A deep Granite Wash well was tested on an Electrical Submersible Pump (ESP) after being shut-in for 11 months due to uneconomic and unsatisfactory rod lift operations. The three main objectives of the test were: (1) to determine if an ESP system can be successfully utilized on a gas well; (2) to implement a downhole recirculation system; and, (3) to monitor the economic impact of the installation of the ESP unit. The challenges for the ESP system for this specific test included: (i) motor cooling restriction due to absence of adequate rathole; (ii) production from multiple perforations over 600 ft spread; (iii) low liquid flow (<400 BPD); (iv) high gas-liquid ratio (>1600 CF/BBL); (v) deep well depth (10,000 ft); (vi) small ID production casing (5.5" 17lb/ft); and, (vii) high potential wellbore scaling/corrosion issues. Due to these challenges, using a traditional motor shroud jacket was considered a disadvantage. As a result, a downhole recirculation system was used as an alternative method to (a) prevent potential gas locking; (b) circulate fluid to keep the motor cool; and, (c) enhance capillary deployment of scale and corrosion chemical treatment. This paper presents basic principles of the application of ESP systems in a gas well, principles of implementing a downhole recirculation system, and uncommon techniques to effectively operate an ESP unit in dewatering gas wells. It also includes the historical design challenges, system specific design/operation, and production results of the tested well. The test concludes that it is possible to successfully and economically de-water a deep non-conventional gas well utilizing a properly designed ESP with a downhole recirculation system. In addition, the test had demonstrated the benefits of web-based monitoring of the variable speed controller and downhole sensor information.
Wellbore designs and completions can positively impact long-term production in directional wells, but many directionally drilled wells are designed today without regard for future pump applications. Communication between drilling, completion, and production teams is often poor, and this negatively impacts the ability to produce in liquid-rich multiphase environments. This situation is especially true as the well matures. Early collaboration between these groups is imperative to maximize production options. Without such cooperation, many directional wells are designed without future pump success in mind. Consequently, electrical submersible pumping systems (ESPs) are excluded as a viable artificial lift solution in a majority of directionally drilled wells. ESP technology advances have made ESPs viable in many multiphase liquid-rich wells. Ignoring current ESP capabilities ultimately diminishes production over the life of some wells. Many of these directional wells flow naturally, but liquid loading reduces production without artificial lift. ESPs can be the most productive method for reducing reservoir pressure and optimizing production, and they should be considered when designing a wellbore. The Mississippian Lime in Oklahoma and Kansas (though not a shale play) has many similar attributes of a liquid-rich shale. This paper includes a case study from the Mississippian play for a horizontal drilling plan and completion technique aimed at optimizing pump performance. "Pump-friendly" fundamentals for wellbore design and geometry are presented. This paper concludes that increased awareness and implementation of a few basic principles will pay huge early dividends as the well matures.
Artificial Lift Case Study: A Mississippian Lime well was tested on an electrical submersible pump (ESP) after previous installations were unsatisfactory. The three main objectives of the test were: (1) to determine if the run life and production of an ESP system could be increased on a gas-slugging well; (2) to implement a downhole recirculation system inside an artificial sump; and (3) to monitor the economic impact of the installation of the ESP unit to the well. The challenges for the ESP system for this specific test included: (i) low liquid inflow during severe gas slugging; (ii) high gas/liquid ratio (>800 SCF/BBL); (iii) difficult startup conditions; (iv) thermal and mechanical damage to motor lead extensions. Due to these challenges, using traditional gas-separation and gas-handling technology was considered a disadvantage. A downhole recirculation system inside an artificial sump was used as an alternative method to prevent potential gas locking, to circulate fluid to keep the motor cool, and to enhance reservoir drawdown. This paper presents basic principles of the application of ESP systems in a gassy and gas-slugging well, principles of implementing a downhole recirculation system, and uncommon techniques to effectively operate an ESP unit in gas-slugging wells. Historical design challenges system-specific design/operation, and production results of the tested well are also presented.
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