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Yurubcheno-Takhomskaya oil and gas accumulation zone (YTZ) located in the western part of the Siberian platform is known as a really challenging exploration object. The main reservoirs are located in Riphean carbonates made up of single p.u. porosity dolomites. Prospective drilling of the territory demonstrated high heterogeneity of this formation. Prospective wells drilled to this formation tests results vary from 0 to more than 600 m3 oil per day. The article describes efforts made on a new exploration approach elaboration based on an integral analysis of the structural, seismic and borehole data. First of all, this is seismic profiling on the regular orthogonal grid with the employment of modern seismic techniques and technologies, and also the study of the distribution of fractures in-situ (directly in the location of the deposition) with the integrated use of equipment and technology of formation micro-scanners and dipole sonic tools. This new approach consists on high-potential zone localization controlled by the disintegrated levee-like stromatolithic constructions, which are more exposed to fractured formation due to high silification in the southern and northern slopes of the Madrinskiy and Irkineevo-Katangskiy rifts respectively. Besides, highly productive may turn out to be the highly fractured streaks and sections, controlled by the regional and zonal fault zones. Such localization of the highly productive sections within the huge oil-and-gas-bearing territory allows hoping for the realization of the opportunity of the recovery of reserves of the entire region by limited number of high flowrate wells with the natural recovery drive. Introduction Yurubcheno-Takhomskaya oil and gas accumulation zone (YTZ), located in the western part of the Siberian platform (Fig.1), was identified in 1973 while drilling the Kuyumbinskaya parametric well (K-1), which discovered the accumulation of gas with daily flowrate of 200 thousand cubic meters under the clastic Vendian sediments in the carbonate depositions of the Riphean. The following exploration effort identified the extensive oil and gas accumulation zone with the total square of 20 000 km2, main reserves of which are associated with the Riphean depositions (from 0,8 to 1,1 billion years of age) and partially with the Vendian depositions (approximately 0.6 billion years old). The discovery of oil and gas presence in the rocks of such age in this region of the Siberian platform was a big surprise, since there were no preconditions for the formation of the HC deposits both in ancient times at that moment of time based upon the concepts of 1970es. As a result of the exploration effort taken in 1980-es the structural model of the pre-Vendian units of the YTZ was developed. It was deemed that the basis of the YTZ is constituted of main massive deposit, associated with a gigantic natural reservoir in the Riphean multiple-aged mostly dolomitic vugular-fractured reservoirs, covered by Vendian-Lower Paleozoic cap, saliferous in the Cambrian interval. The discovery of the accumulations of HC in the deep Riphean horizons and nonanticlinal deposits in the terrigenous deposits of the Vendian in the southern boundary of the zone was predicted. Nonetheless, technical capabilities of exploration at that time did not give the opportunity to meet the challenge of prospecting and exploration of that extremely geologically complicated block of resources, called since then the YTZ. This referred both to the capabilities of seismics, which could not differentiate some fine features of the geological cross-section under several trappean and saliferous caps in high-velocity cross-section, and to the borehole surveys of the high-resistivity carbonate mass of mostly fractured reservoirs of the Riphean age.

The maintenance of Western Siberia oil production levels has required the industry to evaluate and develop ever more complex reservoirs. In this case study we look at the evaluation of the heavy oil bearing field located in the north part of Western Siberia and specifically the unconsolidated Pokurskaya formation of the Cenomanian age. The specific evaluation requirements included an understanding of the oil properties, especially viscosity and its variations, and an understanding of recovery factor by an analysis of residual oil saturation. In order to accomplish these objectives an extensive suite of log data was acquired including standard triple combo data, cross-dipole acoustic, NMR, micro-images, spectroscopy and formation tester samples and pressures.In this paper we show how an innovative use of NMR data allowed us to improve the fluid model and irreducible water saturation calculations. Combining NMR with standard data allowed a prediction of the residual oil saturation. Additionally, from the NMR data we were also able to extract oil viscosity information, however we needed a calibration point and for that a formation oil sample was required.Unconsolidated formations saturated with viscous oils are notoriously difficult to sample with formation testers. Sand production can lead to contaminated samples, tool plugging and even borehole collapse. To avoid these issues we included dipole sonic data to estimate formation strength in order to select the optimal sampling locations. Additionally a new 'dual intake' straddle packer configuration was used to optimize the fluid sampling. As a result of these precautions samples were successfully acquired and the resulting PVT data was used in field development planning as well as calibration points for a continuous NMR-derived viscosity curve. Advanced logging suite for Pokurskaya formation studying PetrophysicsAs industry attention turns to ever more difficult and complex reservoirs to exploit the complexity of the attendant petrophysical interpretations increase. Case in point is the Pokurskaya formation of the Messoyakha field in the Yamalo-Nenets Autonomous Okrug. To date no integrated log-core data analysis has been performed on this formation due in part to poor core data/recovery and incomplete log data sets. In this paper we describe how we performed such a study accounting for complexities such as multiple clay and matrix components, sorting variations, variable fluid saturations and viscous oil. We divided out study into two phases, an elementary analysis of the mineral composition and a fluid model. The primary outputs of the elementary analysis (ELAN) is a total pore volume and a clay volume. By using geochemical log data from a neutron capture spectroscopy log (ECS*) it is possible to evaluate the mineralogical components, resolve the clay components and then refine the total porosity estimation. We note that the neutron capture spectroscopy measurements is independent of external information, a significant advantage in our case as we had no core data...

Carbonate reservoirs can exhibit heterogeneity in terms of porosity, permeability, fractures, vugs and wettability. This heterogeneity affects well performance, completion and reservoir management development decisions. Although extensive logs are run for the petrophysical evaluations in these formations, the use of advanced wireline formation testers (WFTs) can greatly aid in reservoir description. WFT not only can identify hydrocarbon bearing formations but also plays a vital role in fracture characterization and calibration of fracture models. Advanced petrophysical logs were used to identify potential pay intervals, while high resolution image logs to delineate fractured zones and static fracture parameters, such as dip, azimuth and aperture. It has been shown that fracture dynamic properties, such as conductivity, can be quantified via pressure transient analysis using wireline formation tester in addition to fluid analysis. In this paper, WFT data was used to understand the pressure behavior of naturally fractured reservoir containing a network of discrete finite-conductivity fractures. The study presents results obtained from advanced logging suite that was run to characterize complex low porosity and low permeability carbonate reservoir where natural fractures provide primary pathways of fluid flow. Advanced wireline formation tester with straddle packer and fluid analyzer were used to test potential intervals. Two out of several intervals were enabled to flow, identifying mobile gas. The pressure transient response confirmed the complexity of reservoir and dominant contribution to flow regimes from fractures in these two intervals. Dynamic fracture properties were characterized through pressure transient analysis and were integrated into fracture model. On the other hand, flow could not be established in number of other intervals indicating tight matrix and no flow contribution from fractures, leading to calibration of geological models. The novelty of approach is the use of wireline formation tester not only to measure formation pressure and acquire downhole samples but to characterize dynamic fracture properties to calibrate fracture model.

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