Anatoly Politov

To improve the efficiency of injecting intensifying chemical slugs into injection wells, new formulations have been proposed. These compositions are based on high-tonnage surfactants combined with industrially produced nanoparticles. Experiments show that adding silica- or carbon-based nanoparticles to surfactant compositions doubles the oil displacement coefficient from Pashian sandstones. Carbon nanoparticles derived from shungite mineral were also tested. It was found that during the filtration of the surfactant solution, the increase in the oil displacement coefficient is always lower than during the filtration of the same solution in the presence of nanoparticles. This composition contains anionic and nonionic surfactants in a 1:2 ratio at a 1% concentration in fresh water, with a 1% nanoparticle additive. It increases the oil displacement coefficient by 19.0–23.2% after waterflooding. It has been established that in the proposed technology for near-wellbore formation treatment, the role of nanoparticles lies in a transport function due to the formation of nanoparticle aggregates with surfactant micelles, representing dynamic structures sized 25–75 μm. These aggregates break apart when passing through narrow pore throats. This delivers surfactants directly to the oil–rock interface, mobilizing residual oil and improving displacement. Nanoparticles of silica with different wettability, during filtration, are deposited in pore channels, leading to intra-pore flow redistribution. Together with the increased microscopic sweep efficiency from surfactants, it results in lower residual oil saturation.

To improve the efficiency of injecting intensifying chemical slugs into injection wells, new formulations have been proposed. These compositions are based on high-tonnage surfactants combined with industrially produced nanoparticles. Experiments show that adding silica- or carbon-based nanoparticles to surfactant compositions doubles the oil displacement coefficient from Pashian sandstones. Carbon nanoparticles derived from shungite mineral were also tested. Regardless of nanoparticle type, a specific surfactant composition was highly effective. This composition contains anionic and nonionic surfactants in a 1:2 ratio at a 1% concentration in fresh water, with a 1% nanoparticle additive. It increases the oil displacement coefficient by 19.0-23.2% after waterflooding. It has been established that in the proposed technology for near-wellbore formation treatment, the role of nanoparticles lies in a transport function due to the formation of nanoparticle aggregates with surfactant micelles, representing dynamic structures sized 25-75 μm. These aggregates break apart when passing through narrow pore throats. This delivers surfactants directly to the oil-rock interface, mobilizing residual oil and improving displacement. Nanoparticles of silica with different wettability, during filtration, are deposited in pore channels, leading to intra-pore flow redistribution. Together with the increased microscopic sweep efficiency from surfactants, it results in lower residual oil saturation.

Polyacrylamide and polyacrylamide/polysaccharide hydrogels exhibiting high structural and mechanical properties, along with acceptable gelation times and gelant viscosity, are proposed for water shutoff applications in high-temperature reservoirs. The obtained polyacrylamide gels demonstrate an elastic modulus 1.6–2.7 times higher than that of the baseline polyacrylamide–resorcinol–paraform–sulfamic acid gel (17.2 Pa), reaching up to 46.3 Pa, while the polyacrylamide/polysaccharide gels surpass it by a factor of 2.3–5.2, reaching up to 89.9 Pa. The gelation time of the polyacrylamide/polysaccharide gels ranges from 3 to 7 h, with the gelant viscosity varying from 685 to 2098 mPa·s at a shear rate of 100 s⁻¹. Crosslinking of polyacrylamide with polysaccharides was achieved using paraform. Using the gel based on crosslinked polyacrylamide with xanthan as an example, spectral methods characterized the copolymer constituting the basis of the plugging material. Our analysis established that crosslinking occurs between the amide group of polyacrylamide and the hydroxyl group of the polysaccharide. Model reactions with low-molecular-weight analogs (glucose, acetamide, and formaldehyde), coupled with mass spectrometric confirmation of the structure of the resulting products, revealed possible reaction pathways. The crosslinking of polyacrylamide was investigated using a broad range of polysaccharides of plant and microbiological origin. The resulting series of hydrogels, possessing the suite of properties required for water shutoff in high-temperature formations, will enable oil companies (operators) and service firms to select a specific gel-forming system based on project objectives, logistics, and budget constraints.

Well-killing operations in water-sensitive hydrophilic formations are often complicated by extended well clean-up periods and, in some cases, failure to restore the well’s production potential post-kill. Typical development targets exhibiting these properties include the Neocomian and Jurassic deposits of fields in Western Siberia and Western Kazakhstan. This paper proposes a well-killing method incorporating simultaneous near-wellbore treatment. In cases where heavy oil components (asphaltenes, resins, or paraffins) are deposited in the near-wellbore zone, their removal with a solvent results in post-operation flow rates that exceed pre-restoration levels. For wells not affected by asphaltene, resin, and paraffin deposits, killing is performed using a blocking pill of invert emulsion stabilized with an emulsifier and hydrophobic nanosilica. During filtration into the formation, this emulsion does not break but rather reforms according to the pore throat sizes. Flow rates in such wells typically match pre-restoration levels. The described engineering solution proves less effective when the well fluid water cut exceeds 60%. For wells exhibiting premature water breakthrough that have not yet produced their estimated oil volume, the water source is identified, and water shutoff operations are conducted. This involves polymer-gel systems crosslinked with resorcinol and paraform, reinforced with inorganic components such as chrysotile microdispersions, micro- and nanodispersions of shungite mineral, and gas black. Oscillation testing identified the optimal additive concentration range of 0.6–0.7 wt%, resulting in a complex modulus increase of up to 25.7%. The most effective polymer-inorganic composite developed by us, incorporating gas black, demonstrates high water shutoff capability (residual resistance factor ranges from 12.5 to 65.0 units within the permeability interval of 151.7 to 10.5 mD). Furthermore, the developed composites exhibit the ability to selectively reduce water permeability disproportionately more than oil permeability. Filtration tests confirmed that the residual permeability to oil after placing the blocking composition with graphene is 6.75 times higher than that to water. Consequently, such treatments reduce the well water cut. Field trials confirmed the effectiveness of the developed polymer-inorganic composite systems.

The challenge of water shutoff in carbonate reservoirs is complicated by the presence of fractures, which cannot be effectively blocked using conventional hydrogel screens designed for granular reservoirs. To reliably seal fractures, fibrous and dispersed fillers are added to hydrogels. These fillers must exhibit affinity for the matrix to ensure the composites can effectively isolate water. Given the wide variability in fracture apertures, it is evident that water shutoff composites should incorporate fibers and dispersed fillers of varying geometric sizes. This study presents a range of hydrogel composites reinforced with mono-, bi-, and tri-component fibers, as well as dispersed fillers, designed for water shutoff in fractured carbonate reservoirs with varying fracture apertures. Oscillation test results demonstrated a twofold increase in the elastic modulus (40–45 Pa) for compositions with various fillers compared to the base composition (23 Pa). Filtration studies revealed the effectiveness of the optimized compositions under different fracture apertures. Specifically, even at a fracture aperture of 650 μm, the residual resistance factor (RRF) reached 82.3 and 9.76 at water flow rates of 0.1 cm³/min and 0.5 cm³/min, respectively. The conducted rheological and filtration tests, along with field trials, confirmed the validity of the selected approach.

Investigations of crystalline phenanthrene in the Bridgman diamond anvils under pressure up to 5,0 GPa and simultaneous shear caused by optical microscopy and fluorescence spectroscopy were carried out. It’s proven that phenanthrene fluorescence spectrums are reversibly changed under high pressure. The phenanthrene vibrational structure of lines disappears similar to the one of the anthracene. Dimerization or any other irreversible changes under combination of high pressure and shear in phenanthrene, unlike anthracene, were not observed.