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The channel fracturing technique changes the concept of proppant fracture conductivity generation by enabling hydrocarbons to flow through open channels instead of through the proppant pack. The new technique is based on four main components: proppant pulsing at surface with fracturing equipment and software, a customized perforation strategy, a fibrous material to deliver stable channels, and a set of models to optimize channel geometry. The Taylakovskoe oil field is located in western Siberia—430 km away from the nearest settlements. The Jurassic reservoir in Taylakovskoe field is a sandstone formation with significant net pay (average 25 m) and middle-range permeability (3 to 20 mD). Bottomhole temperatures range between 85°C and 90°C. Fracturing gradient is typically 14 kPa/m. The majority of the wells are stimulated immediately after drilling. Sufficient fracture conductivity and effective fracture length are essential for adequate well performance. The optimization of hydraulic fracturing treatments conducted in recent years was based on improved fluid chemistry and pumping "aggressive" fracture designs; this yielded high-quality results. The new channel fracturing stimulation technique, which allows significant increases in fracture conductivity, became the next technological progression. With channels inside the fracture, fluid and polymer residue flow back faster than with a conventional proppant pack, improving cleanup and increasing effective fracture half-length. One of the most important advantages of the new technology is a very low risk of screenout events. The fibers make fluid more stable, while the presence of clean pulses around proppant structures promotes bridging-free flow. Reduced risk of premature treatment termination is even more important in remote operations such as in the Taylakovskoe field because of the higher costs of nonproductive time and deferred oil production. Candidate selection criteria were developed specifically for local conditions. Ten channel fracturing treatments performed in Taylakovskoe wells have already showed significant increases in incremental oil production—average 44% beyond expected production as shown by well performance analyses. We describe the performance evaluation of wells completed with this technology and future plans for applying channel fracturing methods in the Taylakovskoe field.

Scale formation and accumulation is a major concern for Russian production companies. In Western Siberia, most wells produce fluids via Electric Submersible Pumps (ESP), and it is believed that up to 30% of the ESP failures result from scale damage. Despite that scaling is commonly first recognized at the ESPs, it can ultimately affect the whole production system. The most efficient treatment strategy to prevent scale induced damage in the tubular, including ESP, is scale inhibition. Traditionally, this involves an inhibitor squeeze treatment which is a localized inhibitor placement covering the near-wellbore area or the continuous injection of the inhibitor via a capillary tube. However, these techniques are designed to protect the production system. Squeeze treatments in hydraulically fractured formations are not always effective. Scale inhibitors together with compatible borate fracturing fluids can be used for a more effective scale inhibitor placement throughout the created hydraulic fracture to prevent scale formation from the reservoir level to the production system. This technique combines hydraulic fracturing and scale inhibition into one treatment resulting in operational simplicity. Since 2008, the combined fracturing/scale treatments have been successfully applied in the Krasnoleninskoe oil field in Western Siberia. This paper outlines the learning procedure and presents designs, testing and monitoring results from the campaign conducted at Krasnoleninskoe oil field (including Talinskaya and Em-Egovskaya sections).

Horizontal drilling and multistage fracturing completions are becoming widespread practices in the development of Western Siberia’s low-permeability oil fields. More than 100 wells have been completed to date—with success from both operational and production perspectives. The majority of applications were applied in newly drilled wells, where it is possible to install openhole packers and frac ports for isolating fracture stages. The concept of multistage fracturing was transferred to old areas of brownfields, where sidetracks drilling was the main method of increasing oil recovery. Traditional sidetracks were associated with risks of production underachievement in low-permeability environments - even after stimulation treatments. The ability to drill sidetracks with a considerable horizontal section, and stimulating them with several fracturing stages would improve production significantly. However, slim wellbores of sidetracks significantly restrict completion option choice and abrasive perforating via coiled tubing (CT) becomes a universal enabler for multistage fracturing treatments. One of the greatest challenges in such a process is isolation between the stages. Fiber-enhanced proppant plugs were used for better proppant grains suspension, which sets the plug in the most efficient, homogeneous way. The first well was recently completed with this method. Three stages of fracturing stimulation were performed with CT abrasive perforation; fiber-enhanced proppant plugs were placed at the tail-in of the first two fractures. In both of the fractures, reliable isolation was achieved at first attempt. After all three stages were placed, wellbore cleanout with CT was performed, followed by nitrogen kickoff. Oil production has exceeded expectation by 30%. Multistage fracture (MSF) stimulation in the horizontal section of a sidetrack well completed with cemented liner with the utilization of abrasive perforating and fiber-enhanced proppant plugs has demonstrated unique value, as it is the only effective solution currently available for these conditions. The decision-making and candidate-selection processes, execution and lessons learnedare described.

This reference is for an abstract only. A full paper was not submitted for this conference. Introduction Kamennoe field is one of the most valuable assets and one of the major development projects of TNKBP in Western Siberia. Most of the production in Kamennoe comes from the shallow VK formation of Neocomian age. Most of the reserves are attributed to the upper VK-1. Typically, the underlying VK-2 formation is water- saturated with a relatively weak barrier toward VK-1. Stimulation Practices Overview in Kamennoe Field, Western Siberia Hydraulic fracturing is being successfully used to uncover the reserves of Kamennoe field and sustain production growth. One of the major challenges is placing the desired volume of proppant into the target formation (VK-1) without breaking into the waterbearing VK-2 through the weak barrier. To address this challenge, the series of techniques has been successfully introduced to assist proppant placement into the target zone while reducing the risk of breakthrough:• artificial barrier placement• linear fracturing fluid at the pad stage (as opposed to conventional X-linked fluid) to reduce the net pressure developed during the fracturing treatment• low-viscosity viscoelastic surfactant fluid treatment. Modeling Approach Until recently, the hydraulic fracturing simulation model was based on a conventional set of logs (GR, SP, NKT, GZ, PZ, etc,) and the gut feeling of the engineer. Over time, we learned that such an approach can lead to an inadequate model that could overpredict the strength of the lower barrier and result in fracture breakthrough to the water zone (current breakthrough rate in the new pads is 32% based on 50% WC cut off, Fig.1). To address this issue, the advanced acoustic logging of VK formation in Kamennoe field was done by running DSI log in one well and waveform sonic logs in six other wells. Formation mechanical properties as established from acoustic logs, have been associated with lithofacies, based on the conventional set of logs and extrapolated throughout the field for further usage in simulation modeling. Fig.1 - Post-frac performance based on the conventional modeling approach approach, the advanced planar 3D hydraulic fracturing simulation was performed for the wells that showed no breakthrough based on conventional model (Fig.2), but that have been put on production with the postfracturing WC>50 % (Table 1). Table 1 - Production parameters of the well that did not show any breakthrough to VK-2 according to the conventional model. Fig.2 - Conventional model for the well 5485 does not show breakthrough to VK-2. Fig.3 - Planar3D model shows breakthrough. The fracture geometry obtained from the planar 3D model has been aligned with the postfracturing production results (Fig. 3). Second, the input for the conventional simulation was adjusted accordingly and the conventional model was put in agreement with the advanced model and postfracturing production results (Fig.4). Fig.4 - Conventional model aligned with the planar 3D simulation, and production results showing breakthrough. Third, the modified input for the conventional simulation is now being used routinely to model new fracturing jobs. Results As a result, the process developed on the basis of this study shows improvement in both geometry prediction accuracy and postfracturing water cut (Fig.5). Fig.5 - Post-frac performance based on the new modeling approach Conclusion Production water cut is one of the most important economic parameters of the Kamennoe field development project because of water lifting/handling cost in the environmentally sensitive area. The current study showed that the risk of breakthrough to waterbearing formations can be reduced by using advanced acoustic logging and fracturing simulation technologies in the high-profile development project. Acknowledgements Authors would like to thank TNK-BP and Schlumberger for permission to publish the paper and for continuous cooperation and knowledge sharing.