Study and Application of Ultrafine Temperature-Resistant and Salt-Tolerant Swellable Particles in Low Permeability Reservoirs

Abstract

Based on the characteristics of low-permeability oil and gas reservoirs and the requirements for profile control and water plugging and for water cut decrease and production increase in the high water cut stage of the middle and late exploitation periods, ultrafine temperature-resistant and salt-tolerant swellable particles DS-1 suitable for low permeability oilfields were prepared by introducing N,N-dimethylacrylamide(DMAA) monomers into the 2-acrylamido-2-methylpropanesulfonic acid (AMPS)/acrylamide(AM)/N,N-dimethylbisacrylamide ternary crosslinking system. The median of initial particle size was 22.00 μm, and is compatible with formation pore throats. A static water absorption experiment showed that the particles can still maintain a high swelling ratio after 15 days at a high temperature and high mineralization degree, so they have long-term stability. The physical and chemical properties of the particles were analyzed microscopically using the infrared spectrum method and the scanning electron microscope (SEM) method. A dynamic displacement experiment confirmed that the particles can effectively plug dominant channels of waterflooding, increase the injection pressure, and improve the interlayer and intralayer heterogeneity. In the field experiment, the swellable particles DS-1 were used as a main slug for water plugging operations, and a good water cut decrease and oil production increase effect was obtained.

1. Introduction

At present, the capacity of constructed low-permeability oil and gas fields accounts for over 70% of the total capacity of constructed oil and gas fields in the world. Owing to such characteristics as low porosity and low permeability, high resistance to flow of crude oil, and lack of formation energy [1,2], such oil and gas reservoirs typically require waterflooding supplemented with production increase measures, including fracturing, and acidization, thereby resulting in serious water channeling and an abrupt increase in water cut in produced fluid in the middle and late periods of oilfield exploitation [3,4]. Therefore, it is of great significance to improve oil recovery by profile control and water plugging in low-permeability reservoirs.

Owing to an excellent swelling property, swelling retarding property, and temperature-resistant and salt-tolerant properties, swellable particles have been widely used in fractured reservoirs or reservoirs with large channels. Lv et al. [5] produced a swellable particles EVA with an initial particle size of 6.8 μm, and the particle swelling ratio reached 27 at 55 °C and 8259.5 mg/L for 7 days. The total recovery was increased from 27.49% to 39.10% by designing a dual-pipe parallel experiment for high- and low-permeability cores, in which the improved recovery value of 13.22% for the low-permeability core was higher than that of 10.24% for the high-permeability core. Li et al. [6] used AMPS and acrylamide-based cross-linkers to synthesize swellable particles, XN-T (adjustable particle size between 0.2~0.8 mm), and improve its retarding swelling capacity by physically coating its surface. At 130 °C and 22 × 10⁴ mg/L, XN-T could still maintain a swelling ratio of 3.60 at 240 h, and the plugging efficiency of the core with a permeability of 78.82 mD was 98.42% in the plugging performance test. Tian et al. [7] constructed a modified α-cyclodextrin polywhene with a double bond structure through a three-step reaction design and cross-linked and co-polymerized it with acrylamide to prepare swellable particles. After 51 h of water swelling, the particle swelling ratio was 8.32. After the external force was revoked by 294.3 N, swellable particles were not broken and could recover to their original state, which had excellent deformation properties. Based on a branched functional monomer, Li et al. [8] prepared hyperbranched swellable particles by inverse suspension polymerization. The initial particle size was about 0.2 mm, and the swelling ratio was about 14.0 at 140 °C and 223,802.8 mg/L for 250 h. In the plugging performance test, the plugging efficiency of the core with a permeability of 4377 mD was 66.7%. With acrylamide and natural latex as the main raw materials, Zhang prepared high-strength swellable particles [9]. The initial particle size was 3 mm. The swelling ratio of particles was 50 at 83.1 °C in distilled water for 240 h. In the plugging performance test, the plugging efficiency of the core with a permeability of 172.3 mD was 98.3%. The pore diameters of low-permeability reservoirs are mainly distributed in the range of 20–400 μm, and the throat diameters are mainly distributed in the range of 2–20 μm. Most of the swellable particles studied so far are mainly used in high- and medium-permeability reservoirs, and their particle sizes are not compatible with the pore sizes of low-permeability reservoir formations, resulting in the particles not being able to enter the formation or play a role in the deep part of the formation. The low-permeability reservoir in Block Q4 of Oilfield Q has a mean permeability of (26–48) × 10⁻³ μm², a mineralization degree of formation water of (20~25) × 10⁴ mg/L, a burial depth of 2000–3500 m, a mean effective thickness of 3–8 m, and a formation temperature of 80–120 °C. The water cut has risen sharply since 2005, and the reservoir has fully entered a high water cut stage at present. The main cause of the increase in water cuts are the serious interlayer diversion and intralayer water channeling from large pores. In order to solve the problem of water channeling in Oilfield Q, we developed ultrafine swellable particles DS-1 suitable for low permeability reservoirs, which has achieved a good effect of water cut decrease and oil production increase effect in the field experiment, providing a new choice of profile control and water shut-off materials for low-permeability reservoirs.

2. Experiment

2.1. Experimental Materials and Equipment

Experimental materials: Swellable particles DS-1, off-white, with a median initial particle size of 22.00 μm; simulated crude oil, formed by diluting the stock tank oil from Oilfield Q with kerosene; simulated formation water, containing Ca²⁺ of 5000 mg/L and Mg²⁺ of 3000 mg/L, with ions being supplemented with NaCl and KCl so that the mineralization degree meets the experimental requirement; 600-mesh and 100-mesh quartz sand; M32.5 masonry cement.

Experimental equipment: Hai’an TZ-3 core drilling machine; Hai’an YBYJIJ-2 hydraulic press.

2.2. Experimental Method

In this paper, the experimental design was carried out according to the China petroleum industry standard SY/T 5799-93 Evaluation methods for profile control agents’ properties.

2.2.1. Particle Suspension Preparation Method

The particle suspension was prepared using the weighing preparation method, which was doneas follows. According to the mass percentage of particles required for the experiment, a given quantity of simulated formation water was added into a beaker, and a given mass of swellable particles were weighed according to the proportion and added into the beaker. Attention was paid to the speed of particle addition, the principle of small quantity and multiple times should be followed, and stirring was conducted until the particles were fully dispersed in the water, thus a particle suspension was obtained.

2.2.2. Experiment Flow for Determination of Swelling Property

• A total of 0.2 g of swellable particles DS-1 was weighed;
• Particle suspensions with mineralization degrees of 1, 5, 10, 15, and 20 × 104 mg/L, respectively, were prepared;
• Twenty (20) mL of suspension was pipetted into a 30 mL ampule by a large pipette;
• The ampule was sealed with an alcohol blast burner and a pair of tweezers, and then placed into a 500 mL aging tank;
• The aging tank was placed into an oven at 50, 80, 120, and 150 °C;
• After 1, 3, 5, 7, 9, 11, 13, and 15 days, the aging tank was taken out and cooled naturally to 50 °C first and then cooled by water;
• The swelling ratio was determined. The aged particle suspension was filtered until no water drop seeped, and then it was weighed. The swelling ratio is as follows:

$$\mathrm{Sw}=\frac{\mathrm{m}1-\mathrm{m}0}{\mathrm{m}0}$$

where Sw is the swelling ratio;

m0 is the mass of particles before water absorption, g;

m1 is the mass of particles after water absorption, g.

2.2.3. Test of Plugging Property

Core preparation: the core concrete with different permeabilities was prepared by controlling the proportion of 600-mesh and 100-mesh quartz sand, cement, and water. When the permeability is 20 mD, the material ratio is 600 mesh quartz sand:100 mesh quartz sand:cement:water at a ratio of 5:2:3:1, and when the permeability is 5 mD, the material ratio is 600 mesh quartz sand:cement:water at a ratio of 7:3:1—the above are all mass ratios. After a steel mold (300 × 45 × 50 mm) was fully filled with one of the above concretes, the mold with concrete was pressed for 15 min at a pressure of 20 MPa by a hydraulic press. The molded concrete was allowed to stand at room temperature, ventilation was maintained, and the surface was watered once every 12 h. After 1 day, the molded concrete was cut with a core drilling machine. All long cores used in the experiment were spliced with small cores of 50 × 25 mm. The parameters of the long cores are shown in

Table 1. Parameters of cores used in the experiment.

No.	Length × Diameter (mm × mm)	Permeability (mD)	Porosity (%)	Pore Volume (cm3)
F1	200 × 25	21.30	25.78	25.30
R1		21.20	23.84	23.39
R2		5.30	15%	14.72

.

The experiment on the plugging property of the core was carried out with the setup shown in Figure 1. The experimental method and process are as follows: (1) The core model was dried, vacuumized, and saturated with formation water. (2) The experimental setup for core flow was assembled according to Figure 1. Heating was conducted until the experimental temperature was reached. Valves A, B, and E were opened to displace oil to establish oil saturation, which was maintained for 24 h. (3) Formation waterflooding was simulated at a constant rate of 0.2 mL/min until the water cut in the core reached 98%. (4) Valve E was closed, Valve A was removed, and 1 PV of particle suspension with a mass fraction of 10% was reversely injected. (5) Valve A was installed, then valve A and B were closed at the specified experimental temperatures after a period of aging, and then Valve A and E were opened and forward waterflooding was allowed. The parameters were recorded.

2.2.4. Test of Oil Displacement Effect of Two Parallel Pipes

The experiment for the enhanced oil recovery was carried out with the setup shown in Figure 1. The experimental method and process are as follows: (1) The core model was dried, vacuumized, and saturated with formation water, respectively. The pore volume in the core was calculated. (2) The permeabilities of high- and low-permeability cores were determined, respectively. Simulated oil was injected into a core at reservoir temperature until no water flowed out, which was maintained for 24 h, and then the oil saturation was calculated. (3) High-permeability and low-permeability cores were placed into the holders as shown in Figure 1. Valves A, B, C, D, and E were opened, and waterflooding was conducted until the water cut in the produced fluid was 98%. We reverse injected 1 PV of 10% swellable particle suspension, then closed all of the valves at both ends of the core holder, and then the core holders were allowed to stand for 5 days. Then, Valves A, B, C, D, and E were opened and waterflooding was conducted at a displacement rate of 0.2 mL/min. During the whole displacement process, the produced fluid was collected once after every 0.1 PV was injected. The oil recovery was calculated.

3. Experimental Results and Discussion

3.1. Synthesis and Characterization of Particles

3.1.1. Synthesis Path

Ultrafine swellable particles DS-1 are gel particles obtained by drying and crushing the polymer produced in the polymerization with monomer N,N-dimethylacrylamide (DMAA) being introduced into the 2-acrylamido-2-methylpropanesulfonic acid (AMPS), acrylamide (AM), and N,N-dimethylbisacrylamide ternary crosslinking system under the action of initiator benzoyl peroxide (BPO). The synthesis path is shown in Figure 2.

3.1.2. Infrared Spectra

The swellable particles DS-1 are a polymer with a three-dimensional structure. The AMPS has a large molecular volume, so its chemical structure is stable and its susceptibility to attack by external cations is poor, causing the polymer to still maintain a large molecular dynamic volume at a high mineralization degree and have excellent temperature-resistant and salt-tolerant properties. The acylamino group in the AA has strong adsorption and hydration properties, causing the particles to have good water absorption and retention capability. The acylamino group—a hydrophilic group—in the DMAA has two methyl groups, which results in uneasy hydrolysis at high temperatures to enhance the temperature resistance of the polymer system. Figure 3 is an infrared spectrogram of the swellable particles, in which two peaks at 3393.22 cm⁻¹ and 3207.53 cm⁻¹ correspond to associated primary amides; furthermore, the peak at 1672.85 cm⁻¹ corresponds to the associated tertiary amide, the peak at 1329.68 cm⁻¹ corresponds to the associated secondary amide, and the peak at 1093.49 cm⁻¹ is caused by the symmetric contraction of sulfonate SO₃⁻.

3.1.3. Scanning Electron Microscope

The temperature-resistant and salt-tolerant properties of the swellable particles originate from the chemical stability of the particles themselves. The microstructure of the swellable particles before and after water absorption was analyzed using the SEM method, and the water absorption and retention capability of the particles was analyzed further. Figure 4A shows SEM images of the particles without water absorption in one position at different magnifications. The particle surface is porous, each pore has a rough inside surface and thick outside surface, and there is good connectivity and thick walls between adjacent pores, indicating that the particles have a strong water absorption capability and can retain the water firmly. Figure 4B shows SEM images of the particles at different magnifications subjected to cooling and drying after 5 days of water saturation at 120 °C and 25 × 10⁴ mg/L. After water absorption, the surface of the swellable particles exhibits a reticular porous structure with dense pores, without accumulation and fracture of reticular structure that occur only after gel failure, indicating that the particles have an extremely strong water retention capability and stability.

3.1.4. Test of Particle Size

As can be discerned from the Figure 5, particles DS-1 with a particle size of less than 22.00 μm account for 50%, and those with a particle size less than 50.69 μm account for 90%. Studies have shown that the initial particle size of swellable particles is less than 1/10 of the pore diameter of the formation [10,11,12], and it has good injection performance. When the ratio of particle size to pore throat diameter is 1.4–1.5, the water plugging effect of the particle profile control is the best [13]. In a low permeability reservoir, the pore diameters are mainly distributed in the range of 20–400 μm, and the throat diameters are mainly distributed in the range of 2–20 μm. Over 80% of the swellable particles have initial particle sizes less than 1/10 of the formation pore diameter, and a ratio of more than 82.28% initial particle size to pore throat diameter is 1.4–1.5, which indicates that particles can be injected and migrate well in low-permeability reservoirs. Driven by the injection pressure, the particles with small particle sizes form 2–4-particle bridging plugging in the deep part of formation through pore throats directly or in a deformed manner, and those with large particle size form 1–2-particle bridging plugging in near-well zones [14]. The particle sizes of the injected particles exhibit a positive rhythm distribution from the injection well to the deep part of formation, and the particles establish strong plugging in the formation after absorbing water to swell.

3.2. Test of Swelling Property

3.2.1. Influence of Temperature on Swelling Property

A 10% particle suspension was prepared with formation water with a mineralization degree of 20 × 10⁴ mg/L and placed in an environment at 50, 80, 120, and 150 °C. The influence of temperature on the swelling property at a high mineralization degree was analyzed by testing the change in swelling ratio with time.

The experimental results are shown in Figure 6. The curves of the swelling ratio of the particles versus time at different temperatures exhibit a trend of descending first and then stabilizing overall. The swelling ratios at 50, 80, 120, and 150 °C start to become stable on day 5 or 11 and have long-term stability. The swelling ratios at different temperatures are stable in the range of 13.2–5.4 on day 15, and the decreases in swelling ratio per unit temperature in the ranges of 50–80 °C, 80–120 °C, and 120–150 °C are 0.037, 0.093, and 0.1, respectively, indicating that, at high temperatures, the particles are even more susceptible to temperature and their swelling property is even more greatly influenced.

3.2.2. Influence of Mineralization Degree on Swelling Property

Ten-percent (10%) particle suspensions were prepared with formation water with mineralization degrees of 1, 5, 10, 15, 20, and 25 × 10⁴ mg/L, respectively, and placed in an environment at 120 °C. The influence of mineralization degree on swelling property at high temperature was analyzed by testing the change in swelling ratio with time.

The experimental results are shown in Figure 7. The curves of the swelling ratio of the particles versus time at different mineralization degrees exhibit a trend of ascending first, then descending and afterwards stabilizing overall. The swelling ratios at mineralization degrees of 1 × 10⁴ mg/L, 5 × 10⁴ mg/L, and 10/15/20 × 10⁴ mg/L start to become stable on day 11, day 7, and day 5, respectively, and relatively long-term stability can be maintained after stabilizing. The swelling ratios at different mineralization degrees are stable in the range of 5.2–8.8 on day 15, and the decreases in swelling ratio per unit of mineralization degree in the ranges of 1–5 × 10⁴ mg/L, 5–10 × 10⁴ mg/L, 10–15 × 10⁴ mg/L, and 15–20 × 10⁴ mg/L are 0.15, 0.16, 0.16, and 0.22, respectively, indicating that, when the mineralization degree is below 15 × 10⁴ mg/L, the particles are poorly susceptible to attack by cations, but when the mineralization degree is above 15 × 10⁴ mg/L, the susceptibility of the particles enhances gradually, and the influence of salinity on the swelling performance of particles was intensified.

3.3. Physical Modeling Experiment of Flow of Swellable Particle Core

3.3.1. Test of Plugging Property

A plugging property experiment was conducted with the experimental setup shown in Figure 1 and artificial spliced core F1, and the plugging property of DS-1 was comprehensively evaluated with the changes in water phase permeabilities (k_w, k_w’) and injection pressure before and after injection of the swellable particles DS-1.

The experimental results are shown in Figure 8. At the first waterflooding stage, when 1 PV of water was injected, the pressure rose gradually and then stabilized at 21.74 MPa. When waterflooding was continued with 0.5 PV of water, the injection pressure declined slightly, indicating that dominant channels of waterflooding had been formed then, and continuous waterflooding could not increase the waterflooding swept volume but scoured to form large pores for seepage, thereby damaging the reservoir. At the stage of reverse injection of DS-1, the injection pressure rose sharply to 45.31 MPa, since the particles have not yet fully absorbed water at this time, the particles have high strength and low elasticity, and the particles with a large particle size play a plugging role. The particles with a small particle size can pass through the pores and enter the front and middle of the core. After 5 days of waiting for swelling, the second forward waterflooding was carried out. The injection pressure rose gradually with the PV of injected water and then stabilized at about 45.75 MPa. When the injection volume reached 3.7 PV, the injection pressure declined slightly, indicating that the smaller particle size at a certain position in the middle of the core is still insufficient to plug the pore throat after water absorption. When the pressure reaches the breakthrough pressure established here, the swellable particles in one pore would be deformed and transported to the next pore to establish stable plugging through transport–plugging–re-transport–re-plugging. The water phase permeability after plugging is 1.2 mD, and the plugging efficiency of the swellable particles is as high as 94.37%, indicating that the swellable particles DS-1 can effectively plug the water channeling channels that are formed after the first waterflooding in low-permeability reservoirs.

3.3.2. Experiment of Oil Displacement Effect of Two Parallel Pipes

In order to test the capability of the swellable particles to enhance oil recovery when acting on strong interlayer (or intralayer) heterogeneous formations, an experiment of two parallel pipes was conducted separately with artificial spliced cores R1 and R2.

The experimental results are shown in Figure 9. After the first waterflooding, the oil recoveries of the high-permeability and low-permeability pipes were 29%, and 5.4%, respectively, with a total oil recovery of 19.88%. When the injection volume reached 1.4 PV, 1 PV of the swellable particles was injected. After 5 days of waiting for swelling, the second waterflooding was carried out. The oil recoveries of the high-permeability and low-permeability pipes were increased by 5.20%, and 7.30%, respectively, with the total oil recovery increased to 25.90%. The experimental results show that the swellable particles can effectively improve the interlayer heterogeneity and control the water absorption profile, thereby forcing the fluid flow to conversely displace the unexploited crude oil to raise the waterflooding swept volume and finally enhance the oil recovery.

4. Field Experiment

4.1. Geological Exploitation Situations in Experimental Well

Experimental Well G42 was located in Block 4 of Oilfield Q, where the formation temperature was 110 °C, the mineralization degree of formation water was 22 × 10⁴ mg/L, the pores in the reservoir were dominated by primary residual inter-grain pores and included various dissolution pores, the permeability was in the range of (28–35) × 10⁻³ μm², and the mean porosity was 12.23%. Furthermore, Well G42 was put into fracturing production in July 2009, and the oil layer thickness was 14.2 m. The daily production of pure oil was 5.61 t during formation testing. At the initial stage after putting into production, the daily fluid production was 7.01 m³, the daily oil production was 6.68 t, and the water cut was 6.8%. At present, the daily fluid production is 12.44 m³, and the water cut was 100%. The accumulative oil production was 18,063 t until now. In this well, the water cut exhibiting stage increased. Water was found in December 2017, and the water cut increased to 80% in December 2019. After the well was repaired in September 2020, the daily fluid production increased from 6.94 m³ to 8.38 m³, and the water cut reached 100%.

4.2. Construction Process

At the end of 2020, profile control and water plugging construction were carried out for the 2538.5–2546.0 m section of Well G42, the designed water plugging radius was 20 m and the total fluid injected into the well was 600 m³. The profile control and water plugging were conducted with the slug injection process. The first slug was 100 m³ of guanidine gum pad fluid extruded forward. The second slug was HPAM polymer solution with swellable particles DS-1 suspended and carried, and its particle concentration was 10% and its volume was 410 m³. In the third slug, 50 m³ of phenolic resin gel was added for sealing, and then 40 m³ of water was injected for displacement. After fluid injection was over, the well was closed. After 5 days of waiting for swelling, normal oil production was started.

4.3. Construction Effect

After water plugging was conducted for G42, the water cut decrease and oil production increase effect was evident. The dynamic curves of production in the oil well are shown in Figure 10.

In Well G42, the mean daily oil production increased from 0 t to 1.45 t, and the water cut decreased from 100% to 83.59%. After the water plugging measure was taken for G42, the water cut decrease and oil production increase effect was evident in the well, indicating that the dominant channels of waterflooding were plugged effectively, thereby achieving reversal of waterflooding fluid flow to raise the sweep efficiency.

5. Conclusions

(1)

Temperature-resistant and salt-tolerant gel particles DS-1 with a three-dimensional reticular structure were synthesized by introducing DMAA monomer into an AMPS/AM/N,N-dimethylbisacrylamide ternary crosslinking system. The median of the initial particle size of the particles is 20.00 μm, where 90% of the particles have particle sizes less than 50.69 μm, and the ratio of particle size above 82.28% to pore throat diameter is 1.4–1.5, which is compatible with the requirements for injection, transport, and plugging in low-permeability reservoirs. The particle surface without water absorption is porous, where each pore has a rough inside surface, and there are good connectivity and thick walls between adjacent pores. The particle surface after water absorption exhibits a reticular structure with dense pores—without the gel failure phenomenon seen at high temperatures salt content—thereby confirming that the particles have a strong water absorption capability and excellent stability.

(2)

Static experimental results show that both an increase in temperature and increase in mineralization degree can influence the swelling property of the particles, but the particles can still maintain a considerable swelling ratio and excellent stability for a long time. The dynamic displacement experiment confirmed that the particles can effectively plug the dominant channels of waterflooding, thereby causing the reversal of fluid flow and increasing the sweep efficiency by controlling the water absorption profiles to enhance the intralayer (interlayer) oil recovery.

(3)

The swellable particles DS-1 had a good water cut decrease and oil production increase effect in the field experiment. In Oil Well G42, the daily oil production increased by 1.45 t and the water cut decreased by 16.41%. The successful use of DS-1 expanded the application scope of swellable particles, providing a new choice for water plugging and profile control agents in low-permeability reservoirs.