CDG are microgels formed in-situ. Gel aggregates form in a lowly-concentrated solution of partially hydrolyzed PAM with a high molecular weight (more than 22 million Da) and a cross-linker (usually aluminum citrate of chrome citrate) [17,27]. The PAM concentration must be below the critical overlap concentration of the polymer, usually 100–1200 ppm. At this concentration, the polymer chains undergo intramolecular cross-linking, forming polymer coils. The ratio of the polymer to crosslinker concentrations vary from 20:1 to 80:1 [35]. The CDG globules formed may reach 1–150 nm in size [38]. The end of the CDG globules formation process is identified by a decrease in the solution’s viscosity [39]. CDG gels have been tested successfully in the fields of Argentina, China, and the United States [40,41,42]. An analysis of 31 cases of pilot tests is presented in the paper [43], the authors of which summarize the main parameters for implementing the technology on the well. The temperature of reservoirs where CDG was applied was 25–100 °C, reservoir permeability varied from 10 to 4200 µm², and the oil viscosity of the treated deposits was 5–30 cPs.

During CDG injection, it is important to avoid any sudden pressure surges that could lead to gel transfer into the production well. The injection pressure can be controlled using the following parameters: injection rate, gel concentration, and polymer-to-crosslinker concentration ratio. In cases where the reservoir has the pronounced heterogeneity, CDG treatment is carried out after preliminary in-situ gel injection [44]. Depending on the injection pressure, CDG treatment can be changed in stages. In cases where the initial permeability of the formation is high, a high-concentration gel slurry is injected; after increasing the injection pressure, the PAM concentration is reduced [44].

CDGs are in-situ gels, i.e., microgel globule formation takes place inside the reservoir. The CDG technology requires low concentrations of polymer and crosslinker having inherent drawbacks of poor water production control. Moreover, factors such as shear degradation during injection, dilution by reservoir water, and interaction with minerals leads to a decrease in effective polymer concentration [45]. All these factors in a case of CDG application could lead to weak reservoir conformance control. The microgels considered further in this article have a significant difference in that they are synthesized before being injected into the dedicated equipment.

DPGs are uniform spherical particles with the size adjusted from nm to mm (see Figure 5). The DPG receiving process occurs in two stages. The first is bulk gel formation. Here, gel strength and thermostability can be adjusted using the PAM with the suitable degree of hydrolyzation and a suitable cross-linker. The second stage is gel cutting by imposing high-speed shearing forces for several minutes [46]. A peristaltic pump [47] or colloid mill [46] can be used for the shearing. In the paper [46], research on DPG made of PAM and phenolic resin is described. The preparation procedure conditions are as follows: the first stage involves the formation of bulk gel at a temperature 75 °C. Thereafter, the gel is mixed with water (in similar proportions) and grinded using a colloid mill (3000 rpm, 3 min) to produce uniform particles 2.5 µm in size. In the article [38], the author used chromium acetate as a cross-linker. The results of experiments showed that Cr-DPG demonstrates good salinity resistance at 30 °C. The experiment for determining the thermostability showed that DPG size distribution dramatically changes after 15 days at 90 °C. The size of the lowest particles was halved (from 186.6 nm to 400 nm), and that of the highest particles increased by more than 5 times (from 796.2 nm to 4450 nm). Lab sand pack core flooding experiments on samples with a permeability ranging from 0.47 µm² to 8.89 µm² showed that DPG has good injectivity, which makes it an effective in-depth plugging agent.

In the article [49], a novel strengthened dispersed particle gel (SDPG) is presented. Silica nanoparticles (SiO₂) were used as reinforced material to improve resistance to the high temperatures and high-salt content in the reservoir water. A non-ionic PAM of molecular weight 9,650,000 g/mol and a phenolic resin crosslinker were used. The SDPG obtained demonstrated their stability at 110 °C and a total salinity of about 213 g/L [50]. Several research describe the effective combination of DPG with surfactants [45,49,50]. The synergetic effect of the combination was confirmed during core flooding tests. The current research of the team of scientists who developed DPG focuses on self-growing hydrogel particles capable of growing after migration to deep fractures [51].

As mentioned above, PPG is a particle gel obtained from drying and grinding of the bulk gel [52]. These gels have a three-dimensional structure that forms during synthesis by cross-linking polymer chains with covalent polar bonds [30]. Preformed particle gels are polyacrylamide-based gels that absorb water and become soft and elastic. Their properties allow particles to penetrate into highly-permeable intervals of the formation. PPGs can be applied both on the fracture and on sandpack reservoirs [52,53,54]. Depending on their structures, PPGs have different mechanical properties that determine particle penetration into the permeable interlayers of rock. Weak PPGs have a better penetration capability and form a permeable crust on the surface of the lowly-permeable interlayer [55]. PPGs block the fractures partially because they are able to form channels for water passage. It is known that weak PPGs create internal channels more easily than strong gels [56]. Under harsh conditions (high salinity and temperature), ordinary PPGs shrink as a result of amide group hydrolysis and crosslinking by polyvalent metal from the water [57,58]. Nanocomposite PPGs with a superior stability and improved mechanical properties are presented in the paper [57]. The modified PPGs contained an equimolar ratio of the acrylamide, vinylpyrrolidone, 2-acrylamido-2-methylpropane sulfonic sodium salt; BIS as a crosslinker. The mechanical properties of the PPGs were enhanced by adding a dispersion of modified bentonite (MB) to the formulation. The nanocomposite PPS obtained demonstrated stability over 3 months at 130 °C. The swelling capacity in 25% total dissolved solids (TDS) solution was 9.53 g/g and that in fresh water 53.43 g/g [57].

The authors of the article [59] studied the matching factor of PPG in coreflooding experiments. Matching factor is the ratio of the PPG’s average diameter to the average pore-throat diameter. PPGs with a swelling particle average size of 9.1 µm were used in the experiments. Several cemented quartz cores were used with different permeability characteristics. The plugging behaviors of the PPG particles were summarized as three basic patterns: complete plugging (core permeability 26.26 mD); plugging-passing through in a deformation or broken state–deep migration (strong plugging in test on core with permeability 46.63 mD; general plugging in cores with 180.34 mD and 240.77 mD, weak plugging in core with 327.74 mD); inefficient plugging—smoothly passing through—stable flow (core permeability of 430.93, 633.29, and 857.86 mD).

Field trials of micro-sized PPG particles are represented in the paper [60]. Microgel size is described as, for example, 28 pm, which means the particles size is less than 28 µm. Particles were obtained from the grinding of bulk gel pieces. Microgel absorption capability at 125 °C in fresh water is about 23, and decreases to 6.5–7.0 when the brine TDS is more that 5%. Microgels are stable during at least one year at a temperature of 125 °C. For the trial treatment, a mature oil field in Northwestern China was chosen. The basic reservoir characteristics include a severe vertical and lateral heterogeneity and an average permeability of 230 md (max permeability was about 1500 md, water-cut of production wells was 95%). Treatment lasted 10 months, 169 tonnes of microgel were injected. The post-treatment effect lasted 18 months, and the quantity of additional oil was about 29.6 thousand tonnes, i.e., 175 tonnes of oil per 1 tonne microgel particles.

SMG Microgels (Small Microgels) are a great example of acrylamide-based covalent cross-linked polymeric gels [31,61,62,63]. SMG are nontoxic [62]. Particle size varies between 0.3 and 2 µm. Their rigidity depends on the chemical composition, particularly of the cross-linker concentration. The three-dimensional structure gives the particles mechanical, thermal, and chemical stability. High shear-rate treatment (15,000 s⁻¹) experiments have demonstrated stable viscosity for 16 min. SMGs are almost two times stable in brine containing H₂S than in an ordinary PAM solution of a similar concentration. Thermal stability tests at 120 °C have demonstrated stable viscosity over three months. First, SMGs were considered for water shut off [64]; however, lab experiments on the SiC granular pack and natural sandstones demonstrated that SMGs have a great in-depth propagation. It has also been established that due to capillary forces, SMGs may be absorbed on pore walls forming thick layers, leading to water permeability reduction. The authors note that in these conditions, oil permeability remains unaffected. As conventional polymers, SMGs behave in the same way as relative permeability modifiers (RPM) [61]. The thickness of the absorbed layer can be regulated by varying the injected flow rate, microgel size, and concentration [31]. The paper [62] presents studies on how the high salinity of water affect SMG properties. These experiments showed satisfactory dissolution of microgels in brine with a salinity 215 g/L of TDS (sodium and calcium chloride). Layers adsorbing microgels tend to swell in low-salinity solutions and shrink when the salinity increases due to a charge screen on the gel particles surface. During coreflooding tests, the permeability reduction was fixed for a wide range of SMG suspension brine concentrations (20–108 g/L of TDS). When testing a suspension with a high salinity (200 g/L of sodium chloride and 15 g/L of calcium chloride), the post-treatment core permeability was found to be less. However, post-flush experiments allowed observing the hysteresis effect of microgel swelling behavior [62]. The first industrial case of successful SMG application was in 2005 for the treatment of an underground gas-reservoir storage [61,62]. In the paper [62], the authors present the first conformance control treatment using SMG. The chosen test well was an injection well surrounded by 7 producers. The basic reservoir had the following characteristic: permeability varying from 10–1000 mD (average around 200 mD), reservoir temperature 48 °C and reservoir water salinity 8000 ppm of TDS. A microgel suspension having a concentration of 500 ppm (1500 ppm of commercial solution) was injected over three months for a total volume of 9000 m³ (0.1 pore volume). Although the treatment pressure increased, it remained below the maximum authorized pressure. One year after treatment, the amount of additional oil was 1570 m³, and water production had been reduced by 23,830 m³ [31]. Two years later, the volume of additional oil was still increasing, reaching 5440 m³ after 26 months. 2.5 kg of microgel was injected for each tonne of additional oil [63].

The authors of the paper [65] synthesized microgels by free-radical polymerization in inverse emulsion using diesel oil in a continuous phase. The chemical structure of the microspheres is formed by polyacrylamide cross-linked by BIS; a mixture of Tween-60 (polyethylene glycol sorbitan monostearate) and Span-80 (sorbitan monooleate) was used as an emulsifier. The absorption capability was determined by changing the particle diameter: the average diameter of the original macrogels was 50 nm, and after swelling, it reached several µm. The authors discovered that the emulsifiers used during the synthesis in combination with an additional surfactant or NaOH sharply reduce the oil/water interfacial tension during microsphere injection, leading to increasing residual and remaining oil saturation. Core flooding test on sandpacks models showed that microgel injection gives about 20% of additional oil. It was proved that microspheres have a great potential in EOR, particularly in reservoir profile control.

Other examples of microspheres based on polyacrylamide and synthesized using the invers emulsion method are represented by different groups of researchers in the papers [66,67,68,69]. The BIS crosslinked elastic microspheres described in [66] swell in 3 days. The average microsphere diameter is 12.05 µm, the size of the swelling particle may increase to 25 µm depending on the temperature. In the salt solution (15–20 g/L), the size of particles is about 16–17 µm. Core flooding experiments on a sand pack demonstrated that the ideal matching factor (microsphere diameter/pore size ratio) is 1.35–1.55. At this ratio of microsphere diameter to pore size, gel particles are able to move while embedded deep in the sand pack. Authors of the article [68] presented a visualization of the process of pore filling by microspheres. A micro-visual model with a pore-throat size of 200–1000 µm was created. After microsphere dispersion pumping, some microspheres were accumulated and squeezed in the pore throat of the model, being used for plugging (see Figure 6). This observation proves that microgels are capable of changing the direction of the injected water to a reservoir’s oil-bearing interval [67].

Authors of the article [67] describe microsphere synthesis using the invers emulsion method; however, the difference is in the absence of any cross-linker in the co-monomers mixture (only acrylamide and acrylic acid). The average diameter of the microspheres obtained was 5 µm (Figure 5). After swelling, the particle size increased 5 times, which is more than with BIS cross-linked microgels described in the article [66]. Core flooding tests on the sand pack also proved the ability to redistribute injected water flows in the low permeable zones of the reservoir.

To adapt microsphere properties to the reservoir conditions, different types of microspheres with different viscoelastic properties were developed. The teams of authors of the papers [70,71,72] presented low elastic polymer microspheres given names such as L-EPM (i.e.) also synthesized using the invers emulsion method. The co-monomers of microspheres are acrylamide, acrylic acid, 2-acrylamido-2-metilpropansulfonic acid (AMPS), and BIS. Aviation kerosene was used as the continuous medium. The emulsifier was made from a mixture of Span-80 and Tween-60. The authors consider one important characteristic of microgels responsible for particle deformability and injection ability as storage modulus. The storage modulus G’ of L-EPM is 23.6 Pa. Experiments for determining microsphere behavior in the core pore space are presented in the paper [73]. For the test, sandstone cores with different porosities and pore sizes were taken. Depending on the microsphere-diameter-to-pore-size ratio, the following mechanisms of L-EPM penetration in the core were identified: (1) direct passing through the pore throat; (2) microsphere adhesion in the pores; (3) dehydration, stretching, extrusion, and retention to original form; (4) squeezing and breakage into pieces under pressure and its forward migration; (5) microspheres stack at the injection end of the sand pack, forming an external filter cake [48]. The coreflooding experiments showed that L-EPMs have a high selective profile control performance in remote heterogeneous reservoir zones [71].

Microsphere modifications are micron-size silica-reinforced polymer microspheres synthesized using the above-mentioned inverse suspension polymerization with the addition of 3-(methacrylyloxy)-propyl-trimethoxysilane (MPS) and silicon dioxide (nano sized) (authors call these microspheres such as PNSCMs) [74,75,76]. By adjusting the content of MPS-modified SiO₂, the microsphere swelling ratio can be regulated well and the sensitivity of the swelling behavior to the environment is weakened. With increasing SiO₂ loading, the microsphere mechanical stability, thermal stability, viscoelasticity, and dispersion stability were correspondingly improved [74]. PNSCM particle sizes vary between 10 and 100 µm. The swelling capability of SO₂-modified microspheres was 35.5 g/g (for comparing the swelling capability of conventional microspheres was 47 g/g). Temperature has less effect on the swelling capability of silica-reinforced microspheres than that of conventional ones. This can be attributed to the introduction of modified SiO₂. The maximum degradation temperature of silica-reinforced polymer microspheres was 430 °C (11 °C better than conventional microgels). In the article [76], the results of sand pack core flooding tests are represented. The main parameters of the experiment are as follows: the initial permeability of the core was 2.17 µm², porosity about 30%, the resulting permeability decreases to 0.35 µm². SO₂-modified microspheres demonstrated excellent plugging properties in the micron-size pore throat, and the authors recommend it for deep conformance control application.

To detect microspheres in the reservoir-produced fluid, a new type of microspheres that fluoresce under ultraviolet irradiation was synthesized using an inverse suspension polymerization method [77,78,79,80]. The following fluorescent co-monomers were used for microgel synthesis: acryloyloxy coumarin [77,80], allyl-rhodamine B (RhB) [77,78], oxyfluorescein [77] (see Figure 7, Table 1). Since the concentration of fluorescent monomers was quite small, there were no significant changes in the initial particle size and the swelling property of the polymer microspheres.

These microgels were developed by a consortium of BP, Chevron, Texaco, Mobil and Nalco Exxon Energy Services representatives. The idea of thermal-activated microgels is based on the fact that water injected into an oil reservoir is often cooler than the reservoir rock, which leads to formation of a temperature front somewhere between injection and the production wells [81]. Brightwater microgels are synthesized using the invers emulsion method in light mineral oil. The commercial form is 30% wt concentrate in light mineral oil. The chemical structure is based on highly cross-linked sulfonate-containing polyacrylamide. The three-dimensional structure is formed by two types of cross-linkers: stable and unstable. If the temperature rises the unstable cross-linker dissevers, particles absorb more surrounding water and expand. The author calls it the “popcorn effect”. Correct selection of cross-linkers provides particles with a sensitivity to the required temperature. Microgel particle sizes may vary from 0.1 to 3 µm. After popping, the particle size increases to 15–20 µm. Core fluid experiments on kernel particles have demonstrated that swelled microgels are able to penetrate the core with a permeability higher than 124 mD. The resistance factor and residual resistance factor values depend on the microgel concentration and core porosity [81]. Brightwater has been applied since 2001 starting from the Minas Field (Indonesia) [82]. There have also been trials in Brazil (Salema Field, Campos Basin) [83], and Alaska [84]. The main criteria for choosing the test oil-well for treatment include available movable oil reserves, early water breakthrough to high water-cut, porosity of highest permeable zones more that 17%, permeability in thief zones more than 100 mD, minimal reservoir fracturing, reservoir temperature 50–150 °C, and salinity of injection water not higher than 70,000 ppm [82]. The paper [84] presents tests of the Brightwater product in Alaska, Mylne Point field. The reservoir was generally homogeneous, with several macro-fractures mapped over the area. The tests were carried out on the area with three wells: one injection and two production wells. The production wells had a water cut of about 90%, the recovery factor was 20%. For processing, a microgel with a dry particle size of 0.1 to 1 μm was used, in swollen form—5 μm. Laboratory tests of the microgel demonstrated its stability for 2 years at elevated temperatures and a water salinity of 120 g/L. The reagent injection was divided into three sequential stages: (1) rapid injection of particles to pass the particles across the near wellbore formation zone; (2) filling the most permeable intervals with particles, heating to the formation temperature, destruction of temporary crosslinking; (3) popping and swelling of particles at a temperature of 50–75 °C. The temperature of the suspension when it acquires the perforation zone in the injection well was about 45 °C. The formation temperature at the production well in the same interval reached 80 °C. The treatment was carried out within 21 days. 60.8 tonnes of microgel suspension with a concentration of 3300 ppm were injected and 30.4 tonnes of surfactant were additionally pumped together. No change in injectivity was observed during the pumping. The first decrease in injectivity occurred 9 months after treatment. During the same period, recovery of additional oil was started for one oil production well. For another well, the production response was 11 months after treatment. The effect lasted 2 years. The total incremental oil volume was about 8000 m³ [84]. Experiments conducted on the test oil field demonstrated that Brigthwater is a thermally reactive particulate system that functions as an in-depth reservoir conformance control agent.

This type of microgel is highly sensitive to pH changes: the microgel suspension has low viscosity at low pH, with the viscosity increasing with an increase in the pH value. This gel is used for conformance control in remote formation zones: a microgel suspension is injected into a low-pH environment, small particles penetrate and move across the near-wellbore zone. During this process, acid from the microgel suspension reacts with rock minerals, leading to an increase in pH, microgels swell and block the highly-permeable zones deep in the reservoir. The pH-responsivity is provided by incorporation of co-monomers possessing carboxyl functional groups (e.g., acrylic acid) [85]. With increasing pH, the carboxylic groups of polyacrylate networks are hydrolyzed, and the charged groups repel each other. As a result, polymers chains are stretched and microgels swell [86]. To guarantee microgel penetration into the deep reservoir zone on the first stage of the reservoir treatment, pre-flush of formation by acids is recommended [86]. The experiments showed that acetic acid is better as a pre-flush agent [86,87]. The second stage is microgel injection, and the last stage of treatment is post water flooding. The higher water mineralization, the lower the pH value of weak acids, and the less swelling capability of microgels [87]. The most widely used pH-sensitive microgel is Carbopol^® (Lubrizol, Calvert, KY, USA). There have been several studies on the efficiency of microgels made using sandstone and carbonate cores [86,87,88,89,90,91]. The average size of Carbopol dry microgel particles is 2–7 μm. The permeability of cores used in the experiment was about 2.3 µm² [87]. All experiments showed that at a pH of 2 (pH of microgel suspension), microgels block the injection end of the core. pH correction using NaOH helps overcome this problem [88]. During the flooding experiments, it was shown that these microgels efficiently plug the fractures and high permeable zones and redistribute filtration flows of water into the rock matrix. [86,87].