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Successful hydraulic fracturing in various "risky" oil reservoirs has been the biggest challenge for fracturing engineers in the Western Siberia basin, as a significant number of the oil-bearing formations in the basin are located near a water zone. These hydraulic fracturing difficulties created a niche for technologies that offer fracture-geometry control without sacrificing proppant-pack conductivity. The conventional approach is based on net pressure control. This can be achieved using low-viscosity fluids, such as viscoelastic systems, oil-based systems or reduced polymer systems. The fluid systems can then further be pumped as linear gel pad stages with cross-linked proppant stages with or without the use of materials for fracture height-growth control (HGC). The Yaraynerskoe oilfield case study documents the fiber assisted fracturing fluid technology used with HGC materials as a significant improvement in HGC solution. This technology combination additionally enhances fracture placement success. As the treatments significantly differ from the regular fiber assisted application in tight gas formations, a series of experiments had to be performed to ensure full compatibility with formation fluid, resin-coated proppants, and treating fluids. Characteristics such as leakoff behavior, viscosity development, settling rate for large-sized proppants, and fiber degradation in static and dynamic conditions were determined in various laboratory tests. This engineering work allowed fiber based fluids technology to be extended to moderate permeable oil reservoirs (1-20 md) and relatively cool formations (76-95ºC), where fracturing treatments are regularly designed for tip-screenout treatments requiring fracture geometry control maximizing proppant pack permeability by increasing mesh size and proppant concentration. The first five treatments performed have pushed the limits of the technology in regard to proppant size, type, concentration, and fracture fluid gel loading. Combining this solution with the use of advanced HGC materials offers unprecedented results in regard to fracture-height containment, where positive net pressures were obtained the first time. These operational results were confirmed by production measurements where the average water cut is 50% lower compared to the conventional treatments. Increases in productivity allowed up to a 37% increase in oil flow rate.

This paper describes successful implementation of degradable fiber-laden fluids for hydraulic fracturing in one of the largest oilfield in Western Siberia. Placement advantage of fiber-assisted fluid already becomes obvious after initial campaign of four fracturing treatments. It demonstrated good proppant carrying capabilities and allowed decrease of polymer load without increasing risk of premature screenout. Fibers proved to be reliable for successful placement of 10/14-mesh size Intermediate Strength Proppants (ISP) at concentration up to 1000 kgPA and higher with only 3.0 kg/m3 (25lb/1000gal) guar polymer loading, a feat previously only achievable with 3.6–4.2 kg/m3 (30–35 lb/1000gal) gel loading in similar geological conditions. In addition to reducing damage with lower polymer concentrations, other advantages of degradable fiber usage were anticipated to be proven after proppant fractures geometries and production parameters (including PI and Jd) evaluation. Analyses of the fracturing treatments have been performed based on bottomhole pressure gauges data and well-supported with direct fracture geometry estimation obtained by using differential cased hole sonic anisotropy measurements. As it is common for most formations in Western Siberia to have high degree of lamination and multiple shaly layers inside producing zone, pilot well-candidates for the project were specifically selected to have complex geology including several layers of sandstones and shaly strikes. This requires the fracture to intersect layers of sandstone and provide optimum connection for hydrocarbons flow to the wellbore, by evenly distributing proppant throughout the height of the fracture. Thus, degradable fiber-assisted fluid must be utilized, as conventional fracturing fluids may not suspend proppant for required time period and proppant settling during fracture closure results in considerable part of net pay being under stimulated. The laboratory testing on large size ISP proppant suspension by degradable fiber in viscous fluids was performed for this project and described in the paper. Western Siberia field and degradable fiber-laden fluid provided a good example of how one solution may be applied for various challenges of hydraulic fracturing optimization. This research will present a comprehensive story supported by technical analyses. Introduction and Background Fibers, in various forms or compositions, have been utilized in the oilfield business for decades, whether to promote structural integrity of a cement system, and more recently to combat lost circulation issues, and to prevent proppant flowback in hydraulic fracture stimulation1. Most recently however, the scope of fiber application has vastly expanded, with additional benefits of degradable fiber-laden slurries being realized as application expands to new areas. Since 2000, fiber-laden slurries2 have been used to improve fracture geometry and enhance production from propped fracture treatments. These particular degradable fibers are continually gaining a favorable reputation worldwide as the technology has evolved and the scope of relevant well-types has expanded.

Hydraulic fracture azimuthal orientation depends on stress distribution in the formation and is considered to coincide with the maximal horizontal stress azimuth. The knowledge of the hydraulic fracture orientation is of critical importance in field development planning, including well spacing, pattern, water injectors location that will lead to desired line drive mechanism, optimized reservoir drainage and maximized recovery factor. That information is not less critical for infill drilling, fracturing «old» wells, re-fracturing, fracturing of sidetracks and the knowledge of hydraulic fracture orientation of the water injectors well that are fractured by the mere injection process. It is also known that re-fracturing and pore pressure re-distribution will re-orient the stress field not only in the near well bore area but also in the far field. Theoretical modeling and world experience suggest that the hydraulic fractures do re-orient under the influence of pore pressure changes because of fluid production and water injection. Field sector formation pressure distribution makes the fracture offset from maximal stress direction towards injection wells and this effect of local stress reorientation is more likely to occur in low permeable formations with low diffusivity and low stress orientation anisotropy. A number of complex fracture geometry orientation investigations were performed on low permeable formation of Siberia, to understand the phenomena. This included acoustic measurements and micro-seismic monitoring. Though the main purpose was to optimize fracture geometry by evaluating the measured and matching of modeled fracture parameters, the importance of fracture orientation for reservoir development was even more significant. The results undeniable indicate that a significant deviation of the field sector fracture azimuth from maximal regional stress exists. It was discovered that the degree of deviation from the regional preferred fracture azimuth is affected by water injection and reservoir fluid production in the sector of the monitored well. Observations regarding the effect of fracture wings length asymmetry may be also explained by the disturbance of initial stress conditions. The results of this investigation will be used to further optimize hydraulic fracture design, reservoir pressure maintenance including well spacing and well pattern and water flooding strategy. Introduction Hydraulic propped fracturing is considered a very conventional way to effectively stimulate oil and gas wells in low to mid permeability formations. The operators in Western Siberia in general and in particular Rosneft-Yuganskneftegas use hydraulic fracturing almost without exemption in all new wells as a conventional completion method. Additionally, initial and refracturing of wells with 10–15 year of production history, as well as fracturing of sidetracks and fracturing of infill drilled wells are a common practice nowadays. The oilfields are typically developed with an inverse nine or seven spot pattern and are under intensive pressure maintenance program. Well spacing is between 500–1000 meter in most oilfields and fracture lengths have been constantly increasing within the last few years. Moreover, it is also quite common that the ongoing water injection program is above the fracturing pressure, hence water injector wells under intensive and long injection schemes are subject to create long fractures as well. Many of the late wells are planned injector wells, or converted fractured producer wells that are accordingly fracture stimulated, therefore avoiding significant water bypass or overshooting of the water front between layers within the formation. The uneven injectivity is aggravated because of the strong waterflood inducing also thermally fracturing in vertical sweep of injection wells. In highly variable reservoir quality, injection water tends to be injected into the best zones. This promotes cooling, and the resulting thermally induced fracturing further enhances injection into these zones. This phenomenon is well known from the literature 1 and is in detrimental in formations of highly anisotropic transmissibility.

Problems related to inorganic scale precipitation are common in oil fields across Russia. The predominantly calcium carbonate scale rapidly precipitates from the produced water and causes reduction in reservoir permeability, restricts fluid flow in tubing and perforation, fails electric submersible and rod pumps, and plugs surface equipment. Local industry offers a number of inhibitors to prevent scale deposition. Although regular and planned injection of inhibitors into producing and injector wells is the most common method of scale precipitation prevention, no successful attempt to enhance scale prevention in conjunction with a stimulation treatment has been documented. This paper describes the first application of a combined scale inhibitor and hydraulic fracturing treatment in Western Siberia. It allowed the operator to place significant amount of scale inhibitor within the propped fracture and into the adjacent formation. The case history delineates the detailed sampling and pretreatment analysis of several oil fields with high-water-cut wells. In some of the fields, as many as 26% of the production wells experience scale-related problems. Up to 33% of electrical submersible pumps (ESP) failures are related to inorganic scales. Further, the candidate selection process provided ground for detailed lab testing to optimize the inhibitor type and volumes required for the first scale-inhibited hydraulic fracturing application in the Novogodnee field. The pilot project wells that were hydraulically fractured with the addition of scale inhibitor yielded a threefold increase in productivity and similar initial fluid production rates. The scale-inhibited wells did though provide sustained rates over a 3month monitoring period compared to rapid decline in production on the non-inhibited wells. At the same time, the wells treated with scale inhibitor have provided not only sustained production but also a fourfold reduction in operating cost, confirming the success of the pilot project.