May 2000 Vol. 221 No. 5  Production

Perry A. Fischer,  Engineering Editor

You can almost feel the production

Anzoil NL, based in Perth, Australia, Success Oil Co. and 40% shareholder Maurel & Prom have formed a new venture called Viboil International. The new firm will apply an innovative EOR method called VibroSeismic Extraction Technology (VSET). Viboil has signed a memorandum of understanding with Elsib, a Siberian company that is the third largest manufacturer of electricity equipment in the FSU and apparently the originator of the technology. Elsib has agreed to grant Viboil exclusive rights to market VSET worldwide. The partners feel confident enough in the new technology to ask for other people’s money.

Elsib will furnish the hardware – essentially large vibrators – and field operating personnel, as well as scientific analysis. According to a press release to the Australian and New Zealand stock exchanges, VSET can: increase total recovery; increase production by 10% and, in some cases, above 35%; decrease watercut; be extremely cheap compared to other EOR technologies; and be applied to most of the world’s oil fields.

VSET is only new outside of Russia, but "it has been successfully applied in a number of Russian oil fields. It is scientifically proven in Russia, but to date has seen little application outside." The first commercial pilot project outside Russia was recently completed for Caltex in Sumatra. Viboil says that production increased 25% as a result of VSET.

Actually, something similar has been under development in the U.S. since 1997. The current project at The Los Alamos Seismic Research Center (LASRC) is funded by the DOE under the Natural Gas and Oil Technology Partnership. The project is called Seismic Stimulation for Enhanced Production of Oil Reservoirs. Project participants are: AERA Energy, Applied Seismic Research, Chevron, Conoco, Fluidic Technologies, Halliburton, Marathon, OGCI Management, PerfClean Int., Phillips Petroleum, Piezo Sona-Tool, Texaco, Wave Energy Resources, Wellington Operating Co., LBNL and the University of California at Berkeley.

A 6-month stimulation test at Wellington field, located 90 mi north of Denver, Colorado, ended in July 1999. The field has produced continuously since 1923 and currently produces about 50 bopd. Cumulative oil production to date, about 8.7 million bbl, represents roughly 10.6% of the original oil in place. Recovery efficiencies for similar reservoirs in the region range from 15% to 30%, so the field should have been a good EOR candidate.

Eight wells were monitored for production changes during operation of a downhole fluid-pressure-pulsation device (Wave Energy Resources’ DRSS). One of the eight wells showed an increase in oil cut to 10% from 6% and an apparent increase in total fluid-production rate to 85 bpd from 63 bpd; however, one well went permanently offline during the experiment. The field as a whole showed no significant overall production changes.

Another test in AERA Energy’s San Ardo field in California used a new acoustic device. The test has been operational since July 1999. Although production data has not yet been released, initial reports from AERA are encouraging. AERA plans to deploy additional acoustic sources based on the results so far.

And now the Iowans seem to have caught up with the Russians. Developed by ETREMA, an Ames, Iowa, firm, the new downhole acoustic source is called a magnetostrictive alloy, swept-frequency (200–400 Hz) acoustic-wave radiator. The company wasted no time in claiming that the device has been shown to "increase oil production by 100%." The tool is deployed on tubing and is powered electrically from the surface. The company has also introduced a version for larger casings with long perforation zones with three times the earlier unit’s power output.

The company further states that "tests of production are being conducted in cooperation with several oilfield operators," and that energy propagates "as far as 3,300 ft radially" (although the LASRC project has yet to detect any energy – even as close as 400 ft). This January, ETREMA was awarded a patent for its PowerWave acoustic petroleum-production-stimulation tool.

Exactly when, where and why acoustic-stimulation for EOR works – and sometimes doesn’t work – is not yet understood. Lab experiments to date have shown a wide range of results, from positive to neutral to negative. Such tests suggest that the key parameters are acoustic frequency, whether oil is displacing brine during drainage or brine is displacing oil during imbibition, and exactly how the acoustic energy is coupled.

Several new, larger-scale field-stimulation experiments are being discussed with industry partners who will be supporting the majority of the field-related costs. Clearly, something exciting is going on. Stay tuned.

Extraordinary VSP. Paulsson Geophysical Services (P/GSI), Inc., recorded a 152,000-trace, 3-D/3-C VSP in 60 hours for Calgary-based PanCanadian Petroleum Ltd. and its partners – an oil industry record for a 3-D VSP survey.

The clamped, three-component, borehole-seismic receiver array was deployed in a well in Weyburn field in Saskatchewan, Canada last December. With 80 levels and 50-ft geophone-pod spacing, the array measured 4,000 ft long – also an oil-industry record. To image the fractured carbonate reservoir at a 5,000-ft depth, deployment of an array this long made repositioning unnecessary for different surface-shot locations, as is often required for shorter downhole-seismic tools.

The 3-D/3-C VSP data were simultaneously acquired with a surface 3-D/3-C survey using dynamite sources and PanCanadian’s patented MegaBin land-acquisition technique. All seismic data were collected to provide baseline measurements for a planned 4-D seismic program for a large-scale, horizontal-well, CO₂-flood project, commencing in October 2000.

Using proprietary processing software, the first prestack-depth-migrated 3-D image was generated in the field, nearly simultaneous with recording the last shot. The final prestack-depth image was delivered to PanCanadian six weeks after the survey was completed. Reservoir features – including faults and pinch outs – were evident on a much smaller scale than occurs from using surface-seismic methods. Preliminary results show that the frequencies (175–200 Hz) recorded should allow for 5-m resolution in the final images.

Comments? Write: fischerp@gulfpub.com