The paper focuses on the simulation case study of smart technologies for horizontal wells for the development of thin oil rims in the center of Russian gas condensate production.Operating companies worldwide are turning to intelligent completions to mitigate the consequences of uneven drawdown and reservoir heterogeneity along the wellbore. The proposed enhancements have proved its applicability to increase oil-part profitability of the highly productive formations offshore Africa and the North Sea. Following recent completion advances, the oil rims common in the Yamal region of Russia could be good candidates to be smart instead traditional well interventions which may be more costly or ineffective.We describe a systematic workflow that can be used to evaluate the viability of such technologies, specifically in thin oil rims. The intent then is to improve oil recovery at the simultaneous production from oil and gas zones. We analyze a number of horizontal well completion designs with stingers and ICV by means of simulation models. The models consist of a multisegment well option from a commercial software program. The ICV simulation, compared with models of conventional reduced well designs, predicted an additional 2-3% of oil recovery over 10 years. Additionally, it also indicates CAPEX would be 5-7 times more and operating risks are much greater. Summarizing, the results showed current limitations and effects of each smart solution but also forced us to consider production on the supercritical gas rate modes: naturally flowing production with gas breakthroughs controlled at the wellhead. Finally, the economic and risk screening criteria are introduced pointing to the optimum recommendations for development decisions.

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.

Development of oil, gas and condensate fields assumes simultaneous production of both free gas with condensate and oil with breakthrough gas. In this case, infrastructure solutions must be flexible and maximally fit for purposes of collection and treatment of all produced fluids. Joint planning of field development and infrastructure arrangement takes on a great importance as it is necessary to align solving of subsurface hydrodynamics, transportation of products in wellbore and collection system problems. A great number of producer companies throughout the world use the "Formation-Well-Surface Infrastructure" integrated models for planning of development and infrastructure arrangement which allow forecasting the performance factors with a high degree of accuracy covering not only field development and geological aspects but the limitations of the surface infrastructure, including pipelines, areal facilities and economic conditions. The most important task of the integrated modeling is the correct forecast and optimization of performance factors with account for all existing limitations of reservoir, well design, downhole equipment, products collection and treatment system. This article considers the existing "Formation-Well-Surface Infrastructure" model of one of the multipay oil, gas and condensate fields of the Western Siberia. Description of the integrated model development stages is given which includes a creation of digital models of oil and gas wells with complex completion systems, models of collection systems for all products and a reservoir simulation model of the field. Examples of a solution of application tasks for optimization using the generated integrated model are given which allow significantly improving quality of the adopted solutions by covering of all production system components "from reservoir to collection and transportation of hydrocarbons" integrated into a single model.

Recovery of tight oil reserves related to thin under-gas rims complicated by a presence of bottom water represents a crucial task for a huge number of operators throughout the world. The main problem of development of such reserves are represented by almost inevitable processes of gas and water coning leading to gas and water breakthrough to the bottom of producing wells which in its turn affects process and economic performance indicators of development and prevents reaching high oil recovery factor (ORF) values. This article represents an efficient approach to recovery of tight oil reserves related to thin under-gas rims with bottom water providing for the use of multipurpose wells with complex design allowing efficiently using the gas cap energy and managing the risks related to water coning.

The paper highlights the importance of adequate characterization of capillary pressure effects when preparing a development plan for a greenfield gas condensate reservoir with a large transition zone (TZ).Capillary pressure data from centrifuge or porous plate (semi-permeable membrane) are used to characterise the transition zone. It is essential that a representative set of sample measurements is obtained. Core laboratories are not capable to keep initial pressure-temperature conditions during capillary pressure measurements. Hence, the conversion from surface to reservoir becomes uncertain. Conversion utilizes interfacial tension and wettability angle which are quite unknown and can be predicted using different P-T charts. Finally saturation model depends on the way of: characterization -discrete Rock Types (RT) or tuned-up Continuous Functions (Leverett, Amaefule etc.); matching log saturation profile with the one observed in the model; welltest playback in terms of mobile water and drained volumes.In this study, the authors present a systematic workflow on how capillary pressure should be incorporated in a dynamic simulation model pointing out example pitfalls and giving validation tips. The illustrated case shows that if one of the steps is missed or wrong assumptions are made, then the TZ and the production potential will be incorrect. In our example, the discretization of connate water saturation and capillary pressure curves on early stages resulted to 8% underestimation of GIIP. Moreover, results indicated that uncertainty in conversion of capillary curves (from surface to reservoir) gives 15-20% differences in outcomes (depending on development scenario). Also it demonstrates a strong impact on the length of production plateau, rate of wellhead pressure decline, compression start-up which are vital aspects for the development concept, especially during front-end-loading stage of the project plan. We feel that the procedures presented here (both for engineers and management) can serve as a guide for QC and possible failures when they are not applied.