Abstract
Eagle Ford Shale (EFS) wells are comprised of a combination of challenges that can quickly limit production potential. This paper will review a case history of a well where conventional lift methods were crippled by these challenges, so an electrical submersible pump (ESP) was tested after previous installations were uneconomical.
Utilizing artificial sumps in gassy wells has proven valuable in larger casing sizes, but this well included an additional set of unique challenges. The challenges for the ESP system for this specific test included: (i) deviated wellbore; (ii) scale and corrosion issues; (iii) tight casing; (iv) high gas-to-liquid ratio; (v) gas slugging. To overcome these challenges, a slimline ESP system was installed inside an artificial sump to separate gas and operate smoothly during gas slug events. The system was equipped with a recirculation system to maintain cooling for the motor and a capillary line for continuous chemical treatment.
This paper presents comparisons between different forms of artificial lift producing separately in the same well, as well as different forms operating concurrently in offset wells. Uncommon design and operation methods are presented with production results. The test concluded that a comprehensive design for downhole ESP equipment, including a chemical treatment plan, can increase production in an EFS well. Results included an improved drawdown rate, improved production, and no evidence of scale buildup. Additional benefits would include significantly increased time between well work overs and reduced number of system failures due to corrosion, resulting in a substantial reduction in non-productive time.
The positive results of the test demonstrate how to achieve the beneficial economic impacts of a properly designed ESP system in the Eagle Ford Shale as compared to traditional artificial lift designs.
