During the past year, Southwestern Energy Co. and other operators (most notably Chesapeake Energy) have further delineated the Fayetteville Shale play in the Arkoma Basin of Arkansas. Southwestern has also reported some excellent results from recent horizontal wells in the play utilizing water fracs. For example, the Southwestern Energy Grills No. 2-31-H made 95.5 million cubic feet of gas in August 2006.

The Fayetteville appears to be maturing past the exploratory phase in the initial fairway or core area of Conway, Faulkner, Van Buren, Cleburne and western White counties, with an average estimated ultimate recovery for the latest horizontal wells in this region appearing to be above 1.5 billion cubic feet. However, there have been disappointing results so far in the eastern extension of the play into the Mississippi Embayment, such as Lee, Woodruff, St Francis and eastern White counties.

As of November 2006, according to state records, there were 123 producing Fayetteville/Moorefield (more on the Moorefield later) wells in the core area of the play in Cleburne, Conway, Faulkner, Van Buren and western White counties. Southwestern (114), Chesapeake (8) and Yale Oil (1) operated the respective wells.

In addition, there were more than 250 active drilling permits (wells currently drilling, being completed, being tested or staked) for these counties.

In addition to Southwestern and Chesapeake, which are the most active players, companies with outstanding permits include Hallwood Petroleum, Maverick, Pathfinder, CDX Gas, Aspect Energy,Teepee (also known as Alta Resources, which has the partial financial backing of George Mitchell of Mitchell Energy & Development), J-W Operating, Edge Petroleum and David Arrington. Shell Oil Co. has a large leasehold in the play but has elected, at least to this point, not to operate any of the wells in which it has a working interest.

In 2006, Chesapeake announced that about 700,000 of its 1 million acres were not currently prospective based on its disappointing drilling results in the Mississippi Embayment-portion of the play. However, various companies have applied for more than 20 drilling permits in Woodruff, St. Francis,Monroe, Phillips, Jackson,Lee and Prairie counties, all in the eastern (Mississippi Embayment) portion of the play.

Geology

There is a general lack of industry knowledge about the potential shale reservoirs in the Arkansas portion of the Arkoma Basin. Using our experience in the Barnett and other shale plays,we have completed an extensive geologic and petrophysical study of the Fayetteville Shale. It soon became clear that the Moorefield, which we divided into a lower and upper unit, was also a prospective horizon.

Since we began our work, Southwestern Energy has completed at least one well in the Upper Moorefield in Cleburne County. The Woodford Shale, now prevalent in southeastern Oklahoma, has also been tested in the basin, but we don’t believe there is sufficient gas-in-place to warrant a complete study at this time.

We correlated logs from all available wells (about 150) in the eastern portion of the Arkansas part of the Arkoma Basin and Mississippi Embayment. We also constructed nine regional cross-sections across the basin, and constructed 21 maps to help understand the geology of the Fayetteville and Moorefield shales.

In many ways, the stratigraphy and structural geology of the Arkoma Basin are more complicated than in the Fort Worth Basin, making the exploration and exploitation of the Fayetteville and Moorefield shales more difficult than the Barnett.

One problem or misunderstanding is where exactly in the stratigraphic column the Fayetteville lies. In short, we agree with the stratigraphy data used by Southwestern Energy, and think that the formational boundaries used by the Arkansas Geological Commission, though possibly technically correct in a biostratigraphic sense, are not useful for geologists prospecting in the basin.

A quick examination of wireline logs across the relevant stratigraphic section shows that the higher gamma ray-higher resistivity shales are the prospective intervals, not the shale higher in the stratigraphic column (between the Fayetteville and the overlying Hale).

The Ouachita Thrust Belt is a common factor in natural gas production in these plays:

  • Barnett Shale in the Fort Worth Basin;
  • Woodford and Caney shales on the Oklahoma side of the Arkoma Basin;
  • Fayetteville, Moorefield and Chattanooga shales on the Arkansas side of the Arkoma; and
  • Floyd/Neil shale in the Black Warrior Basin of Mississippi and Alabama. (See related article elsewhere in this report).

Without the emplacement of the Ouachitas and the resultant heating events across these basins, there would be no gas production from these reservoirs. The continental-scale thrusting events acted like a series of squeegees, pushing hot, mineral-laden brines out in front of the thrust sheets.

This brine moved through the underlying Ordovician strata (e.g., the Ellenburger in the Fort Worth Basin) and heated the shallower rocks (Mississippian and Devonian shales) to a point much hotter than would be expected with a “normal” Midcontinent burial history. Without this additional heat flow, many portions of these basins would not have made it into the gas window.

The highest heat flow was in the Arkoma Basin,probably because of its location at the apex of the Ouachita Trend. The lead-zinc deposits of the Tri-State mineral district of the southern Ozarks were emplaced as a result of this hot-brine migration.

Fayetteville Shale

It quickly becomes obvious that the Fayetteville Shale is different from the Barnett of North Texas. Most importantly, the Fayetteville was deposited in a much different environment than the Barnett; and, hence, it’s restricted to a smaller area. There were abrupt facies changes during the time the Fayetteville was deposited, especially to the east toward the Embayment and south toward the Ouachita Thrust Belt, that create hazards for exploration for gas in this formation.

The thickest portion of the Fayetteville Shale is toward the north and northwest, at the outcrop belt. This is in direct contrast to the Barnett, where the thickest section is in the deepest portion of the Fort Worth Basin, which is in front of the Muenster Arch in Montague County. This “upside down” thickness pattern, such that the thickest shale interval is toward the basin margin, gives some indication as to the depositional system responsible for the Fayetteville Shale.

The Moorefield Shale lies just below the Fayetteville; a relatively thin limestone unit called the Hindsville separates them.We divided the Moorefield into a lower and upper unit,with the upper being the more perspective unit.

Petrophysical Traits

Historically, critical petrophysical parameters have been difficult to predict in gas shales. Techniques developed through years of experience in the Barnett Shale in the Fort Worth Basin were used here to tie the limited core data to the more widely available log data. Models were developed to predict porosity,water saturation and gas-in-place (free and sorbed) in the Fayetteville,and upper and lower portions of the Moorefield shales.We have mapped these.

For the Fayetteville Shale study,we began by digitizing the pertinent log data for more than 120 wells. Preliminary formation correlations were made to aid in analysis. The models require gamma ray, bulk density and resistivity logs. The gamma ray and bulk density data were normalized to account for calibration issues.We patched the bulk density data to eliminate false reading because of washouts. Resistivity inversion analysis, performed on old E-log data, old induction data and dual-laterolog data, eliminated discrepancies because of different generations of resistivity tools. The cleaned and normalized log data enabled more confident stratigraphic correlations.

Modeling of petrophysical parameters is based on available core and cuttings data, including standard gas shale core data for two wells, the Thomas 1-9 and the Thomas 1-16 (both drilled by Southwestern Energy) and geochem analysis from cuttings on 45 wells.

We trained and confirmed neural network models to calculate porosity and total organic carbon (TOC) using the core data. The TOC model was further confirmed using the cuttings-derived geochem data.We developed deterministic models to calculate water saturation and gas-in-place, comparing these results to published core data.