State-of-the-Art Summary

Affordable, Effective Technologies Being Applied by Independents
by Lance Cole

Dr. Iraj Ershaghi, PTTC's West Coast Region Director, issued a challenge to independents to become familiar with and apply "smart well" technologies.

Major operators in large fields have employed smart well systems, and in doing so, they have reduced costs and improved recovery. Technology improvements are bringing the cost and complexity down. The goal is to change from episodic or reactive (after the fact) management to continual, real time, proactive management. This means monitoring parameters soon enough and frequently enough that early warning signs are seen so that changes can be made that prevent failures. 

Mark Reedy, Global Energy Partners, presented key insights from a recent study about reducing power consumption in California's old pumping oil wells. The study found that nearly 50% of the wells could benefit from optimization. For change to occur, old mindsets about continuing to operate "as is" versus investing for efficiency must be changed. Opportunities for power cost reduction fall into electrical or mechanical categories.

Key steps include examining motor efficiency, installing pump-off controllers, combating gas interference, monitoring performance and reducing water production. In California's case, this study led to a rebate program that reimburses operators for some of the investment required to become more energy efficient.

Bob Kiker, PTTC Permian Basin, described how operators there are changing their wellbore management programs to reduce failures, by as much as a factor of 10. Supported by several case studies, operators have found that structured programs requiring all involved (operators and appropriate vendors) to work closely in teams with defined accountability can have dramatic results. Open sharing of preferred practices or "what's working" is quite common in the Permian Basin, which only aids these structured programs. 

Modern reservoir simulation technology is user-friendly, PC-based, powerful (quick run times) and robust (can handle complex problems). This enables companies to get results quickly, resulting in more reservoirs being modeled and simulation results being used to aid in near real time decisions. 

Jim Erdle, Computer Modelling Group, made the point that for even majors, the historical practice has been to only perform reservoir simulation in "core" assets. But that practice is changing. He noted how one engineer with a major had, in just one year, simulated 25% of the profit center's reservoirs. Over a two-year period, an estimated 7 million BOE of reserves were added. In another example, he noted how simulation helped an independent make a timely decision about the level of steam injection (cut back or discontinue completely) during California's energy crisis in the winter of 2000-2001. A proven simulation model was on hand, so the operator's consultant could quickly perform "what if" scenarios. The operator cut back steam injection, saving $6.7 million within just six months, and changes were made with the confidence that long-term adverse impacts had been minimized.

Old plays can have new life with new technologies. Rodney Reynolds, PTTC's North Midcontinent Region Director, described how larger volume gel polymer treatments using MARCITsm technology and GasGunsm solid propellant stimulation treatments are increasing production in Kansas's very mature Arbuckle producing areas.

Reynolds noted that, since early 2001, more than 150 production wells had received large volume gel polymer treatments. Similarly, more than 50 operators had stimulated nearly 150 separate wells with GasGunsm treatments with about one-third of those being in the Arbuckle. Overall results with both technologies have been very positive. PTTC staff is working to further document case studies and periodic workshops keep producers aware of current activity and results.