In the Anadarko Basin, well development costs increase exponentially with depth. Average porosities for both sandstone and carbonate reservoirs decrease with depth in a predictable manner. Normal pressure and temperature gradients and a general porosity-water saturation relationship can be used to establish gas in place for reservoir rock at various depths. Recoveries can be calculated using typical permeability versus porosity data.

A base case with 10 feet of net sandstone pay at a depth of 10,000 feet was used for comparative purposes. A 0.15 probability of this case yields an expected discounted cash flow rate of return of 15%. At depths of 15,000, 20,000 and 25,000 feet, sandstone pay thicknesses of 29, 89 and 297 feet are required to match the base case in terms of volume of gas in place per dollar spent. If recovery rates are considered, these thicknesses must be increased to 34, 128 and 670 feet respectively, to maintain a 15% rate of return. Similar relationships are indicated for carbonate reservoirs.


The purpose of this paper was to compare economic for wells in the Anadarko Basin for depths varying from 10,000 to 25,000 feet. Because of the low incidence ooil occurrence below 10,000 feet, only gas wells were considered. For comparative purposes, economics for a base case gas well at a depth of 10,000 feet were run. Economics were then calculated for gas wells at depths of 15,000, 20,000 and 25,000 feet. The following data were used:

  1. constant gas price, gas gravity and operating expense

  2. existing Anadarko Basin data correlating porosity with depth

  3. normal temperature and pressure gradients

  4. general variations in water saturation and permeability with porosity

Pay thicknesses were varied to maintain constant economics at depths of 10,000 to 25,000 feet. Economics were considered both from the standpoint of maintaining a constant cost per Mcf of gas in place and also a constant cost per discounted Mcf of gas recovered. For this paper, the term "discounted Mcf" refers to the gas volume which is derived from projecting production rates with a deliverability model projecting production rates with a deliverability model and discounting those predicted volumes of gas with 15% present value factors. This approach considers both recovery efficiency and the present value concept of money.


For this case, the following data were used:

  1. 10,000 ft depth

  2. 10 ft sandstone pay

  3. 400 acre drainage area

  4. 0.65 gas gravity (no condensate)

  5. 4340 psia original pressure

  6. 207 degrees F reservoir temperature

  7. 12% porosity

  8. 27% water saturation

  9. 0.5 md permeability

  10. -4 skin factor

  11. 215 psia pipeline pressure

  12. $475,000 producing well cost (1/3 equipment;2/3 intangibles)

  13. $380,000 dry hole cost

  14. $2.07/Mcf gas price

  15. $20/day operating expense

  16. 50% tax rate (federal income, production and ad valorem taxes)

  17. 3/16 royalty

  18. 20 year double declining balance depreciation

This content is only available via PDF.
You can access this article if you purchase or spend a download.