Until the past few years, the U.S. supply of natural gas has always exceeded demand. Enough natural gas was available from conventional reservoirs that it was neither necessary nor economic to develop low productivity reservoirs. The current situation in the U.S., however, necessitates that additional supplies of natural gas be developed to meet the nation's demand. Since 1974, advance in technology and improved economic incentives have resulted in a dramatic increase in the exploration and exploitation of tight gas basins.
Tight gas reservoirs are often termed as "unconventional" reservoirs. The exact definition of conventional and unconventional reservoirs is vague. In economic terms, a conventional reservoir is one in which a reasonable profit can be made at low gas prices and without requiring large volume stimulation prices and without requiring large volume stimulation treatments. Likewise, an unconventional reservoir can be described as one which requires the higher gas prices and large volume fracture treatments before a prices and large volume fracture treatments before a reasonable profit can be made.
In engineering terms, the best way to classify reservoirs is by permeability. Of course other factors are important, such as porosity, net gas pay and reservoir pressure; however, permeability is normally the dominant parameter when evaluating tight gas reservoirs. Considering the current gas price and the level of stimulation technology, it is the opinion of these authors that the "permeability cut-off" for conventional reservoirs is approximately 0.1 md. Normally, if the permeability is greater than 0.1 md, an undamaged well will recover 70–80 percent of the gas in place. When the permeability is about 0.01 md, large fracture treatments are required to recover 40–60 percent of the gas in place. In reservoirs where the permeability ranges from 1 to 5 microdarcies, large fracture treatments are required to recover about 10 to 30 percent of the gas in place. As mentioned above, other parameters such as reservoir pressure, well spacing porosity, etc will affect the pressure, well spacing porosity, etc will affect the recovery efficiency; however, in general terms, the recovery efficiencies given above are realistic.
Substantial quantities of natural gas exist in these unconventional, low permeability reservoirs. The location of the basins which contain a majority of these tight gas reservoirs have been known for many years. Most of these basins are found in the western portion of the U.S. Figure 1 illustrates the location of the most important basins.
Figure 1, was reproduced from a Department of Energy report which was published earlier this year. That report presented a comprehensive study concerning the "enhanced recovery of unconventional gas". Four sources of unconventional gas were considered:
tight gas basins
The Devonian shale
geopressured aquifers
methane from coal seams
To determine the potential of each of these unconventional sources of gas, geologic data, engineering analyses and economics were combined to estimate the recoverable gas from each source.
A portion of that study - the tight gas basins and the Devonian shale - required the use of numerical reservoir simulation to predict well performance. A single phase, two dimensional, finite difference reservoir model was used for this purpose. The model has been described in an earlier publication.
The objectives of this paper are to present the techniques used to model each of these reservoirs and to demonstrate how computer history matching can be coupled with geologic information to develop a realistic interpretation of insitu reservoir conditions.
The first use of the numerical model in this study was to perform a sensitivity analysis using "typical" tight gas reservoir parameters. Computer runs were made to isolate the effects of formation permeability and fracture length upon recovery permeability and fracture length upon recovery efficiency for this average data set.
