Formations with a bottomhole static temperature below 70 degC are very common for quite a number of Russian oil provences such as Komi, Samara Area, Orenburg, Tatarstan Bashkiria, and Eastern Siberia. Many of these formations are now being developed with proppant fracturing which incorporates a lot of flow back issues due to the various reasons including high viscosity oil, aggressive TSO designs and cycle loads on a proppant pack due to ESP change regime. There are a number of solutions to prevent proppant flow back and the most common one is usage of resin-coated proppants. At temperatures below 70degC RCP needs chemical activation in order to achieve a solid proppant pack consolidation. Depending on temperature range and coating structure various types of activators can be used. Traditionally commercial activators were used at very high concentrations that may compromise proppant pack conductivity and performance fracturing fluid. Alternative techniques are based on using fiber technologies and unconventionally shaped proppants.The majority of flowback control techniques have been tested in Volga-Urals region of Russia, Orenburg, Samara and Bashkiria areas. Novel additives that accelerate curing, RCP was successfully implemented and pumped during hydraulic fracturing on the most oil fields of Samara area. Flow back problems were observed only at extremely low temperature reservoir (Ͻ30 degrees Celcius) with highviscous (ϳ100ϩ cP) oil. Paper uncovers the details of activation process with detailed laboratory investigation for several RCPs and activators, proposes decision matrix for low temperature flow back control techniques, its applicability and design. Problem: Proppant Flow backProppant flow back is the term used to describe the problem of proppant being produced out of a hydraulically created fracture during well cleanup or reservoir production. This phenomenon can create several problems. Once removed from the fracture, proppant cannot contribute to fracture conductivity or reservoir production, moreover, productivity of the remaining fracture is severely affected. Proppant flowing back from the fracture may cause mechanical problems with downhole equipment, especially for the wells equipped with an electrical submersible pump (ESP).
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.
The Volga-Urals basin is one of the largest oil-producing regions in western Russia. The most prolific wells are producing from Devonian formations characterized by light crude oil with high bubblepoint pressure. Today, most of the Devonian reservoirs are depleted and produce at bottomhole flowing pressure below bubblepoint pressure, which yields multiphase and non-Darcy flow in hydraulic fractures, drastically decreasing production. As a result, conventional hydraulic fracturing treatments are less effective. To regain fracturing treatment efficiency, the restrictions to hydrocarbon flow inside the fracture must be minimized. To account for this, a new method of fracture conductivity generation was introduced. Channel fracturing creates open pathways inside the fracture, enabling infinite fracture conductivity. Channels are created by discontinuous proppant feeding at surface into viscous fracturing fluid. Dissolvable fibers are added to the slurry to separate proppant structures and prevent them from settling during treatment. Proppant structures act as bridges inside fractures; voids between them are essentially stable channels connected along the entire length of the fracture. While channel fracturing has already been implemented successfully in many places around the world, the fracturing conditions of Volga-Urals Devonian formations were still new for this technology. The Volga-Urals region is well known for high tectonic stresses and low fracturing-fluid efficiency. While channel fracturing treatments are being designed and pumped in a regime without tip-screenout (TSO) in other locations, channel fracturing treatments in Devonian formations often showed significant TSO. Production analyses showed consistent productivity increases, and in most cases, 2 folds higher compared with offset wells where conventional fracturing technology was used. After the success of the pilot campaign, proppant flowback was resolved by incorporating a rod-shaped proppant as a tail-in stage of channel fracturing schedules. The nonspherical shape of the proppant increases internal friction between the particles and mechanically holds them in place. In addition to improving proppant flowback control, the combination of technologies maximized conductivity of the near-wellbore area which connects channels and the wellbore. The success of more than 30 of such fracturing treatments expanded the pool of candidates for channel fracturing with rod-shaped proppant to meet the challenges of similar complex geological conditions.
Hydraulic fracturing de-facto is the most common stimulation technique that is employed worldwide. Russia is following the same trend and most of the new and old wells are considered for hydraulic fracturing. However, eventually as more and more reservoirs become depleted operators are looking forward to formations with so called "hard-to-recover" deposits in order to sustain hydrocarbon production.These "hard-to-recover" deposits include:• Unconventional shale pays similar to US -Bazhenov and Domanik formations.• Caspian, Arctic, and Sakhalin offshore • Eastern Siberia green fields • Mature fields and formations where conventional stimulation is not as effective as expected due to variety of reasons.
In the last two decades, hydraulic fracturing has become a routine completion practice in most oilfields producing from the low- and medium-permeability Jurassic formations in western Siberia. To optimize hydraulic fracture conductivity, operators and service companies were progressively decreasing polymer loading in fracturing fluids, developing new polymer-free fluids, implementing foams as fracturing fluids, increasing proppant size and concentration, enhancing polymer breaker performance, increasing breaker concentration, and implementing the tip screenout technique. All these methods have some positive impact on proppant pack conductivity but lead to higher risk of premature screenout. The intrinsic limitations stem from the fact that conductivity is created by the proppant pack, which physically limits permeability. The new channel fracturing technique allows development of an open network of flow channels within the proppant pack; thus, the fracture conductivity is enabled by such channels rather than by flow through the pores between proppant grains in the proppant pack. The channel fracturing technique is capable of increasing fracture conductivity by up to two orders of magnitude. Talinskoe field, located near Nyagan, Russia, produces from a series of Jurassic sublayers at depths of 2270 to 2700 m. Several oil-saturated sandstone sublayers are separated by shale barriers, and their development is conducted separately. For some wells, production from bottom sublayers JK10 and JK11 became uneconomical due to injection water breakthrough or low liquid rates. Production in these wells was switched to upper layers JK2 through JK9 after perforation and stimulation operations. Five of these wells were stimulated with the channel fracturing technique. Six-month of post-frac production data were compared with production data from eight offset wells stimulated recently via conventional hydraulic fracturing. The wells stimulated with the channel fracturing technology showed an average productivity index about 51% higher. This production effect still remains positive. The absence of screenouts confirmed reliability in proppant placement observed in other projects worldwide. The successful implementation of the channel fracturing technique in brownfield development is described in detail with a theoretical and operational review, results from laboratory experiments, and analysis of the production results in comparison with conventional fracturing.
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