessary to appropriately reduce injection velocity [10,11,12]. Reducing the viscosity of crude oil can reduce the seepage resistance and is an effective method to enhance oil recovery. Torabi’s experimental results showed that both water and oil relative permeabilities increase when temperature increases, and the relative permeabilities of both oil and water increase with decrease in oil viscosity [13]. Wang et al. used aquathermolysis technology to achieve in situ upgrading and viscosity reduction of heavy oil under reservoir conditions, enhance the percolation capacity of heavy oil in the reservoir, and improve the development effect of heavy oil reservoirs [14]. On the basis of physical simulation experiment and steam-assisted gravity drainage (SAGD), heavy oil thermal recovery technology, Songyan et al. implemented diethyl ether assisted SAGD technology, which made up for the problem of large steam chamber heat loss, ensured the effective reduction in crude oil viscosity, obtained higher spread efficiency in development, and further improved recovery efficiency [15]. In 2008, Bryan et al. carried out alkaline surfactant flooding for heavy oil with high viscosity. By conducting nuclear magnetic resonance detection on the core of the displacement experiment, they studied the influence of pressure change during emulsion injection and the improvement of oil displacement efficiency [16]. In 2011, Alagic et al. studied the effect of low salinity injection system on oil displacement efficiency, and proved that low salinity is conducive to improving the oil displacement effect of surfactant system [17]. Feng et al. evaluated a biological nano-oil displacement system, it can improve the sweep coefficient and oil displacement efficiency by the viscosity reduction in offshore medium and low-permeability reservoirs [18]. At present, there are no relevant reports about the development results of common crude oil in ultra-low permeability reservoir.

In this study, the temperature stability, the salt stability and the ability of viscosity reducer (VR) solutions to reduce viscosity were studied. The percolation capacity of the oil–water dispersion (OWD) solution after injection of VR was studied. The method of injecting (VR) to reduce the viscosity of thin oil can change the percolation capacity of the fluid, which is of great significance to enhance oil recovery in ultra-low permeability reservoirs.

2 Testing of experimental fluid properties

2.1 Experimental instruments

The experimental instruments used are Brook Field DV-II + Pro type rotary viscometer, the viscosity data of all figures and tables are the average of three test results, the temperature fluctuation range during the test was 0.5°C; thermostat; pressure piston vessel; pressure sensor; ISCO piston pump (model 260D, flow error less than 2.5 × 10−4 mL/min, pressure error less than ±0.5%); vacuum pump; and electronic balance.

2.2 Testing of basic properties of experimental fluids

There are two kinds of water used in the experiment. The simulated brine (TSB) is configured with a salinity of 6054.99 mg/L according to the mineral composition of the formation water, the ionic composition is shown in Table 1. The viscosity of simulated brine is 0.30 mPa s, the quality content of each mineral component in the simulated brine is shown in Table 2. The simulated brine is used for saturated cores and salt resistance experiment of VR solution. Another type of water is the treated oilfield wastewater (TOW) used for percolation capacity experiments and VR solution configuration, the viscosity of TOW is 0.35 mPa s at 72°C (reservoir temperature). The viscosity–temperature relationship between the two kinds of water is shown in Figure 1.

Table 1

Formation water ionic components data

Anion (mg/L) Cation (mg/L) Total salinity (mg/L) pH Water type
HCO 3 − CO 3 2 − Cl− SO 4 2 − K+ + Na+ Mg2+ Ca2+ 6054.99 6.5 CaCl2
183.06 0 3367.75 204.13 215.43 21.27 2063.35
Table 2

Mineral mass content per liter of formation water

Content (mg/L)
MgSO4 Na2SO4 CaCl2 NaHCO3 KCl NaCl Total salinity (mg/L)
106.4 176.1 5525.8 252.1 5.1 20.0 6085.5
Figure 1 Viscosity–temperature relationship curve of TOW and TSB.
Figure 1

Viscosity–temperature relationship curve of TOW and TSB.

The viscosity of degassed crude oil provided by Daqing oilfield was tested by using Brook Field DV-II+Pro rotary viscometer in the laboratory at a temperature range of 50.0–75.0°C, the viscosity at different temperatures is shown in Figure 2. At 72°C (reservoir temperature), the viscosity of ground degassed crude oil is 26.4 mPa s. A simulated oil with a viscosity of 18.0 mPa s configured for kerosene and degassed crude oil was used for laboratory experiments.

Figure 2 Viscosity–temperature relationship curve of degassed crude oil.
Figure 2

Viscosity–temperature relationship curve of degassed crude oil.

2.3 Testing of viscosity–temperature relationship of the VR solutions

The VR is provided by Daqing Oilfield, the VR solutions are configured using the TOW, and the VR concentration of solution (C VR) is 0.3%. The viscosity of VR solution was detected at five temperature points of 35, 45, 55, 65, and 75°C. The test results are shown in Figure 3, indicating that the viscosity of the five VR solutions decreased with the increase in temperature, and the No. 5 solution decreased the most.

Figure 3 Viscosity–temperature relationship curve of the VR solutions (C VR = 0.3%).
Figure 3

Viscosity–temperature relationship curve of the VR solutions (C VR = 0.3%).

2.4 Time stability test of the VR solutions

The TOW and VR were used to configure the VR solutions for the test experiments, and the C VR is 0.3%. The VR solutions were placed at 72.0°C environment, at 0, 1, 3, 7, 30, and 60 days. The viscosity value of the VR solutions were tested with time stability, the results are shown in Figure 4, the viscosity of the VR solutions are stable at the formation temperature.

Figure 4 Viscosity stability experiment results of VR solution under 72°C.
Figure 4

Viscosity stability experiment results of VR solution under 72°C.

2.5 Salt resistance test of VR solutions

Using the TOW to configure the VR solutions for the test experiments, the C VR is 0.3 %. The testing solutions are mixed by the VR solutions and the TSB according to the volume ratio of 1:1 for the salt resistance test of the VR solution. Under the formation temperature of 72.0°C, the viscosity of the testing solutions are tested on days 0, 1, 3, and 7. The results are shown in Figure 5. There is no change in the viscosities of the five VR solutions, and the salt resistance the VR solution is good.

Figure 5 The viscosity of the VR solutions in formation brine environment at 72.0°C.
Figure 5

The viscosity of the VR solutions in formation brine environment at 72.0°C.

3 Detection of viscosity reducing ability

3.1 Experiments of viscosity reducing ability of different VR solutions

At 72°C, at a dispersion rate of 9,000 rpm, the OWD solution with different VRs was configured according to the oil–water ratio of 1:1 using the crude oil of well Chao111-Yang65. The viscosity of ground degassed crude oil is 26.4 mPa s. The VR concentration of OWD solution (C VR) is 0.15%, and the viscosity of the OWD solution was measured. The viscosity reduction rate (f) experiment results are shown in Table 3 and Figure 6.

Table 3

Viscosity reduction rate and viscosity of OWD solution with different VRs

VR no. Oil–water ratio C VR (%) Viscosity (mPa s) f (%)
1 1:1 0.15 7.1 73.1
2 4.1 84.5
3 10.5 60.3
4 12.4 53.0
5 9.8 62.9
Figure 6 Viscosity reduction rate of OWD solution with different VRs.
Figure 6

Viscosity reduction rate of OWD solution with different VRs.

The calculation formula of viscosity reduction rate is

(1) f = μ 0 − μ μ 0 × 100 ,

where f is the viscosity reduction rate, %; μ 0 is the viscosity of crude oil, mPa s; and µ is the viscosity of OWD solution, mPa s.

The reducer ability experiment results of different VR solutions show that the viscosity reduction effect of No. 2 VR is the best one, and the viscosity reduction rate is 84.5%.

3.2 Effect of No. 2 VR concentration on viscosity reduction rate

At 72°C, the OWD solution with the oil–water ratio of 5:5, 7:3, 8:2, and 9:1 was configured using TOW and No. 2 VR solution. The viscosity of ground degassed crude oil is 26.4 mPa s. Under the same oil–water ratio condition, the C VR of OWD solution was changed to 0.05, 0.1, 0.15, 0.2, 0.25, and 0.5%, and the viscosity reduction rate was determined. The viscosity reduction rate experiment results are show in Table 4 and Figure 7.

Table 4

Viscosity of OWD solution with different C VR

C VR (%) Oil–water ratio
5:5 7:3 8:2 9:1
Viscosity (mPa·s) f (%) Viscosity (mPa·s) f (%) Viscosity (mPa·s) f (%) Viscosity (mPa·s) f (%)
0 35.2 −75.7 35.6 −34.9 37.8 −43.2 36.3 −37.5
0.05 3.7 86.0 32.7 −23.9 37.2 −40.9 31.8 −20.5
0.10 2.0 92.4 30.4 −15.2 37.4 −41.7 29.4 −11.4
0.15 4.1 84.5 29.7 −12.5 37.6 −42.4 30.7 −16.3
0.20 4.5 83.0 27.9 −5.7 36.9 −39.8 32.1 −21.6
0.25 4.4 83.3 29.3 −11.0 37.6 −42.4 33.6 −27.3
0.50 8.2 68.9 35.6 −34.9 37.8 −43.2 36.3 −37.5
Figure 7 The Viscosity reduction ratio of OWD solution with different C VR.
Figure 7

The Viscosity reduction ratio of OWD solution with different C VR.

Table 3 and Figure 11 show the experiment results of the influence of the C VR of No. 2 VR on the viscosity reduction rate in different OWD solutions. Among them, the viscosity reduction rate of OWD solution (the oil–water ratio is 5:5, and the C VR is 0.1%) is the highest, which is 92.42%.

3.3 Effect of oil–water ratio on viscosity reduction rate of No. 2 VR

At 72°C, the OWD solution with different oil–water ratios were configured using TOW and No. 2 VR solution, the C VR of OWD solution is 0.1%. The viscosity reduction rate experiment results are shown in Table 5 and Figure 8.

Table 5

Viscosity of OWD solution with different oil–water ratios

Oil–water ratio Viscosity (mPa s) f (%)
9:1 31.8 −20.5
8:2 37.2 −40.9
7:3 32.7 −23.9
6:4 14.7 44.3
5:5 2.0 92.4
Figure 8 The viscosity reduction rate of No. 2 VR with different oil–water ratios.
Figure 8

The viscosity reduction rate of No. 2 VR with different oil–water ratios.

The results of viscosity reduction of the OWD solution with different oil–water ratios show that there is no viscosity reduction when the oil–water ratio is 9:1 to 7:3. When the oil–water ratio decreases from 6:4 to 5:5, the viscosity reduction effect of the OWD solution becomes better with the decrease in the oil–water ratio. Test results show that the more thin oil the viscosity reduction agent contacts, the better the viscosity reduction effect.

4 Natural core percolation capacity experiments

4.1 Experimental procedures and principles

The VR solutions configured using the TOW and the simulated oil (its viscosity is 18.0 mPa s) configured with kerosene and ground degassed crude oil were used for the flow experiments. Measure the length, diameter and dry weight of the natural core to prepare for the calculation of core porosity; vacuum pumping saturated formation water with 12.0 h, the core mass after saturated water is weighed, and the core mass increment after saturation is the saturated water amount, and the core porosity is calculated. Under the confining pressure of 4.0 MPa, the simulated formation water was injected at the rate of 0.3, 0.5, and 0.7 mL/min, and the pressure at the injection end was recorded, and the permeability of the core water was calculated. Under the condition of confining pressure 4.0 MPa (monitoring the pressure at the injection end at any time, keeping the confining pressure higher than the injection pressure 2.0 MPa), the simulated oil viscosity was 18 mPa s, and the constant displacement speed of 0.05 mL/min was used to saturate the oil until no water was produced at all, the injection pressure data were recorded and the oil saturation was calculated. At a temperature of 72°C, experimental research was carried out on the influence of VR solution injection on the fluid percolation capacity in the reservoir, and the injection pressure of water flooding was recorded during the basic water flooding experiment. In the comparison flow experiment, 0.1PV of VR solution was injected before water flooding and then water flooding was carried out. The injection pressure of each stage was detected until the pressure was stable and the experiment was stopped. In the injection capacity comparison experiment, the C VR of OWD solution in each scheme is 0.05, 0.08, 0.10, 0.20, and 0.50%, respectively. According to the criteria for judging whether the terminal effect has an impact in “Test method for Two-phase relative permeability in rock” (GB/T28912-2012) [19], regarding the condition of oil–water two-phase seepage, the injection speed of both the VR solution and the water solution was 0.05 mL/min, the influence of the terminal effect can be ignored.

4.2 Natural core parameters

The natural core of extremely low permeability layer in Yang 1 oil formation was selected to carry out the flow experiment for studying the influences of the VR solutions on the percolation capacity. The natural core parameters are shown in Table 6.

Table 6

Percolation capacity experiment scheme natural core parameters

Core number Length (cm) Diameter (cm) K g (×10−3 μm2) K w (×10−3 μm2) PV (cm3) Φ (%)
949-4 6.51 2.53 2.95 0.54 4.82 14.8
109-10 6.41 2.53 2.90 0.55 4.81 15.0

4.3 Percolation capacity experiment results and discussion

Two natural cores from Yang 1 reservoir, numbered 949-4 and 109-10, respectively, were selected to carry out an injection change ability evaluation experiment. Core parameters are shown in Table 6. Core 949-4 is used to carry out flow experiment of basic water flooding (the concentration of VR solution is 0%). After the experiment, the fluid in the core is cleaned, the porosity and permeability of the core are checked after drying, and then the influence of VR solutions on fluid percolation capacity is carried out. Core 949-4 was used to carry out percolation capacity experiments with VR solution concentrations of 0.0, 0.8, and 2.0%. Core 109-10 was used to carry out percolation capacity experiments with viscosity reducing agent concentrations of 0.5, 1.0, and 5.0%. The results of percolation capacity experiments with different C VR using natural core from Yang 1 reservoir are shown in Table 7 and Figure 9.

Table 7

Experimental data of water flooding injection capacity of Yang 1 natural core

C VR (%) Φ (%) K w (×10−3 μm2) S oi (%) S or (%) P max (MPa) ∆P max (MPa) P min (MPa) ∆P min (MPa)
0 14.7 0.54 58.1 39.0 7.43 0.00 4.90 0.00
0.05 14.9 0.55 58.5 37.6 7.18 0.25 4.68 0.22
0.08 15.0 0.53 57.5 33.9 6.85 0.58 4.26 0.64
0.10 15.1 0.56 58.5 31.4 6.60 0.83 4.10 0.8
0.20 15.0 0.53 59.3 33.7 6.72 0.71 4.24 0.66
0.50 14.9 0.58 59.2 34.1 6.74 0.69 4.25 0.65
Figure 9 The P max and P min of Yang 1 of natural core by injection VR solution with different C VR.
Figure 9

The P max and P min of Yang 1 of natural core by injection VR solution with different C VR.

The injection capacity of basic water flooding (C VR is 0.0%) experimental result shows that the maximum instantaneous injection pressure (P max) reaches the highest value of 7.43 MPa in the process of water flooding. The injection pressure in stable stage (P min) is 4.90 MPa in the later stage of injection. The P max of water flooding after the VR solution injected is lower than the P max of basic water flooding experiment. The P max of the VR solution injected with the C VR of 0.10% is the lowest, which is 6.60 MPa, the P max decreases by 0.83 MPa than the P max in the basic water flooding experiment, the iP min decreases by 0.80 MPa, the fluid percolation capacity in reservoir becomes stronger after the injection of VR solution.

In the percolation capacity experiment of Yang1 natural core, after the injection of VR, with the increase in VR concentration in the injection system, the instantaneous maximum pressure of subsequent fluid seepage and the pressure in the final stability stage both showed a trend of decreasing first and then stabilizing, indicating that the fluid percolation capacity in the core pores was enhanced under the action of VR.

5 Influence of VR solution on oil displacement experiments in different water saturation ( s w )

5.1 Experimental procedures and principles

In order to study the influence of VR solution on the oil displacement effect, the oil displacement experiments were carried out by injecting VR solution under different core water saturation ( s w ) conditions, and the effect was compared with that of water flooding experiment. The best time to inject the VR solution was analyzed. Under the condition of 72°C, the VR solutions configured using the TOW and the simulated oil (its viscosity is 18.0 mPa s) configured with kerosene and crude oil were used for the flow experiments. VR solution concentration is 0.5%. Experimental fluid injection speed is 0.5 mL/min.

The four experimental schemes are as follows: Scheme 1: Artificial core 1 was used to carry out conventional water flooding, and the experiment was ended when the water content ( f w ) at the production end reached 98.0%. Scheme 2: Artificial core 2 is used, 0.2PV VR solution is directly injected before water flooding, and then subsequent water flooding is carried out, the experiment ends when the f w at the producing end reaches 98.0%. Scheme 3: Using artificial core 3, when the f w of water flooding stage at the producing end reaches 50.0%, inject 0.2PV VR solution, and then carry out subsequent water flooding, the experiment ends when the f w of the water flooding to the producing end reaches 98.0%. Scheme 4: Using artificial core 4, inject 0.2PV VR solution when the f w of water flooding stage reaches 90.0% at the producing end, then carry out subsequent water flooding, and end the experiment when the f w water flooding reaches 98.0% at the producing end.

The s w of the artificial core during the experiment can be obtained by the following equation:

(2) s w = s wi + Q w − in − Q w − out PV × 100 ,

where s w is the water saturation of the core, s wi is the bound water saturation, Q w − in is the core cumulative injected water, Q w − out is the core cumulative water production, PV is the core pore volume.

5.2 Artificial core parameters

Four square artificial cores with a length of 80 cm and an end face length of 4.5 cm were selected to carry out the oil displacement experiment. The core parameters and experimental scheme are shown in Table 8.

Table 8

Experiment scheme and natural core parameters

Scheme Core number Width × height × length (cm) K g (×10−3 μm2) K w (×10−3 μm2) Pore volume (cm3) Φ (%) Experimental scheme
1 16B-1 4.5 × 4.5 × 80 9.00 3.74 220.32 13.6 Water flooding
2 21B-3 4.5 × 4.5 × 80 12.10 4.00 237.82 14.7 Water flooding, f w = 0.0% + 0.2PV VR + water flooding
3 16A-3 4.5 × 4.5 × 80 8.90 3.76 225.18 13.9 Water flooding, f w = 50.0% + 0.2PV VR + water flooding
4 15A-3 4.5 × 4.5 × 80 9.20 3.62 231.98 14.3 Water flooding, f w = 90.0% + 0.2PV VR + water flooding

5.3 Influence of s w on VR solutions oil displacement experiment results and discussion

The experimental results of different f w conditions at the production end are shown in Table 8 and Figures 10 and 11. The final recovery rate (E R,final) of basic water flooding in scheme 1 is 26.5%. From scheme 2 to scheme 4, water flooding is carried out first, when the f w at the producing end reaches 0.0, 50.0, and 90.0%, respectively, slug of VR solution is injected, and the injection volume of VR solution is 0.2PV, the E R,final is 42.5, 38.7, and 36.24%, respectively. Compared with the basic water flooding, the E R,final increased by 16.0, 12.2, and 9.7 percentage points, respectively.

Figure 10 Experimental characteristic curve.
Figure 10

Experimental characteristic curve.

The experimental results show that with the same amount of VR solution, the earlier the injection time of VR solution, the higher the E R,final. The best injection timing is when the f w is 0.0%, the E R,final is 42.5%, which increases by 16.0 percentage points compared with water flooding.

It can be seen from Table 9 and Figure 10 that the maximum injection pressure of basic water flooding is 11.42 MPa in Scheme 1. In Scheme 2, the VR solution is directly injected before water flooding. During the flooding process, the maximum injection pressure of the core is the smallest, which is 9.74 MPa. In Schemes 3 and 4, when the f w from water flooding to the production end is 50.0 and 90.0%, respectively, the maximum injection pressure of the core is 10.86 and 11.34 MPa, respectively, which is close to the maximum injection pressure of Scheme 1. This is because the maximum injection pressure occurs in the water flooding stage. When the f w is 50.0 and 90.0%, respectively from water flooding to the production end, the injection pressure has begun to decline gradually when the VR solution is injected into Schemes 3 and 4. At the same time, it can be found from the experimental characteristic curve of the four schemes in Figure 11 that the final stable stage, the final stable values of the injection pressure of Schemes 2–4 are lower than that of scheme 1, indicating that the injection of the VR solution enhances the percolation capacity of the fluid.

Table 9

Influence of s w on VR solutions oil displacement experiment results

Scheme Core number s wi (%) f w (%) S w(fw) (%) s or (%) P max (MPa) E R,Water flooding (%) E R,final (%) ∆E R (%)
1 16B-1 40.7 0.0 40.7 43.5 11.4 26.5 26.5 0
2 21B-3 41.1 0.0 41.1 33.9 9.7 — 42.5 16.0
3 16A-3 41.6 50.0 54.6 35.8 10.9 14.7 38.7 12.1
4 15A-3 39.4 90.0 59.8 38.6 11.3 24.7 36.2 9.7
Figure 11 Curves of recovery degree of different schemes.
Figure 11

Curves of recovery degree of different schemes.

The s wi of Schemes 1– 4 was 40.7, 41.1, 41.67, and 39.4%, respectively. Scheme 1 was water drive scheme, and as the basic comparison scheme, only water drive oil recovery was carried out. In Schemes 2–4, water flooding is carried out first, when the f w at the producing end reaches 0.0, 50.0, and 90.0%, respectively, slug of VR solution is injected, and the injection volume of viscosity reducing system is 0.2PV, after injection of slug of VR solution, the water displacement experiment will continue.

According to formula (2), the s w at the same time can be calculated using the f w at the producing end, and the calculation results are shown in Table 8 and Figure 12. The s w in the core of Schemes 2–4 at the time of injection of VR solution is 41.1, 54.6, and 59.8%, respectively.

Figure 12 Relationship between water content and core water saturation.
Figure 12

Relationship between water content and core water saturation.

In scheme 1, the s wi of basic water flooding is 40.7%. As can be seen in Figure 12, with the increase in s w , the f w at the producing end gradually increases, and the f w at the producing end rises rapidly in the initial stage of water flooding. When the f w at the production end is between 95.0% and 98.0%, the rising trend becomes slow. Combined with the experimental characteristic curve of core 16B-1 in Figure 11, it can be seen that the production end at this stage is in the condition of high f w , the production cycle is long, and the E R,final is still increased. However, due to the rapid rise of f w in Scheme 1, the fluid usage is not good, and the residual oil saturation after water flooding is still 43.5%, indicating the worst oil displacement effect.

In Scheme 2, the s wi of core 21B-3 is 41.1%, and the VR solution is directly injected before water flooding. At this time, the f w at the production end is 0.0%, and the s w in the core is equal to the s wi of 41.1%. As can be seen from Figure 12, from the initial stage of water flooding, the f w at the producing end of core 21B-3 tends to rise more slowly than that at the producing end of water flooding under Scheme 1, indicating that the oil phase percolation capacity becomes better due to the injection of VR solution, which affects the seepage of oil–water fluid and slows down the f w rise at the producing end. Combined with the experimental characteristic curve of core 21B-3 in Figure 10, it can be seen that the f w of core 21B-3 in the production process is mainly below 95.0% at the production end, and the E R,final is the highest, reaching 42.5%. After water flooding, the residual oil saturation is only 33.89%, indicating that the injected VR solution has a good effect on the oil phase percolation capacity.

In Schemes 3 and 4, VR solution is injected when the f w at the producing end reaches 50.0 and 90%, respectively. The change trend of f w at the production end in the two schemes is similar to that in Scheme 1. When the VR solution was injected, the f w of the production end increased slowly. Combined with the experimental characteristic curves of core 16A-3 and core 15A-3 in Figure 10, it can be seen that although the oil phase percolation capacity is enhanced after the injection of VR solution, and the rising trend of f w at the production end is slow, the s w in the core is already high at this time, and the effect of injection of VR solution on changing the fluid flow capacity is poor. However, the water flooding effect of Scheme 3 and 4 is still better than that of Scheme 1.

The research surface shows that the lower the f w at the producing end, that is, the lower the s w of the core, the earlier the effect of the injection of the VR solution on the oil phase percolation capacity, the better the oil increase effect.

6 Conclusion

The method of the VR solution used in the thin oil can change the percolation capacity of fluid in Ultra-low Permeability Reservoir and enhance oil recovery of thin oil in the low permeability reservoir.

With the increase in oil–water ratio, the ability of VR solutions to reduce viscosity decreases. With the increase in VR concentration (C VR) in the solution, the viscosity reducing effect becomes better first, and then becomes worse. The C VR with the best viscosity reducing effect is 0.10%, and the viscosity reduction rate reaches 92.4%.

With the increase in C VR in solution, the decreases of maximum instantaneous injection pressure (P max) and injection pressure in stable stage (P min) first increased and then decreased, while the C VR was 0.10%, they were reduced to 0.83 MPa and 0.80 MPa, respectively, and the oil–water fluid flow capacity was enhanced after injection of VR solution.

The injection of VR solution increased the oil recovery rate (E R,final), and the injection of VR solution before water flooding had the best oil increase effect, reaching 42.5%. In the process of water flooding, the oil increase effect of injecting VR solution will gradually deteriorate with the increase in water cut ( f w ) at the production end.

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Acknowledgments

The authors extend their appreciation to Key Laboratory for Enhanced Oil & Gas Recovery of the Ministry of Education, Northeast Petroleum University.

  1. Funding information: Authors state no funding involved.

  2. Author contributions: Conceptualization, original draft writing, reviewing, and editing: Chen Baoyu, Zhang Jicheng, and Ma Wenguo. Formal analysis, funding acquisition, reviewing, experiments, tests, and editing: Chen Baoyu, Ma Wenguo, Wang Yueqi, Liu Xuan, and Pan Tianchen. Resources, data validation, data curation, and supervision: Chen Baoyu, Zhang Jicheng, and Liu Xuan.

  3. Conflict of interest: The authors declare no potential conflicts of interest concerning the research, authorship, and/or publication of this article.

  4. Ethical approval: The conducted research is not related to either human or animal use.

  5. Data availability statement: Data will be available upon request from the corresponding author.

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Received: 2024-09-25
Revised: 2025-05-16
Accepted: 2025-06-04
Published Online: 2025-11-03

© 2025 the author(s), published by De Gruyter

This work is licensed under the Creative Commons Attribution 4.0 International License.

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https://doi.org/10.1515/chem-2025-0174
Keywords for this article
thin oil; ultra-low permeability reservoir; viscosity reducer; percolation capacity; water content; water saturation
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