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Platunov, A.. (OJSC Rosneft Oil Company) | Martynov, M.. (OJSC Rosneft Oil Company) | Nikolaev, M.. (OJSC Rosneft Oil Company) | Leskin, F.. (OJSC Rosneft Oil Company) | Davidenko, I.. (OJSC Rosneft Oil Company)
Abstract This paper is based on study of formations in Bazhenov and Tyumenskoe horizons of Em-Yoga field Krasnoleninsky arch West Siberia with the aim of defining the geomechanical concepts of studied area. Hydrocarbon production from Bazhenov and Tyumenskoe formations in West Siberia is actually established through number of pilot wells with production testing. Economic profitability of producing wells depends on the efficiency of hydraulic fracturing in cases where the technology is predefined by reservoir development project. This article describes the principles and prerequisites of hydraulic fracturing mechanics under geomechanical conditions of the studied rocks. Tyumenskoe and Bazhenov formations are dated to Upper and Middle Jurassic geological time. Geological depositional environment and posterior transformations in time have created specific conditions for rock geomechanics. Rock mechanics in studied formations practically predetermines the concept of how rock is fractured. This work presumes basis for typification and description of fractures occurred naturally and created as a result of hydraulic fracturing and how those interfere with each other. This work is stand on the accumulated results of the ongoing study and actual data from producing wells in Em-Yoga field Krasnoleninsky arch West Siberia. The Jurassic rocks studied in this article are stratigraphically divided into formations of Tyumenskoe, Abalak and Bazhenov horizons. Enacted stratigraphic cross-sectional classification describes the formations of Tyumenskoe horizon as porous rock, Abalak horizon as cavernous-porous naturally fractured and Bazhenov as naturally fractured and micro-porous types of rock.
Kayumov, Rifat (Schlumberger) | Klyubin, Artem (Schlumberger) | Yudin, Alexey (Schlumberger) | Enkababian, Philippe (Schlumberger) | Leskin, Fedor (TNK-BP) | Davidenko, Igor (TNK-BP) | Kaluder, Zdenko (TNK-BP)
Abstract 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.
Parkhonyuk, Sergey (Schlumberger Oleg Sosenko) | Levanyuk, Olesya (Schlumberger Oleg Sosenko) | Oparin, Maxim (Schlumberger Oleg Sosenko) | Sadykov, Almaz (Schlumberger Oleg Sosenko) | Mullen, Kevin (Schlumberger Oleg Sosenko) | Lungwitz, Bernhard (Schlumberger Oleg Sosenko) | Enkababian, Philippe (Schlumberger Oleg Sosenko) | Mauth, Kevin (Schlumberger Oleg Sosenko) | Alexander, Karpukhin (TNK-BP.)
Abstract Excess water production is a major concern for Russian oil companies. Maturing fields are producing at ever-increasing water cut resulting in problems such as the cost of disposal and environmental issues. In recent years, operators have shown a rising interest in Relative Permeability Modifiers (RPMs) as a potential solution to reduce water production. RPMs are designed to disproportionately reduce the relative permeability to one phase (water) over the oil phase. RPMs are a preventive approach to reduce water production. Ideally, they should completely block water flow without affecting oil flow. While RPMs are used worldwide, they must be adjusted to the reservoir conditions. This becomes even more important in the case of hydraulic fracturing of formations with nearby water-saturated layers. Commonly, service companies recommend one type of RPM which fits all reservoirs. This paper demonstrates how RPM selection on reservoir cores is critical for successful application in the field. We describe laboratory testing and review field trial results of RPMs in a low permeability (2 to 14 mD), highly laminated formation. Because RPMs are typically used only in high-permeability reservoirs, this application is unique. We evaluated chemically different RPMs on actual core material and found strong performance variations of the tested RPMs. We selected a suitable RPM following both core flow testing and compatibility testing. For the field test, wells in the Krasnoleninskoe oilfield were selected for RPM treatments. Oil production was increased in most cases while the water cut was reduced or only slightly increased by up to 5% during 6 months following the treatment. These results show that with proper evaluation, RPMs can also be successfully used in low-permeability reservoirs. We demonstrated also that otherwise proven successful RPMs may not fit every reservoir and proper evaluation and monitoring is critical for success.
Yakimov, S.. (TNK-BP) | Mukhametshin, M.. (TNK-BP) | Sosenko, O.. (TNK-BP) | Sadykov, A.. (Schlumberger) | Levanyuk, O.. (Schlumberger) | Oparin, M.. (Schlumberger) | Gromakovsky, D.. (Schlumberger) | Mullen, K.. (Schlumberger) | Lungwitz, B.. (Schlumberger) | Fu, D.. (Schlumberger) | Mauth, K.. (Schlumberger)
Abstract 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).