A reliable method for determining the in situ stress state in deep formations is of great importance to the gas industry in designing massive hydraulic fracture treatments of low permeability reservoirs. Knowledge of the horizontal in situ stress directions and magnitudes would allow prediction of fracture azimuth and height. In this paper a method using anelastic strain recovery measurements of oriented core will be presented as a reliable and practical tool for determining both the directions and magnitudes of the principal horizontal in situ stresses in deep formations. The principal horizontal stress directions are determined directly from the principal horizontal strain recovery directions. The principal horizontal strain recovery directions. The principal horizontal stress magnitudes are calculated from principal horizontal stress magnitudes are calculated from the principal strain recovery magnitudes, overburden stress, and Poisson's ratio of the rock using a viscoelastic model by Blanton. In addition, petrophysical measurements of the core parallel to the principal directions of strain recovery, at atmospheric pressure and at elevated confining pressure, suggest that the strain recovery process is a consequence of microcrack formation and expansion. Introduction As a result of an increased need for better recovery techniques to enhance gas production, massive hydraulic fracturing has been used in low permeability reservoirs where it is uneconomical to retrieve gas in the conventional manner. Massive hydraulic fracturing is the most promising technique for stimulation of low permeability promising technique for stimulation of low permeability gas reservoirs at the present time. This technique is at least an order of magnitude scale-up from conventional hydraulic fracture technology and it is designed to create long penetrating fractures which contact large areas of the reservoir. However, the results to date have often been disappointing and the general applicability of these treatments for unconventional gas resources is uncertain. Among the many technological problems encountered in massive hydraulic fracturing there are two important questions that must be answered properly to design a hydraulic fracture treatment and locate production wells for optimum gas recovery in a specific gas production wells for optimum gas recovery in a specific gas field. The first question is, what is the geometry, particularly the height, of the fracture. The second particularly the height, of the fracture. The second question is, what is the azimuth of hydraulic fracture propagation. The first question is concerned with the problem propagation. The first question is concerned with the problem of predicting whether or not the fracture will be vertically restricted or contained within the gas producing zone or will the fracture propagate out of this zone producing zone or will the fracture propagate out of this zone into the overlying and underlying formations. When a fracture is designed the height of the fracture is the parameter about which the least is known, prior to parameter about which the least is known, prior to stimulation, yet the fracture height influences all aspects of the design. Theoretical, laboratory, and field studies have shown that in deep formations the fracture height is predominantly influenced by variations in the minimum in situ stress magnitude. The susceptibility of a vertical fracture to be restricted or contained is significantly enhanced by a compressional increase in the minimum principal horizontal stress. Prediction of fracture height could be made if the in situ stress state in the reservoir fracture-interval and the bounding formations were known. Moreover, for fracture treatments in which the economic success of the treatment requires fracture containment in the reservoir fracture-interval, a knowledge of the in situ stresses would enable selection, a priori, of zones that are bounded by high stress layers, and thus would have favorable fracture growth and containment conditions. P. 421