(Tech Connections Column, August 2007, American Oil and Gas Reporter)

One thing industry has learned about gas shale resources is that each play, or even subplay, requires a somewhat unique set of exploration, drilling, completion and operations practices to maximize profitability, but those are based on common underlying concepts. One is that an integrated approach involving geology, geophysics and engineering must be employed. A second reality is that certain data will inevitably be needed, so operators should plan to gather it. Appalachian Basin operators gathered to see what they could learn by simultaneously looking at several Eastern province gas shale plays.

Geophysical studies can identify areas of better reservoir quality, locate fractured areas or sweet-spots, and identify fracture directions. Azimuthal seismic analysis is extremely valuable for detecting fracture systems. Factors controlling reservoir quality include mineralogy/clay content, amount of cementation, and presence of natural fractures. Completion planning should consider the location of major and minor faults, and the size of a fault’s structurally damaged zone.

On the petrophysical side, one must delineate the shale gas beds, quantify gas content, estimate producibility, and predict production. Shale gas reservoirs are depositionally continuous (wide geographic area), but vertically heterogeneous. Short range structure and diagenesis affect gas in place and productivity. Geomechanics can help characterize stress state and guide completion decisions. A critical question with horizontal wells is lateral placement. Which direction should be drilled? Where should the lateral be landed, considering drilling efficiency? What is the impact of vertical lamination/complexity?

Common questions early in a play’s life are:

• How much will wells produce?

• How widely will they vary?

• How many wells must be drilled, and how long do they need to produce before production and reserve estimates are reasonably accurate?

Of the several reserves techniques available (volumetrics, material balance, decline curve and modeling), decline curve forecasting and modeling are most commonly applied. However, decline curve analysis can seriously underestimate long-term production and cumulative recovery. Note, though, that it is “early life” cash flow that makes or breaks well economics.

A key concept in hydraulic fracturing is to maximize stimulated reservoir volume. Microseismic data indicate that stimulated reservoir volume increases with larger fluid volumes. Since larger fluid volumes can most economically be achieved using water alone, slick-water fractures are the predominant treatment, although some operators now are moving to more expensive systems (gels, foams and microemulsions). Some also are moving toward increased proppant volumes. Although costs for horizontal wells may be twice those of vertical wells, reserves can be two to four times larger.

The Antrim in Michigan is one of the more mature gas shale plays, with more than 9,100 producing wells averaging 41 Mcf a day, and still more than 400 wells being drilled each year. Wells are completed in both the Lachine (upper) and Norwood (lower) members, commonly utilizing separate light-sand nitrogen fracs.

Significant Antrim player Aurora Oil & Gas, has evolved to low-residue gel frac systems. Early on, many wells were not logged open hole. Instead, sample logs, rate-of-penetrations logs, and cased-hole gamma ray logs were used. Conventional open-hole logs still are not commonly used. Aurora does run an open-hole acoustic fracture identification log in every well.

A driving principle in any shale play is to minimize back pressure. John Hunter with Aurora shared some of its completion and operating practices.

In a typical medium-radius horizontal, casing is set at the top of the shale, then the lateral is drilled open hole, rising from heel to toe. With the pump set in the casing, there would be some back pressure from fluid head.

An alternative is to drill and case a sump through and below the zone, then move uphole and drill the lateral rising from heel to toe. Fluid would then flow from the toe to the heel and drop into the sump where the pump is set. Another option is to intersect a vertical producer drilled at the toe of the horizontal. In this case, the horizontal trajectory is downward from heel to toe.

Aurora continues this “low pressure” philosophy throughout its surface facilities. Gathering systems use separate, largediameter poly pipe for gas and water. Modular screw compressors provide more flexibility and are lower cost than reciprocating compressors. Carbon dioxide also can be removed on site at low pressure (100 psi), versus the conventional approach of compressing to pipeline pressure (1,200 psi) and transporting for third-party treating.

On a closing note, the U.S. Geological Survey presented data from its assessment of undiscovered natural gas resources in the Appalachian Basin’s Devonian black shales. This is done on an individual cell (acreage) basis for the several shale formations in the basin. One end product–a map showing the estimated per well recovery of different geographic areas–would seem indispensable to anyone embarking on a gas shale program there.