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This paper describes a methodology for waterflooding pattern optimization based on multi-criteria analysis of the interaction between producers and injectors. This method takes advantage on the use of streamlines which are generated from the post-processing of finite difference simulation results to define the flow paths between injectors and producers and characterize flow allocation between interacting wells. This information is then combined with well production/injection data (oil / water rates, pressures etc.) to calculate parameters like compensation ratio and injection efficiency for each well. Having all this information, a set of cross-plots is used to rank the producers and injectors by their sweep / drainage efficiency. The results of such analysis allows the planning of workovers, optimization and allocation of the volumes of injected water and ultimately enables a comparative assessment of the efficiency of each individual workover event in terms of incremental oil production, water-cut reduction and decrease in non-effective water injection. One of the advantages of this method is the use of already available results from finite difference simulation. This fact dramatically increases the time available for the waterflood optimization process and significantly widen the range of scenarios where streamlines technologies can be applied. Moreover, this approach does not require significant or time-consuming computational efforts, which make it a very convenient decision-making tool for field operations planning.

The tendency of recent years in the sphere of modeling oil and gas fields and the processes of oil and gas fields' development is an increase of complication of models, revision and abandonment of a number of simplifications, which were necessary earlier due to the limited computing and time resources available to engineers. This tendency makes more widespread such approach as accounting for the performance and optimization of surface gathering systems becomes a critical task in the case of gas, gas condensate fields, and also - light oil fields. Given the apparent growth in the interest of oil and gas companies in such assets, the popularity of integrated modeling in the industry as a whole is extremely high. The problem with this technology is that the integrated simulation models are complex in the creation, they require more knowledge from the engineers involved in the project in the related field of activity (the reservoir engineer should have an idea of the principles of operation and methods of managing the surface network, production engineer should understand the physical basis of the work not only of the reservoir, but also of its simulation model, etc.). Both the network model and the reservoir model can be performed in different variants in terms of the complexity and accuracy of the transfer of the boundary conditions and taking into account the necessary physical effects. This article offers a comparative analysis and possible applications of different types of models, and also describes a number of additional tools that help to eliminate some typical problems of this class of tasks.

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One of the main aspects that is worth paying attention to when planning the development of gas-condensate (GC) fields is accounting for and reproducing gas-liquid phase transitions that affect the flow of hydrocarbons (HC) in the reservoir as well as gas and condensate production indicators during the entire life cycle of the field. Undoubtedly, this effect will be more significant for cases with a complex gas component composition, high condensate content, as well as under conditions of low reservoir formation permeability and a high degree of areal and vertical heterogeneity. Compositional hydrodynamic modeling is a comprehensive tool for assessing hydrocarbon production capabilities, taking into account the phase behavior for GC field. The purpose of this work is to compare the various methods of improving the accuracy of numerical simulations and the reliability of the hydrodynamic modeling results for this type of reservoirs. Using a high-resolution hydrodynamic simulator and a high-performance cluster system, multivariate simulations were performed to evaluate the effect of various parameters and options on the results of numerical simulations. The simulations were carried out using a compositional model, which is an analogue of a gas-condensate fields in Western Siberia within Yamalo-Nenetsky Autonomous Okrug (YNAO), based on geology, PVT and core, production history and well test data for vertical and subhorizontal wells, accounting for the presence of hydraulic fracturing. The work started with a detailed study of the challenge while the GC systems modeling on local sectors with further transition to a larger scale models using the results obtained on the previous step, taking into account their cross-validation. Based on the results of the work, several important decisions (observations) were made, allowing determining the potential limits and the technical capability of modeling the GC systems with the required accuracy of phase transitions. In addition, the degree of influence if the numerical grid resolution and detalization of the PVT model (up to 50 components inclusive) on the gas and oil production and the pressure behavior was estimated. The simulation run time with various numerical schemes were also considered as factors affecting the simulation results on the sector and full-scale models. The analysis carried out and the results obtained can be further used by engineers dealing with GC field development as a guideline for choosing the modeling method depending on the complexity of the task and available computational resources.