Tight gas sands for this analysis have less than 0.1 md (100 microdarcies) in situ gas permeability ranging down to 0.001 md (1 microdarcy). permeability ranging down to 0.001 md (1 microdarcy). Eliminating speculative basins and portions of basins where production is proved, a tight gas resource of 409 Tcf has been identified.

Estimated recoverable reserves vary between 149 and 182 Tcf at $1.75 and $3.00/Mcf (1977 dollars) with anticipated technology improvements in 5 years. Annual production rates, affected by technologic advances and price growth, could be around 2 Tcf/year in 1985 increasing to 7 to 7 1/2 year for the last decade of this century. This compares with production in 1977 of 19 1/2 Tcf.

Most of these technology advancements anticipated relate to better methods for resource characterization lateral and vertical control of massive hydraulic fractures (MHF) extension by design, and the ability to design fracture programs to expose lenticular pays existing within a thousand or more feet from the wellbore but not penetrated by the well programed to drain the area. Parallel with these major objectives are improvements in fracture fluid design, proppants, and postfracture production performance analysis.


Lewin and Associates, Inc. were commissioned by ERDA (now DOE) in 1977 to study the technology and economics of gas recovery from four identified types of unconventional gas, i.e. tight gas, Devonian shale, geopressured water (gas dissolved), and methane from coal. Two reports on this study have been published recently by DOE and a third report detailing methodology will be issued soon. This paper deals only with the tight gas resource as paper deals only with the tight gas resource as studied by Lewin and Associates. The author of this paper has been involved heavily in this study. While paper has been involved heavily in this study. While this paper incorporates the relevant findings of the DOE study, it enlarges and expands on the evolving MHF technology and how it has brought this type of resource into play.

Prior to this study, the Federal Power Commission included in its National Gas Survey a study on natural gas technology. This was initiated in 1971 and was published in 1973. It was during this study that deeply penetrating fractures became recognized as having potential for exploiting tight gas sands in three major western basins particularly the Mesa Verde section. At that time the term "massive hydraulic fracturing" was coined, admittedly for lack of a better alternative. With growing application, the abbreviation MHF has become an accepted term. However, there is no real definition as to when a big fracture treatment enters the MHF category. Most treatments in tight gas formations defined herein are categorized as MHF. It is technology related to MHF that is highlighted in this paper. paper. Exploitation of several tight gas formations also is accelerating with production in 1977, amounting to about 0.9 Tcf. The advanced technologies required are primarily aimed at reducing the risk and the maximizing economic recovery efficiency of the resource.


Most tight gas formations in this study are classified as those having in-situ permeability to gas of less than 0.1 md (100 microdarcies) and ranging down to 1 microdarcy (see Figure 1). Some shallow low pressure formations may fall into the near tight category. Most of these formations have 40 to 60% connate water saturation and porosities generally in the 8 to 12% range.

Singe-phase bench top permeabilities often must be reduced by a factor of 10 or 20 to approximate in-situ gas permeability. The reduction is necessary to account for relative permeability to gas at 40 to 60% water saturation and compaction due to overburden net confining pressure.

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