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Thermal-steam stimulation (TSS) is considered as the most effective among all up-to-date methods for heavy oil production. However problem consists in lower coverage by steam injection and decreased TSS efficiency at later stage of the development. Paper presents the results of solving this problem by combining thermal-steam and physicochemical stimulations and using "cold" technologies involving thermotropic gel-forming and oil-displacing systems: gels increase reservoir coverage, whereas oil-displacing systems increase oil displacement. In 2008-2013 172 wells were treated on the Permian-Carboniferous reservoir of high-viscosity oil in Usinsk oilfield using IPC SB RAS technologies. As a result the increase in oil production rate ranged of 3-24 ton/d per one well and incremental oil production amounted to 980 tons per one well treatment. It is promising to use integrated technologies alternating injection of steam, gel-forming and oil-displacing systems. They are commercially produced in Russia and China. In 2014 to improve TSS efficiency pilot tests of new technologies were successfully carried out: using gelled system based on surfactants with controlled viscosity to increase simultaneously reservoir coverage and oil-displacement factor; using polymer gel-forming system – for selective water shutoff in production wells. TSS is effective, but expensive method. It is promising to use "cold" technologies. To enhance oil recovery from high-viscosity reservoirs at 20-40 °С we propose to use gels and sols based on low temperature inorganic gel-forming system and oil-displacing alkaline and acid systems based on surfactants, inorganic buffer solution and polyol with controlled viscosity, from tens to hundreds mPa·s, and low freezing point, -20÷-60 °С. In 2014 pilot tests of new "cold" technologies were carried out in Usinsk oilfield. Alkaline system was injected into 5 and acid system into 10 low productivity production wells. After injections oil production rate increased by 5-15 ton/d, fluid flow rate increased by 15-25 m3/d. The technologies were recommended for commercial application.

New methods and instruments developed for measurement of rock thermal properties (thermal conductivity, thermal diffusivity, volumetric heat capacity, and coefficient of linear thermal expansion) have provided a sharp increase in the quality of experimental data for reservoirs and surrounding formations. Optical scanning technology primarily provides numerous high-precision, nondestructive, noncontact measurements of thermal conductivity and diffusivity directly on full cores, core plugs, and nonconsolidated rock samples and enables determination of thermal property tensor components and the recording of thermal property variations along cores. The instrument for simultaneous determination of thermal conductivity, diffusivity at formation temperature (up to 250 degC), and three-component pressure (pore, confining axial, and lateral) enables measurements at formation conditions to study thermal property variations during the heating of reservoirs and oil production in thermal enhanced oil recovery (EOR). The instrument for measurements of the coefficient of linear thermal expansion at temperatures up to 250 degC within every temperature interval of 20 degC provides measurements on core plugs that account for rock anisotropy. Application of the new techniques to study more than 8,000 cores from 17 Russian oil-gas and heavy oil fields provided a representative thermal property database for sedimentary rocks saturated by brine, oil, and gas, accounting for rock anisotropy and inhomogeneity as well as formation pressure and temperature. New correlations between thermal and other physical properties were established. The new experimental data demonstrated that previous information on thermal reservoir properties often needs to be significantly corrected. The new instruments provided detailed information on the spatial and temporal variations in the thermal reservoir properties during thermal EOR. Authors used this to construct detailed 4D reservoir models for estimation of reservoir thermal regime, thermal losses, and heat and mass transfer within reservoirs, enabling better design and optimization of thermal methods of EOR.

Russia's Yarega Heavy Oil Field In 1664, a grand embassy traveled from Holland to Russia. Nicholaas Witsen, a scientist and traveler, was a member of that party, and in 1687, he published, “The North and Eastern Tartary.” He wrote in that book, “The Ukhta River is a one-day travel from the Pechora River. There is a shallow place on the Ukhta River 18 miles from the portage where the water is stained with fat, appearing to be black oil.” In 1721, Gregory Cherepanov discovered an oil spring on the Ukhta River, and Tsar Peter the Great issued an order to inspect the oil spring and take samples for analysis. On 18 November 1745, the Mining Board of Russia granted Fedor Savelievich Pryadunov permission to build an oil plant on the Ukhta River. This was the beginning of the oil industry in Russia, in what is now the Yarega field. The Yarega heavy-oil field was dis-covered in 1932. The field is located in Komi Republic, 20 km from the city of Ukhta. A prominent Soviet geologist, I.N. Strizhev, was a pioneer in discovering the field. The top of the terrigenous reservoir at the Yarega field is at 200 m true vertical depth (TVD). The rock properties have high permeability, oil saturation, and porosity. A dominant characteristic of the field is its high oil viscosity, 16000 mPa·s at the initial reservoir temperature of 6°C. The oil is heavy; in-situ density is 933 kg/m3, 945 kg/m3 at the surface. The gas ratio is 10–13 m3/ton. At the initial field-development stage, attempts were made to drill wells from the surface to produce oil without any formation stimulation. Sixty-nine wells were drilled from two sites according to a 75- and 100-m triangle well-spacing pattern covering 43.4 hectares. The recovery factor after 10–12 years of development was only 0.017. Reservoir development from the surface without stimulation proved to be economically unjustified. In 1934, the geologist A.V. Kulevsky proposed the idea of hot-water stimulation. Laboratory test results were encouraging, but insufficient technical and engineering support prevented the implementation of the thermal-stimulation technique in the field.

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