During several decades high viscous guar-based gels remained main and single fluid type on Russian fracturing market. Having high viscosity and excellent proppant carrying capacity, crosslinked gel possesses damaging nature–it results in low retained conductivity of proppant pack even in case of oxidative destructors usage (<50%). In 2016-2017 low viscosity fluids based on synthetic polymer – polyacrylamide (High Viscosity Friction reducer, HiVis FR, HVFR, Viscous slickwater) started to be actively used in North America for shale fracturing. Along with improved sand carrying capacity in comparison with conventional FR due to its elastic properties, fluid demonstrated high retained conductivity of sand packs (~80%) confirmed during laboratory investigations, firstly performed by Stim-Lab (Stim-Lab Proppant Consortium 2015 – Fracturing Fluid Cleanup of various Low Polymer Fluid Systems; Stim-Lab Proppant Consortium - 2016 – Historical and current Friction Reducer Studies). However, fracturing design and job execution on conventional sandstones in Russia significantly differs from shales stimulations, i.e. serious work was required in order to start implementation of HiVis FR (Viscous slickwater) on sandstones in Russia. First field trials of Viscous slickwater were performed in Russia in the end of 2018 on conventional sandstones owned by "Gazpromneft-Khantos" - Gazpromneft subsidiary. In spring 2019 first time in the world full scale fracturing jobs, where Viscous slickwater with only ~30 cP at 511 s-1 demonstrated high transport efficiency to carry and place ceramic proppant at moderate rates (4-4.5 m3/min), as in combination with crosslinked gel as well as single fracturing fluid. Prior HiVis FR was qualified for application on sandstones as alternative to guar-based high viscous gels, major laboratory investigations were performed on novel fluid rheology, dynamic proppant transport, mechanical fluid properties, influence of breakers, etc (Loginov at al. 2019). Later, in field trials phase, additional laboratory testing was carried out to address specific fluid performance questions. New technology field trials for "Gazpromneft-Khantos" were executed with high operational success–according to initial fracturing design. Viscous slickwater was pumped as single fracturing fluid, as well in combination with crosslinked guar gels (≥50%). Jobs were performed on vertical, inclined and horizontal wells. Despitê20 fold difference in viscosity, high proppant transport efficiency of HiVis FR allowed to place standard for South part of Priobskoe oilfield designs in case of hybrids and slightly less aggressive designs in case of 100% jobs on slickwater. Application of Viscous slickwater allowed to identify number of advantages of novel fluid over traditional guar-based fluids both in terms of operational efficiency, location and environmental footprint and fluid performance characteristics. It was shown that start production of wells treated with slickwater were ~10-20% higher, and current production rate were comparable in comparison with traditional designs with higher proppant volume. Field trials on implementation of Viscous slickwater - fluids based on polyacrylamide on low viscosity reservoirs owned by "Gazpromneft Khantos" were proven to be successful both from operational and technological point of view and have become a new milestone in history of Russian fracturing. This basis could be key to the future effective development of analogical oilfields in the world.

The Southern licensed site of Priobskoe Oilfield (South-Priobskoe Oilfield, hereinafter SPRB) is the largest object of Gazprom Neft-Khantos. For the development of low-permeability productive formations AS10-AS12 it is economically feasible to drill horizontal wells (HW) with subsequent multistage hydraulic fracturing (MSHF). Growth of horizontal wells number raises the question of the implementation of different resource-saving technologies, including technologies to speed up the processes related to the preparation of water for hydraulic fracturing. It is also worth considering that in the case of horizontal wells drilled in areas with complex geological structure, which include a part of SPRB, еthere are higher risks to have a premature screen-out during MSHF and accordingly increased cost and time required to complete the well. Fracturing operation utilizing water with temperature equal 10-15°C water – cold water concept vs. standard 25-30°C allows to substantially optimize fracturing preparation steps and improve operational efficiency, which ultimately is expressed in accelerated time to put the well on production. Also, decreased operating time of water heaters leads to a reduction of environmental footprint and air emissions. Channel fracturing technology with pulsed proppant placement, forming highly conductive channels in the fracture, allows to reduce the proppant mass and the volume of hydraulic fracturing fluid while maintaining the target fracture half-length. Combination of cold water concept with channel fracturing technology demonstrated significant acceleration of multistage hydraulic fracturing operation cycle for horizontal wells at the SPRB.

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The South-Priobskoe Field is one of the largest oil pools in Western Siberia, with a unique category of reserves. Due to the low filtration properties of the productive formations AS10-AS12 (permeability of which is not more than 3 mD), the drilling of horizontal wells with subsequent multi-stage hydraulic fracturing (MSHF) completion is the most cost-effective way in this case. The use of highly viscous fracture fluids (at least 400 cP at 100 s-1) and 16/20 mesh proppant with a maximum concentration of 800-900 kg/m3 and the slurry rates are not exceeding 4.0 m3/min, became a kind of standard during the MSHF. However, a steady decline of permeability in the newly drilled areas of the field is observed (below 0.5 mD), because of this, an effective half-length of cracks begins to make an increasing contribution to oil production. This paper describes the introduction of non-standard methods of hydraulic fracturing for a traditional reservoir, and an idea was the use of low-viscous fluids with increased slurry rates, which resulted in an increase in well production rates by an average of 7%.

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