Systematic ESP surveillance and analysis ensures consistent well performance, today, and for the economic lifetime of the producing horizon.

The challenge to extend the economic life of mature fields has been one key factor driving the development of new production technology and field management techniques. New downhole sensors are providing more reliable measurements. Real-time monitoring, surveillance and control of wells producing on electric submersible pumps (ESP), are allowing tighter tolerances on operating conditions and delivering improved economic return. The combined and synchronized application of increased downhole information yields improved lift system results. Efficiently applying these new capabilities requires a systematic, engineered approach.

The Axia Lifting Service from Schlumberger incorporates multiple downhole technologies with engineering software and associated services to aid operators in efficiently evaluating their often-large portfolios of wells producing via ESP. This service allows for an efficient way to validate, store and retrieve well geometry, equipment, fluid and reservoir information. The combination of these workflows enables a more rigorous validation of a well's lift design and operating criteria, while continuous surveillance enables a more proactive strategy for well performance improvement. Atheon I wells are used to illustrate the results that can be achieved.

Required parameters

The production optimization envelope for an ESP is determined by pump performance, maximum production capacity and maximum sandface drawdown pressure. For the highest economic return from a lift system, balance between pump performance and production rate is imperative.

ESP performance takes into consideration both pump life and power consumption. A well's optimum production rate is maintained as a function of pump operation, completion and reservoir deliverability.

Today's downhole sensors and real-time surveillance infrastructure are making it possible to establish and maintain much tighter tolerances on the downhole conditions under which wells are produced. These measurements and systems can be used to analyze fluids, pump performance and reservoir deliverability. It is this combined and synchronized application of information that yields improved system results.

Identifying opportunities

For an operator to prioritize which lifted wells, out of potentially thousands being monitored, require review and optimization, a selection protocol has been set up within the espWatcher component of the Axia Service. The associated downhole technologies required provide production engineers with real-time measurements and key performance indicators for parameter trend and system analysis. Simply delivering more data to the engineering team does not adequately address the need for rapid well analyses and more efficient interventions. It is the coordination of data acquisition, storage, publication/presentation, analysis and recommendation capabilities that distinguishes the service described.

The process begins by defining the production optimization envelope. Pump performance is modeled and validated by comparing measured data against the bench test for the specific pump. Next, reservoir parameters are determined and validated. Reservoir diagnostics are done on a periodic basis to determine permeability, skin and reservoir pressure. Through this analysis, reservoir production can be predicted and reservoir deliverability trends can be monitored to identify opportunities to improve a well's inflow performance.

The strength of this methodology lies in modeling the total system. The ability to model the entire system, both pumps and reservoir performance, requires ESP experts in conjunction with reservoir engineers to validate the input parameters and create the hydraulic models. Access to critical information on demand that seamlessly populates established workflows provide the opportunity for continuous iterations of the system's model before a change is made in the actual well.

The final step is to establish the critical boundaries of drawdown pressure. The maximum flow rate allowed for any given pump establishes the theoretical upper boundary. However, prior to increasing the speed to obtain an increase in production, maximum drawdown pressure must be estimated. This is done to ensure that no formation or completion damage occurs.

At this point, a geomechanical analysis program, which analyzes the relationship between the reservoir and bottom hole flowing pressure, identifies the critical drawdown pressure. This pressure establishes a safe upper boundary for maximum flow (Figure 1). Alarms are set in the surveillance system to maintain drawdown below this point. Pump frequency is increased close to this limit, resulting in maximized production in a safe range for the pump and formation.

In addition to the ESP pumps themselves, state-of-the-art downhole sensors and accurate flow measurements are needed to execute the steps described. Equipment configuration can vary based on local production complexity. The selected technologies are supported by a range of surveillance, lift and sand management analysis software, models and engineering services.

Field application

Atheon has more than 200 wells in western Texas and central Oklahoma under surveillance using the espWatcher system (Figure 2). These wells are connected through their acquisition panels to Schlumberger's computing server via satellite link. The centralized computing server provides authorized and controlled access to the collected data from any desktop via the Internet. The desktop interfaces used to view the data are customized to allow the service company experts to be able to drill down deeply into the raw data while providing Atheon's engineers the reports and data required to properly collaborate with and supervise the service company team.

During 2004, one Atheon well experienced decreasing intake pressure, which triggered a warning alarm in the Schlumberger Production Center of Excellence. The surveillance engineer looked at the potentially under-performing situation in several ways.

First, trend analysis of the data indicated that flow rate and intake pressure were decreasing, while other parameters remained constant. Pump performance analysis meanwhile confirmed that the pump was not causing the well's underperformance (Figure 3).

To evaluate the reservoir's potential, the intake pressure response was examined and two transient events were identified in the recorded pressure response over time. Both pressure transient events were examined and a pressure transient interpretation was performed (Figure 4).

To evaluate well production and validate the model derived from the pressure transient analysis, an inflow performance relationship (IPR) curve was created. Using this relationship, a match point of the measured intake pressure and the measured flow rate was plotted against the predicted values. Next, the model created was used to predict well production assuming the removal of the near-wellbore skin. This analysis showed that production could be increased from 450 bo/d to 640 bo/d.

A stimulation treatment was recommended and performed and the pump reinstalled. When returned to production, the well stabilized at 525 bo/d at a much higher intake pressure.

Post-workover production analysis determined that the near-wellbore skin remained at 2.2. If desired, further production improvement could be obtained with a more aggressive treatment.

Meeting the challenge

Today's Axia Lifting Service can be used to target specific wells requiring optimization of the completion and/or lifting system in order to deliver improved performance. One of the key benefits is that downhole data are both accessible and in a useable format.

With downhole data readily available, engineers can then define a well's production optimization envelope by:

• Validating the well fluid data;

• Applying hydraulic modeling to determine the best operating condition for the pump;

• Diagnosing reservoir behavior and validating reservoir parameters with downhole measurements during the transient phase; and

• Establishing the critical drawdown boundaries by geomechanical models.

Once all steps have been completed, proactive alarms are set in the espWatcher system to ensure stability within the desired envelope.

This procedure delivers maximum production with expected ESP performance while remaining within the critical drawdown boundaries. The ideal operating settings vary with changes in produced fluids, mechanical changes, reservoir parameters and surface line pressure. Having the ability to make continuous adjustments is critical for optimum performance and maximum well production. Ease of collaboration between the service and operating company staffs, as well as reliability of the systems being used for surveillance, analysis and communication, are critical components.

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