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Frequently, production from gas and gas condensate wells is negatively impacted by the wellbore accumulation of liquid – a mixture of water and condensate. As reservoir pressure and tubing gas velocity decline and produced water cut increases, heavier liquids can no longer be effectively removed from the wellbore, resulting in the liquid column build-up at the bottomhole. This creates additional backpressure on the producing formation and leads to gradual production decline, until the well completely stops producing – the condition widely known as "liquid loading". Use of smaller size tubing (velocity string) is often the simplest and most straightforward solution, but depending on reservoir properties (water cut, productivity and pressure) and well completion (vertical, slanted or horizontal) this approach may not be efficient. This paper describes the technical approach to resume continuous production from liquid-loading gas condensate wells at North Urengoy field. It is shown that Electric Submersible Pumps (ESPs) can be successfully applied to unload horizontal wells producing large amounts of water. In this application, water and condensate is lifted by the pump through the tubing string, while gas and condensate mixture is simultaneously produced through the annular space between the tubing and the casing. Reviewed in detail are the technical challenges of modeling the well and pump performance using dynamic multiphase flow simulators, and the ESP design for the pilot application in deep, horizontal gas condensate well in Russia.

One of the most important challenges of the current stage of the field development is selection of concept of infrastructure system development and solution of classical problem of optimization: Minimization of capital expenditures for infrastructure development, Minimization of cost of production, treatment and intra-field transportation of the raw material to the LNG plant, Ensuring of high reliability of the entire infrastructure system for continuous flow of raw material to the LNG plant trains. Reaching of the field performance targets, namely: - Duration of the period of continuous gas production - Hydrocarbons recovery factors Besides, in designing of the infrastructure system and accordingly, in selection of the solution, it is necessary to take into account the following factors representing complexity of the future industrial activity in general: Geographical location of the field in the area with challenging climatic (arctic) conditions which calls for the necessity of maintaining of high level of self-sustainability in the field; Considerable differences in values of formation and accordingly, wellhead pressures of the production wells stock; Taking an optimal decision in part of concept of infrastructure development in these challenging conditions is possible only on the basis of the complex integrated digital model "Well - Reservoir - Gathering network - Treatment system" allowing for correct evaluation of engineering parameters of field development with account for the effect of existing limitations related to reservoir, well design, downhole equipment, gathering system and production treatment. Solving of this problem using the up-to-date modeling technologies accounting for mutual effect of all elements of the system on the basis of multi-disciplinary teams includes the following: Generation of the integrated models "Reservoir - Wells - Gathering system - Treatment system - In-field transport system to the LNG Plant Inlet", Separation of individual types of process design calculations for analysis with consequent incorporation into the integrated model, Carrying out of multi-option calculations of engineering parameters of development and infrastructure, Assessment of the results of calculations of engineering parameters of options by specialists of the multi-disciplinary team, Economic assessment of costs of implementation of the studied options. Using the above mentioned approach with involvement of the integrated field model, multi-option calculations of location and parameters of production treatment facilities and dynamic calculations of flow lines operation parameters for various scenarios of the LNG plant were performed.

Nowadays many oil and gas companies demonstrate a great interest to technology of liquefying of natural gas (LNG). LNG technology is especially topical for gas and gascondensate fields of Yamal and Gydan Peninsulas located so remote from network of transfer pipelines. The exploitation of the field, which provides the output to LNG plant, has its peculiarities in compare with traditional approaches. Development of new approaches to the LNG plant start-up optimization is among the foreground tasks today. Failure prediction and monitoring of operation on the field, providing the production to LNG plant, are inconceivable without dynamic multiphase flow simulator. Main purpose of this work is failure prediction and optimization of South Tambey field operation in the period of start-up and ramp up, taking into consideration posible uncertaincies and risk estimation. In this article authors present the results of predictive computation of the field operation while start-up, and describe their optimization sugestions. The concept of integrated modeling of the entire system "formation-well-pipeline system-inlet facilities" introduced in this paper could be used for the purpose of subsequent monitoring of operation regime.

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