Abstract

The Woodford Shale is one of several unconventional energy reservoirs in the southern Midcontinent. It is almost entirely Devonian in age making it much older than the Mississippian Caney, Barnett, and Fayetteville reservoirs. The Woodford consists mostly of organic-rich siliceous shale with variable amounts of carbonate and interbedded cherty beds. The latter is most common in the upper and lower parts of the formation where they form laterally continuous beds that are 1-3 inches thick. Cherty beds were deposited in a cyclic manner and are composed of radiolarian skeletal remains. In these same strata, phosphatic nodules may be abundant. Diagnostic log characteristics of the Woodford include very high gamma-ray (GR) and high resistivity (where hydrocarbon saturation is high) in both the shale and other strata.

From January 2000 through April 2009, the Woodford Shale produced >350 billion cubic feet of gas (BCFG) from ~800 horizontal wells. Most of them were completed in the Arkoma Basin of southeast Oklahoma. Average production per well is ~700 thousand cubic feet gas per day (MCFG/d) with initial rates as high as 5–11 million cubic feet of gas per day (MMCFG/d). Wells are typically drilled using oil-based mud close to the center of the formation. Laterals are routinely drilled 3,000 to 5,000 feet and fractured-treated in 3–9 stages. Slick-water fracs pump about 100,000 to over 300,000 pounds proppant (sand) per stage into the formation. The resulting pattern of induced fractures greatly increases formation exposure to migrating hydrocarbon molecules, which are chiefly stored in a network of microfractures. Enhanced mobility of hydrocarbons from reservoir/source rocks to the horizontal wellbore is the basis for higher production volumes for longer periods compared to vertical wells.

In this study, reported and extrapolated monthly production from 21 Woodford wells is tabulated in Microsoft Excel™ spreadsheets and plotted using simple line graphs. Predicted declines are realistic because actual production rates define the most significant period of decline for each well. Initial annual decline rates were 45–80% with most being on the high side of this range. Subsequent annual declines were calculated so projections were appropriate in achieving a hyperbolic decline during the first several years of production. Although graphs are projected to 20 years, many wells are uneconomical or depleted long before this time period. Additionally, only wells having moderate-to-long laterals (>2,300 feet) are considered in order to represent recent drilling practices.

In order to more realistically compare cash flow to well costs (drilling and completion), several gas pricing scenarios are used; $8, $5, $3.50, and $2 per thousand cubic feet of gas (MCFG). Furthermore, cash flow was reduced to 70% (of gross) to account for revenue reductions linked to Net Revenue Interests (NRI), gross production taxes, and other expenses. Although well costs are directly related to many factors including depth, lateral length, and completion methods; the cost basis as used for all wells in this study is $5,500,000. Based on these assumptions, wells having an Estimated Ultimate Recovery (EUR) above 3 BCFG will pay out within in a few years with wellhead gas prices of $5 to $8/MCFG. Even at $3.5/MCFG, this same population of wells (perhaps <15% of the current wells) will pay out within 3–7 years. However, for "average" wells, those having an EUR of about 2 BCFG, payout will linger from 4 to 7 years with gas at $5/MCFG, and probably never reach payout with prices below $3.50/MCFG. Seasonal and discounted (index) gas pricing will further erode cash flow and delay payout significantly. As is common with most of the major gas producers, "hedged" gas prices above $7/MCFG have justified the current frenzied drilling pace to profitably drill and strategically hold acreage. However, this pricing structure will likely diminish significantly in the near future thereby jeopardizing development of this play.