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The Pashyian Regional stage (horizon) is the main productive unit of the middle Devonian clastic succession of the South Tatar arch. This article presents, for the first time, maps of the lower and upper parts of the Pashyian, including data on sand-shale ratio, number of sand layers (reservoirs) and thickness, based on the analysis of logging data from 25,000 wells. The maps were created by spatial interpolation of Natural Neighbor and ArcGIS Pro software. The model of sedimentation of the Pashyian Regional stage reflects the interpretation of the plotted maps as well as the synthesis of the results of detailed core investigations (lithological, sedimentological, ichnotextural, petrophysical, etc.) and analysis of archive and published materials. The main points of the proposed model are as follows. The Pashyian sediments were formed in a marine basin, in an environment comparable to that of the middle shelf of modern seas – in an offshore zone dominated by current activity. The basin floor was a relatively flat plateau, on which sandy, silty and clay sediments were simultaneously accumulated. Sediments of all types accumulated during sea transgression. Sea regression caused erosion and destruction of the already formed sediments. Positive landforms of seabed relief, composed predominantly of sandy well-sorted material, comprised autochthonous underwater sand bars, formed by constant currents parallel to the bathymetric contour of the seabed. Underwater sand bars formed extensive systems nearly throughout the entire territory of the modern South Tatar arch. At the same time, allochthonous, poorly sorted, less mature sediments were formed in underwater troughs produced by transversal currents (directed from the shore towards the sea). The proposed model explains the consistent thickness of the Pashyian Regional stage, the mosaic distribution of sand bodies over the area, and the lens-like shape of the sand and siltstone reservoirs. The model can be extrapolated to other stratigraphic intervals of the Devonian clastic succession with similar sedimentological features.

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The paper presents a practical case of production performance analysis at one of the mature waterflood oil fields located at the Volga-Ural oil basin with a large number of wells. It is a big challenge to analyse such a large production history and requires a systematic approach. The main production complication is quite common for mature waterflood projects and includes non-uniform sweep, complicated by thief injection and thief water production. The main challenge is to locate the misperforming wells and address their complications. With the particular asset, the conventional single production analysis techniques (oil production trend, watercut trend, reservoir and bottom-hole pressure trend, productivity trend, conventional pressure build-up surveys and production logging) in the vast majority of cases were not capable of qualifying the well performance and assessing of remaining reserves status. The performance analysis of such an asset should be enhanced with new diagnostic tools and modern methods of data integration. The current study has made a choice in favor of using a PRIME analysis which is multi-parametric analytical workflow based on a set of conventional and non-conventional diagnostic metrics. The most effective diagnostics in this study have happened to be those are based on 3D dynamic micro-models, which are auto-generated from the reservoir data logs. PRIME also provided useful insights on well performance, formation properties and the current conditions of drained reserves which helped to select the candidates for infill drilling, pressure maintenance, workovers, production target adjustments and additional surveillance. The paper illustrates the entire PRIME workflow, starting from the top-level field data analysis, all the way to generating a summary table containing well diagnostics, justifications and recommendations.