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The Tyumen formation is the main hydrocarbon-saturated layer of the Krasnoleninskoe oil and gas condensate field located in Western Siberia. This formation is characterized by significantly changing structural dips and represented as thin, interbedded shale and sandstone layers. Such a formation structure complicates the real-time evaluation of formation properties, well correlation and proper well placement. This paper presents the results of horizontal well drilling at the Krasnoleninskoe field using advanced resistivity logging technology.
Advanced resistivity logging technology is used in field operations for various applications. This technology includes logging-while-drilling (LWD), a deep-azimuthal resistivity tool, and sophisticated data interpretation software. The tool performs multi-component, multi-spacing and multi-frequency measurements downhole. The measurement set can be configured individually for each particular geology and application type to ensure effective operations. Next, these measurements are transmitted to the surface, where high-performance multi-parametric inversion recovers formation parameters of interest in real-time. The inversion software enables the processing of any combination of tool measurements and is based on a 1D layer-cake model with an arbitrary number of layers to operate with complex multi-layer formations.
Besides the complex laminated structure of the Tyumen formation, an additional challenge is the low resistivity contrast between the shale and sandstone interlayers. This factor is typical for many West-Siberian fields; it complicates the resolution of interlayers and degrades the evaluation accuracy of their parameters.
To overcome these challenges, a set of deep-azimuthal resistivity tool measurements, suitable to resolve thinly laminated formations, was identified and transmitted uphole while drilling. Real-time inversion was performed in a user-controlled mode to ensure the careful tracking of geology changes. These results enabled operational geologists to monitor the formation properties during the drilling.
Data inversion software ensured the accurate evaluation of formation properties and structural dips estimation in complex conditions of the Krasnoleninskoe field. Structural dips recovered by inversion significantly differed from values observed at offset wells, i.e., 5 to 12 degrees, instead of 0 to 2 degrees. A perfect match between the measured and synthetic resistivity data confirmed high confidence of inversion results. Moreover, there was a strong correlation between the structural dip angles estimated from resistivity data and derived from LWD natural gamma-ray (GR) image. Many of shale and sandstone layers observed in the GR curves were resolved by resistivity inversion.
The depth of the remote layer detection was estimated during the job; it enabled geoscientists to delineate the reservoir volume that contributed to the tool measurements.
This case study describes the first application of advanced resistivity logging technology in a complex laminated formation of the Krasnoleninskoe field. This technology enables the resolution of thin interlayers, evaluation of their properties and estimation of structural dips in real time. These parameters are important for proper well placement and accurate petrophysical interpretation. The presented technology is able to increase the efficiency of oil recovery in the complex laminated formations of the Russian West-Siberian fields.
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.
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).