Enhanced Recovery Utilizing Variable Frequency Drives and a Distributed Power System
The project was selected under the Research with Independents solicitation, DE-PS26-02NT15377. The program is intended to assist small independent oil producers in testing higher-risk technologies that could keep oil flowing from thousands of U.S. fields.
Under this project, Peden Energy will install a microturbine in the oilfield, connect this turbine to a natural gas supply line, connect electric lines from the turbine output to an oil well, and generate electricity to operate two oil/natural gas wells.
The microturbine that Peden Energy utilized is an advanced model that will burn a portion of the natural gas from production and reportedly has an efficiency level of 50%. An effort was made to recover the heat in a combined heat and power mode that can increase overall efficiency to 75-80%.
The use of a microturbine and a variable frequency drive has several benefits:
1) production can be increased; 2) mechanical stress is decreased, 3) electrical and capital expenses for motors, switches, etc. can be reduced; and 4) electricity costs are cut. Potential improvements of 10% increase in production and 20% in energy savings are expected.
Maintenance costs and life expectations for the microturbine are predicted to be more favorable then those for internal combustion (IC) engines (generators) and therefore offer a more favorable life-cycle cost and performance. Currently available options for power supply in the oilfield are traditional electric grid power delivered through power lines or IC enginers at the wellsite. Grid-supplied power is typically one of the highest operating costs associated with a producing oil/gas well and is subject to disturbances or outages. IC engines are typically 30% or less efficient and require frequent refueling with gasoline/diesel.
In conjunction with the microturbine, this project installed two variable-frequency drives with computerized pump-off controllers onto two pump jacks. A variable frequency drive adjusts and varies the pumping speed of the well based upon downhole torque demand. The greater the torque, the faster the pumping; as torque demand decreases, the pump speed is decreased.
This variable speed drive-enabled pump control capability enables the operator to:
- Automatically adjust pumping speed to match the well productivity and automatically prevent pumping off and shutting down. By maximizing stroke speed during low torque demand, total strokes per minute are increased and can lead to a 10% or greater increase in oil production.
- Start motors at minimum frequency (soft start, therefore reducing mechanical stress) and ramp smoothly to full power. Capital expenses also are reduced, as smaller-horsepower electric motors can be used because of the soft-start capability.
- Achieve optimum matching of production capability and lowest power cost, by slowing the beam during peak power demand and increasing the speed during low torque demand on motors. Through this process, a small independent can reduce power demand, maintain minimal power usage per stroke, and anticipate energy savings of up to 20%.
Current Status (October 2005)
The project has been completed, and the final report is in progress.
Project Start: June 30, 2003
Project End: March 31, 2005
Anticipated DOE Contribution: $100,000
Performer Contribution: $125,314 (56% of total)
NETL - Jim Barnes (Jim.Barnes@netl.doe.gov or 918-699-2076)
Peden Energy - Randy Peden (email@example.com or 806-897-2069)