January 1998 Vol. 219 No. 1  Production

Thomas R. Wright, Jr.,  Editorial Director

Frac technique minimizes formation damage

A technology that allows proppant to be placed into a created fracture without using potentially damaging liquids has been developed, tested extensively in Canada, and now made available for U.S. applications. Called Dry Frac, the technique uses liquid CO₂ as the carrier fluid (without water or any additional treatment additives) and has been used in more than 1,200 successful liquid CO₂ sand stimulations in Canada. The process has been described by the Petroleum Technology Transfer Council (PTTC), a non-profit information network begun by U.S. oil and gas producers. PTTC programs are funded by the U.S. Department of Energy, universities, state governments and industry donations.

Key to the process is a CO₂ blender that blends proppant into the liquid CO₂ stream, thus eliminating any need for traditional carrier fluids to transport the sand. As a result, no damaging fluids are placed into the pay zone, and potential damage to water sensitive formations are all but eliminated.

Other benefits to the process are shorter clean-up times and no need for swabbing or frac tanks. Obviously, water disposal and hauling costs are also eliminated.

Treatments have typically ranged from 25,000 to 30,000 gal of liquid CO₂ together with 35,000 to 47,000 lb of proppant (blender capacity is limited to 47,000 lb of proppant). Injection rates vary between 40 to 55 bbl per min (bpm).

The blender is a closed system, pressurized vessel, and is pneumatically loaded with proppant. Liquid CO₂ is introduced into the tank at 0°F and 300 psi. Nitrogen is used as a positive displacement blanket to push the CO₂ / sand slurry through the blender to the suction side of the hydraulic fracturing pumps.

Proppant transport results from turbulence generated from high pump rates with low viscosity fluids (liquid CO₂ has a viscosity of about 0.1 cp). Twin augers are located in the bottom of the blender vessel and their rotational speed controls the density of the slurry. Densiometers determine and record proppant concentrations, which have been measured as high as 6 ppg.

Case histories. A 15-well demonstration project was conducted in the Devonian shale. The U.S. DOE participated through a cost-sharing program that was designed to provide operators with the economic incentive to test the technology.

Four of the wells were treated using CO₂ / sand, seven were treated with nitrogen gas without proppant, and four were completed with N₂ foam and proppant. After 37 producing months, the wells stimulated with CO₂ / sand produced four times as much gas per well as those stimulated with foam, and about twice as much as those stimulated with N₂.

In another DOE cost-shared study, three Pennsylvania gas storage wells were stimulated using the process. Immediately following stimulation, deliverabilities were about ten-to-one and six-to-one in two of the wells. In the third well, attempts to break down the formation were unsuccessful.

Two wells were completed in the Marcos shale in Colorado. Conventional well stimulations employed there were usually foam fracs or gas fracs (no proppants). About 40,000 lb of proppant were placed in the formation and a maximum of 6 ppg was achieved in both wells. Subsequent flow tests indicated that one of the wells was the best in the field, while the other was a dry hole.

Costs of a typical Dry Frac treatment range from $30,000 to $50,000. Variables affecting costs include CO₂ price and hydraulic horsepower requirements (a function of well depth and rock stress).

DOE is seeking to expand tests of the Dry Frac technology. Operators with newly drilled, cased and perforated gas wells, and interested in field testing CO₂ / sand fracturing should contact Albert Yost at (304) 285-4479; e-mail ayost@fetc.doe.gov.

Spending rises; production doesn't. In a recent study covering the first nine months of 1997, Salomon Brothers discovered an interesting enigma—major oil companies have increased their capital spending by 12% compared to 1996, but oil and gas production has risen only 0.5% over the same interval.

In addition, these same companies had, at the beginning of this year, targeted production growth at 3% to 4%. Salomon reports that this anemic production growth and its wide miss of the target may explain why some prognosticators consistently overestimate global oil supply. The firm also speculates that the decreased efficiency of locating reserves with the drill bit may encourage the major oil companies to continue acquiring production through acquisitions.

Another pattern is that majors are growing development capex faster than their exploration expenditures, which may suggest a focus on short-term production goals. This short-term development may come at the expense of longer-term exploration.

Anyone studying the Salomon report would obviously wonder if the miniscule production growth, as compared to spending, is simply the result of the time lag between money invested and production coming onstream. Salomon acknowledges this possibility, but also suggests that increased costs of working in more hostile areas and higher rig rental rates may be erroding profitability. Whatever the cause, the situation merits continued observation, and a better idea of what's happening could emerge when companies announce their 1998 capex budgets.

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