|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Summary The cost-effective development of low-permeability hydrocarbon formations of small thickness requires horizontal wells with multi-stage hydraulic fracturing (MS-Frac). The presence of higher or lower layers that are water-saturated and weak barriers to height growth imposes a restriction on the desirable geometry of the fracture to prevent a breakthrough into a flooded interval. Combining several methods of fracture height restriction and controlling such height can improve the efficiency of multi-stage hydraulic fracturing. The first technology to control the effective pressure was based on changing fracturing fluid rheology and resulted in a decrease in the net pressure and the fracture height. The main treatment buffer utilized a hybrid fluid design. The second technology used to limit the height of the fracture was based on creating artificial barriers inside the fracture that restrict height growth. In this case, a special mixture of proppants was pumped before the primary proppant-laden fracturing main stage. The construction of a horizontal well with a multizone completion implies the possibility of carrying out small volume multistage fracturing to prevent breakthrough into a water-saturated interval, creating an effective drainage zone. For the first time in the given field, MS-Frac was performed using combined technologies and techniques for fracture height growth restriction. The operations demonstrated successful results of horizontal multizone well treatments, where the rheology and fluid rate control methods were used to restrict the fracture geometry growth, and proppant slugs were used to create artificial barriers to arrest the fracture height growth.
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.
Martinov, M E (TNK-Nyagan) | Kozlov, A V (TNK-Nyagan) | Leskin, F Y (TNK-Nyagan) | Filimonov, A Y (Schlumberger) | Ezersky, D M (Schlumberger) | Egorov, S S (Schlumberger) | Blinov, V A (Schlumberger) | Weinheber, P.. (Schlumberger)
Abstract The Vikulovskaya formation of Western Siberia is characterized by thinly-bedded, sand-shale layers. The vertical thickness of these layers ranges from a few millimeters to a few centimeters. This layered feature presents well known challenges for petrophysical analysis from standard logging suite data. These layers are typically beyond the vertical resolution of the standard tools so net-to-gross cannot be derived directly. The shale layers suppress the resistivity readings in the oil strata and the resulting low resistivity contrast makes it difficult to determine the oil-water contact. Finally, the ability to resolve the individual sand layers makes it impossible to accurately determine their water saturation. In this paper we discuss how these challenges were surmounted when performing a petrophysical evaluation of a dataset acquired in a recently drilled well in the Krasnoleninskoe field. This dataset consisted of full bore core and traditional ‘triple combo’ data. Additionally, we had NMR data, high resolution micro-imager data and formation tester pressure and fluid analysis data. By combining the measurements from the traditional tools with the resolution of the micro-imager data we were able estimate the desired petrophysical properties of the thinly-bedded layers individually. By using tools with different physics we were able to realize an independent quality control of the interpretation: stationary NMR measurements were used as porosity and irreducible water saturation reference, and formation tester data of direct inflow composition were used as a reference for fluid saturations. As a final check on our method we performed a digital integration of core and micro-imager data to validate our findings. The resultant workflow is concisely explained such that it can be easily applied to similar evaluation environments.
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.
Martinov, M.E. (TNK-Nyagan) | Kozlov, A.V. (TNK-Nyagan) | Leskin, F.Y. (TNK-Nyagan) | Filimonov, A.Y. (Schlumberger) | Ezersky, D.M. (Schlumberger) | Egorov, S.S. (Schlumberger) | Blinov, V.A. (Schlumberger) | Weinheber, P. (Schlumberger)
The pdf file of this paper is in Russian. To purchase the paper in English, order SPE-166831-MS.
The Vikulovskaya formation of Western Siberia is characterized by thinly-bedded, sand-shale layers. The vertical thickness of these layers ranges from a few millimeters to a few centimeters. This layered feature presents well known challenges for petrophysical analysis from standard logging suite data. These layers are typically beyond the vertical resolution of the standard tools so net-to-gross cannot be derived directly. The shale layers suppress the resistivity readings in the oil strata and the resulting low resistivity contrast makes it difficult to determine the oil-water contact. Finally, the ability to resolve the individual sand layers makes it impossible to accurately determine their water saturation.
In this paper we discuss how these challenges were surmounted when performing a petrophysical evaluation of a dataset acquired in a recently drilled well in the Krasnoleninskoe field. This dataset consisted of full bore core and traditional ‘triple combo' data. Additionally, we had NMR data, high resolution micro-imager data and formation tester pressure and fluid analysis data. By combining the measurements from the traditional tools with the resolution of the micro-imager data we were able estimate the desired petrophysical properties of the thinly-bedded layers individually. By using tools with different physics we were able to realize an independent quality control of the interpretation: stationary NMR measurements were used as porosity and irreducible water saturation reference, and formation tester data of direct inflow composition were used as a reference for fluid saturations. As a final check on our method we performed a digital integration of core and micro-imager data to validate our findings. The resultant workflow is concisely explained such that it can be easily applied to similar evaluation environments.
Abstract Slugs-fracs is one of new-to-field approaches which changed the conditions of wells for fracturing increasing the number of candidates in Kamennoe field Western Siberia. Placing fracturing jobs by slugs of proppant pumped in linear gel successfully implemented in stimulating pay zones in near water intervals with small stress contrast between zones and barriers. A few technical specifics had been used to contribute the success of this methodology such as earlier pumping with near matrix rate to allow more fluid filtration ahead of the main proppant stages before fracture is fully formed. Proppant setting according to Stokes law and dune effects theory were evaluated and considered for design strategy. The slugs-fracs allowed pumping regardless of the wellbore deviation and height of perforated intervals. Post-fracturing results from 120 wells were used for analysis. Significant decrease in initial water cut and sustainable oil production were reported. First slugs-fracs were introduced in the beginning of 2010 and in following 2 years more than 200 hundreds jobs have been pumped across the field. This allowed to drill spots of the field that were previously suspended as result of ineffective fracturing treatments mostly due to high risk of fracture breaking down the water zones.
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.