ESP optimization in the Mississippi Lime
An operator in North America selected service level two—remote ESP surveillance, diagnostics and proactive management—to address rapid production declines, solids production and high gas volume fraction in the unconventional, liquids-rich Mississippi Lime Formation near the Oklahoma-Kansas border. The operator needed to maintain ESP uptime to increase production while keeping lifting costs low in four wells with declining multiphase production, high gas-to-liquids ratios (GLRs) and a high degree of produced solids, primarily from sand used in hydraulic fracturing. The key challenge was managing oil production that ranged from initial rates of 4,000 bbl/d down to 400 bbl/d or less after a year of operation and increasing GLRs, from 300 scf/bbl to 1,700 scf/bbl.
Schlumberger designed a strategy that included abrasion-resistant ESPs to minimize risk of failure from solids, with compression pumps to provide enough flexibility to perform over a wide range of production volumes. The pumps needed to be properly sized to lift the initial high liquid volumes, then adjusted when production declined. A multiphase gas-handling system was incorporated to manage GLR variations, while a high-temperature ESP sensor monitored the operating conditions. The sensors provided real-time monitoring of intake pressure and temperature, motor temperature, vibration, current leakage and pump discharge pressure—all crucial for diagnosing pump problems and improving performance in unconventional wells.
To optimize the workflow, the Lift IQ service used the sensor data to diagnose adverse events in real time and recommended within minutes corrective actions. In Well A, the ESP system and production life-cycle management service managed a 94% production decline, from 5,424 bbl/d to 300 bbl/d over 393 days, with 84% uptime. GLR increases from 350 scf/bbl to 1,200 scf/bbl also were managed. The service also helped to overcome communication problems resulting from an ESP in one well tripping the ESP in an adjacent well.
In Well B, one ESP managed a 90% production decline and a GLR increase from 320 scf/bbl to 1,300 scf/bbl over 189 days. To manage drawdown, the ESP modified pump intake from 1,000 psi to 600 psi. A second ESP managed the lower production of 200 bbl/d of fluids and 250 Mscf/d of gas for 262 days.
In Well C, the ESP system performed for 654 days through a fluid production decline from 4,275 bbl/d to 750 bbl/d over five months, and a slower drop to 350 bbl/d, with a GLR of 1,200 scf/bbl. Cumulative pump uptime was 68.2%, with most of the downtime related to manual shutdowns, ESP trips during low-or no-flow periods and power-generation issues. The production life-cycle management service analyzed pump alarms in real time to optimize ESP performance as downhole conditions changed, and guided decision-making when communication from a nearby well destabilized the pumps. At the end of the ESP life, this well had 16% more cumulative liquid production than a comparable offset well produced with just 53 days on an ESP followed by gas lift, and 55% more cumulative liquid production than was planned for gas lift alone.
In Well D, one ESP managed production decline of 84% and GLR increase of 182%, drawing down the well from 1,300 psi to 400 psi over 190 days. A second ESP managed the next 221 days of production, which declined by 86%.
All monitoring, analysis, diagnostics and communication to the field were managed in real time from the ALSC in Houston. On average in the Mississippi Lime Formation, ESPs operated with the production life-cycle management service increased average runlife by 181%, from 118 to 322 days, and managed GLR increases up to 243% and production declines up to 94%.