Using advanced logging methods combining NMR and spectroscopy an Oil Saturation Index (OSI) is computed that correlates well with the productive layers of the Bazhenov formation. This article describes a method of estimating the OSI from log data, proposes a model for log interpretation in the Bazhenov Formation sediments and compares the results to core analysis. We present results from three wells.
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.
The determination of saturation and therefore fluid contacts can be challenging in certain low permeability reservoirs of the Yamal peninsula. The low water salinity and high shale content make contact determination with traditional petrophysical methods difficult. The low permeability also complicates contact determination using pressure gradient analysis. Downhole fluid analysis seems a logical choice, but it too is fraught with difficulties in low perm, near saturated reservoirs.In this paper we show how to apply DFA for contact determination and how to mitigate, by interpretation and hardware configuration, the various challenges. Additionally we investigate the quality of the obtained samples with respect to their suitability for PVT studies.
In a recent Em-Egovskoe well an extended logging suite was performed with the aim to evaluate the petrophysical properties of Jurassic and Paleozoic formations as well as to improve the structural geological model of this part of the oilfield and to do detailed characterization of the dynamic model by desired properties of formations and fluids. Apart from a standard "triple combo" logging suite the following advanced technologies were applied in the well: neutron-gamma spectroscopy, nuclear magnetic resonance, formation micro imager, formation testers in different modes of reservoir and fluid properties evaluation. Noteworthy, the zone of interest was considered to contain only oil-saturated reservoirs – no gas cap was expected. Indeed on the initial triple combo log data there were no routine gas attributes were observed. Gas-saturated reservoirs were only observed based on integrated analysis of standard and advanced log data, particularly, nuclear magnetic resonance and cross-dipole sonic measurements. Gas-saturated intervals were fully proven by formation tester using downhole fluid analysis (DFA) As a result, one of the Jurassic layers was acknowledged as gas/gas-condensate saturated down to the bottom and the rest of Jurassic intervals were found to be oil saturated.
The Abalak formation was also encountered in this well and evaluated. Thin carbonate streaks were identified with the micro-imager and were tested with the dual-packer module of the wireline formation tester. The result was the first ever Abalak oil sample in this field. Furthermore, based on pressure transient analysis of the build-up from the pressure test it was suggested that these tight streaks are laterally discontinuous.
Finally, we created a stress profile in the Jurassic and Paleozoic layers. Based on formation micro-imager and acoustic scanning measurements the maximum horizontal stress directions and magnitudes were estimated. Then dual-packer formation tester micro-stress measurements were made to acquire direct measurements of fracture closure pressure. These measurements were used to calibrate our stress model.
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