While electric submersible pumping (ESP) systems provide economical, efficient and flexible recovery solutions, failure to properly manage early-stage shutdowns in unconventional wells can defer production, lead to escalating intervention and workover costs and diminishing long-term asset value. In unconventional wells, the production stream is highly volatile for the initial 90 to 120 days after first oil.

During this critical period, frack sand flowback, erratic flow rates and gas slugs can negatively impact the production environment. Industry data show that ESP systems are shut down an average of 10% during the IP phase of these wells. A recent study found that one-third of alerts generated by automated production systems during the first 90 days would have likely led to ESP shutdowns if nothing was done to resolve the underlying problems.

Twenty-four hour surveillance during early-stage production can mitigate threats posed by dynamic downhole conditions on production system performance and longevity. The ability to see indicators such as changes in pump intake or output pressures, fluctuations in motor operating current, excessive vibrations, and temperature anomalies early enough to identify and resolve issues before they become threats can prevent costly repair and workover expenses, maintain ESP and production system health, and protect long-term asset value.

However, the upfront capex for a license for advanced production monitoring software can be prohibitive. A real-time web-enabled subscription software service now makes 24/7 early-stage ESP performance and production surveillance available on a monthly fee that saves substantially on capex and reduces upfront investment.

The AMBIT PLUS 24/7 production surveillance service enables real-time remote monitoring of wells and allows quick detection and fast response to changing well conditions to prevent ESP shutdown and failure. The secure cloud-based service combines advanced production monitoring software, secure enterprise cloud-based remote monitoring and real-time decision support from ESP experts. It is based on a software-as-a-service model in which ESP data are collected, stored and managed by Baker Hughes and delivered to subscribers through a web interface that enables them to quickly visualize the data to make critical decisions. The 24/7 production surveillance services are enabled by the company’s AMBIT asset decision solutions platform.

End-to-end data security provides flexible deployment options and an integrated connectivity solution. Remote pump operation maximizes pump service life, pump performance and production. Custom alerts provide email and interface notifications, records actions and system changes, develops a resolution database, and provides ESP-specific reports.

Solving common problems
A consistent tag naming convention is valuable to exception-based surveillance (EBS), which relies on remote monitoring capabilities to manage unplanned production disruptions, or “exceptions.” Using an EBS model enables a shift from reactive maintenance to preventive maintenance, which can maximize equipment runlife, improve operational efficiency, lower cost and risk, and enhance ultimate recovery. The extent to which these benefits can be realized depends in large part on the SCADA system and how it is applied. Often, to reduce communications costs, operators using a generic SCADA tool will unknowingly “leave” a significant amount of important information at the well site for a number of reasons. There is no common tag language among generic tools. The number of tags transmitted might be insufficient to optimize performance. Not all tags will be enabled or understood. Tags will be named differently from one variable speed drive (VSD) manufacturer to another. A secure cloud-based system addresses these issues.

Personnel can pose a constraint to ESP surveillance if they are insufficiently trained in advanced ESP operations, are too busy with other tasks or have limited availability and backup. Software can limit surveillance if administrative support is lacking or difficult to identify or contact, and if the software is not intuitive or user-friendly.

From first oil, the surveillance service team continuously logs, processes and assimilates data and metrics in the unconventional well to establish a unique production profile. Within hours the ESP domain experts can spot anomalies, and within days data and metrics are updated and evaluated, then reintegrated into the system to build ongoing production intelligence. Based on operator preferences, asset goals and the specific production system, ESP surveillance service experts are available 24/7 to adjust systems and other equipment as needed to optimize production, minimize the impact of threatening downhole conditions and limit HSE risks.

The dashboard features trending and alarming options that notify users by email or text message of any changes that might affect the system or well health. Advanced alarms trigger escalation workflows and send notifications to key personnel to take appropriate actions. Key performance indicators provide reference data for well performance and device efficiency, which can be analyzed to improve production optimization decisions. The system generates customizable automated reports that can be emailed on demand or subscription-based.

After the well stabilizes, the rich baseline dataset and continuous data feeds can be used to monitor production throughout the life of the well.

North Dakota case history
A major independent oil producer in North Dakota was plagued by a well that had suffered numerous shutdowns due to an overheated ESP motor as less fluid flowed past it. The operator and Baker Hughes agreed to a two-week pilot project using the 24/7 surveillance service to diagnose the overall health of the well.

During the trial, 18 potential shutdowns were averted—13 of which occurred after hours—meaning they would not have been caught without 24-hr surveillance. The ESP began to draw down intake pressure, and oil production rose. However, after the trial period ended, the surveillance service was not renewed. The well experienced more than 60 shutdowns in the following month.

Realizing the value of the production surveillance service, the operator reimplemented it. Once the service recommenced, the 24/7 surveillance service team detected natural gas slugs that they suspected to be the root cause of the shutdowns. To prevent damage to the motor, the VSD was programmed to shut down the system when the motor temperature increased beyond a predetermined threshold.

After this potential problem was identified, the service team simulated a gas purge program, actively monitoring the well and remotely changing set points several times to keep the system running. When the ESP was in a gas-locked condition, as indicated by a decrease in motor amperage and an increase in motor temperature, the motor frequency was reduced. When the gas slug was mitigated, the frequency was increased again to allow continued drawdown of the fluid level.

These remote actions helped the operator avoid multiple field service calls, saving direct dollars and mitigating potential HSE concerns. Additionally, the ability to avoid a shutdown and subsequent restart was instrumental in extending the life of the ESP.

During the eight-week service term, the production surveillance service prevented 34 potential shutdowns by simulating gas purges—21 of which occurred after hours. The ESP began a steady trend of drawing intake pressure down again.

Over a three-month trend, with the last two months representing time when the surveillance service was in effect, daily oil production increased, and the operator realized an additional $60,000 of revenue. When combined with the earlier pilot project, overall total liquid produced daily increased by 17%.

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