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 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.

The paper presents a methodology of hydrocarbon fuid composition calculation on the basis of gas and condensate profiles calculated in a black oil simulator. The methodology is based on the straight dependency of the condensate-gas factor (CGR) and the reservoir pressure (Pres). In order to determine a fluid composition a dependence function between a fraction of a hydrocarbon component and CGR is created using a PVT-simulator. Having a relationship between CGR and a hydrocarbon fraction a fluid composition can be calculated using the average CGR from black oil simulation results. This methodology gives a fraction of every individual component in comparison to composition modelling, where real components should be groupped in pseudocomponents. Proposed methodology assumes several constraints -the methodology should be applied just for gas condensate reservoirs without oil rims and the reservoir should be developed on depletion. In the work black oil and composition simulation results were compared. The paper can be useful for reservoir engineers working with gas condensates because it allows reducing simulation time without losing information about fluid composition.

The article presents the process and results of constructing a three-dimensional geomechanical model of an oil field located in the eastern edge of the Caspian basin. Oil and gas content is established in carbonate deposits of the Lower and Middle Carboniferous. The model was based on well log data, one-dimensional geomechanical models and a 3D geological model. The result of geomechanical modeling is the obtained property of additional permeability of the critically loaded discrete fracture network, which was later used in the history match of the hydrodynamic model. In addition to the fracture property, a series of conductive faults were also identified during the history match. When carrying out geomechanical modeling, international experience was taken into account in the calculation of critically loaded fractures and their relationship with the intervals of inflow and loss in carbonate reservoirs. The updated hydrodynamic model, taking into account the geomechanical model, significantly improved the convergence of the model and historical indicators of bottomhole pressures.