Technical expertise, drilling rigs, dollars— and hope—are constantly being exported from the successful Barnett shale in the Fort Worth Basin to others around the country. With greater understanding of what makes shale plays successful, two prime candidates have emerged in the Sooner State. The Woodford shale in the Arkoma Basin is well known, having been successfully drilled for four years, with Newfield Exploration Co. the dominant operator.

The Arkoma Basin in eastern Oklahoma has been the focus of many unconventional-gas players including Newfield, Chesapeake Energy, Devon Energy, St. Mary Land & Exploration Co. and XTO Energy. Newfield, the most active operator, has spud 140 horizontal wells and participated in nearly 60% of the industry’s 400 horizontal wells. It has 13 rigs running in the play, 11 of which are dedicated to development drilling.

As of December 2007, the Houston company cited net production from the Woodford of 165 million cubic feet (MMcf) per day. Estimated recoveries are steadily improving from an average of 3 billion cubic feet per well. Newfield reported the average frac stage will ultimately recover 600 MMcf, and it has run up to nine stages in its longest lateral. It is said that extended lateral completions (at lengths of 3,400 feet or greater) have the potential to yield finding and development costs in the range of $2 per thousand cubic feet.

The Ardmore Basin in southern Oklahoma is another area in which operators are pursuing Woodford shale. Bankers Petroleum Ltd., a Calgary company traded on the Toronto Stock Exchange, is one such operator. It is pursuing Woodford in Carter and Johnston counties through its wholly owned subsidiary, Bankers Petroleum (U.S.) Inc., of Camarillo, California. Privately held independent Wagner & Brown Ltd., based in Midland,Texas, is also in this play.

Woodford shale characteristics found in the Ardmore Basin are similar to those found in the Arkoma Basin. Published data on the Woodford in the Arkoma, along with data from Bankers’ Woodford wells in the Ardmore, indicate comparable percentages of silica content and total organic carbon, and the shales are found at similar depths in each basin. The Ardmore Woodford interval is almost twice as thick, and the estimated gas-in-place numbers are twice as large as in the more-established Arkoma Basin.

However, the Ardmore shales, as measured by vitrinite reflectance (%Ro), appear to be thermally immature. That’s why the Ardmore Basin did not get the initial attention of shale players. Pyrolysis data since have shown %Ro values from the Woodford in the Ardmore were suppressed because of high hydrogen content.

Brian Cardott, Oklahoma Geological Survey geologist, has presented data showing thermal maturity values in the Ardmore Woodford have been suppressed by 0.17% to 0.44 %Ro. Correcting for the suppression pulls the %Ro values in the Woodford up into the thermally mature range and makes the basin more prospective.

Bankers Petroleum has been able to drill a number of wells and quickly get into production mode on its 14,000- net-acre block because of early strides the Arkoma operators made. Its first exploration well, the Nickel Hill 1-26, was a vertical test with an initial production rate of 900,000 cubic feet equivalent (Mcfe) a day. (Bankers calculates Mcfe at a 10-1 ratio of condensate and natural gas liquids to Mcf rate, based on pricing.)

Bankers followed that success with its first horizontal well, the Greenway 35-1H, about one mile south. This well had an initial stabilized production rate of 2.2 MMcf a day. In September 2007, these two wells were tied into a production facility.

Data from Bankers’ wells show an average %Ro of 0.96 (corrected for suppression), which is in the wet-gas window and matches production results. It was assumed wet-gas production was the “kiss of death” to shale plays, but Bankers’ early data show good flow characteristics of gas and liquids from the wells, and in the current gas pricing environment, economics are working on these wells, although it is still early on the learning curve.

Bankers is experimenting with adjustments to its fracture stimulation programs and position of subsurface laterals it believes will improve initial gas production rates. It has continued its work in the basin with three additional horizontal wells, one of which is more than 10 miles east of the Nickel Hill producer. This step-out had an initial production rate of 2.1 MMcfe. The other two were scheduled to be stimulated in December 2007.

A 115-square-mile 3-D survey is in the final stages of acquisition, and first data are already guiding the continued development program. Wagner & Brown has completed drilling its first horizontal well, the Maher 22-1H. Chesapeake Energy has also drilled a horizontal Woodford well, the Jordan 1-12H, in Cado Field west of the Bankers-Wagner & Brown acreage. It had an initial production rate of 2.6 MMcfe per day.

Cado Field was originally drilled in the 1950s and 1960s for lower Pennsylvanian-aged sands with later production mainly coming from Sycamore and Hunton intervals. A number of vertical wells had also been completed in Woodford, usually commingled with the other intervals.

Chesapeake recently has filed for another horizontal Woodford location in the field. It is also acquiring a large 3-D seismic survey to the southeast of Bankers-Wagner & Brown’s acreage block. Antero Resources, Range Resources and XTO Energy are among players that have acquired acreage in the vicinity of Bankers’ leases. Acreage prices in the area have drastically increased during the past year.

Bankers and Wagner & Brown plan to accelerate their drilling program with additional rigs in first-quarter 2008. Drilling costs will receive significant attention. Recently, Newfield reported costs for its horizontal shale wells in the Arkoma Basin average $5.5 million, which the company is working to reduce. Bankers believes it can drill and complete its horizontal wells in the Ardmore for less, about $2.6- to $3.5 million each, depending on depth.

Although the drilling and completion program is still being refined, knowledge gained from other operators in the Arkoma Basin has helped the company achieve its early positive results. If it can match the recovery results that Newfield is reporting in the Arkoma Basin, Bankers’ 14,000 acres could have potential of more than 400 billion cubic feet equivalent (Bcfe) net at 100- acre spacing. That number could float even higher, as estimated gas-in-place per section is 220- to 300 Bcfe. A 15% recovery factor, which has been obtained in places in the Barnett shale play, would yield considerably more gas. These calculations assume all of the 14,000 acres are found to be productive and all other early assumptions hold true.

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