Attributes of a Large Underpressured Gas System, San Juan Basin, New Mexico
Philip H. Nelson, Steven M. Condon, 2008. "Attributes of a Large Underpressured Gas System, San Juan Basin, New Mexico", Understanding, Exploring, and Developing Tight-gas Sands, S. P. Cumella, K. W. Shanley, W. K. Camp
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Large quantities of natural gas have been produced from underpressured Cretaceous reservoirs of the San Juan Basin since 1951, yet the reasons for the under-pressuring and the containment mechanisms remain a subject of inquiry. In this investigation, compilations of reservoir pressures from the 1950s and early 1960s are used to minimize the perturbations caused by later gas production. The pressures are projected to two basin-scale cross sections showing the structural configuration and stratigraphy of Cretaceous and younger rock units. Gas pressures in the Dakota Sandstone vary according to location, with pressure/depth ratios of 0.36 psi/ft (8.16 kPa/m) in the west and 0.41 psi/ft (9.27 kPa/m) in the east, where pressures approach hydrostatic values. Gas pressures in the sandstones of the Mesaverde Group are remarkably consistent, with pressure/depth ratios of 0.24 psi/ft (5.42 kPa/m), except in the southeast corner of the gas accumulation where the pressure/depth ratio is 0.35 psi/ft (7.91 kPa/m).
Pressure-elevation plots, in conjunction with cross sections and measurements of hydraulic head in water wells, show that the gas system is not buoyant in the way that a conventional gas accumulation is buoyant. Underpressuring in this basin reflects the absence of bottom water and the presence of top water. The pressure reference for the gas is at the edge of the gas accumulation instead of at the bottom, and the preproduction gas pressure is determined by the elevation of the lateral transition from downdip gas to updip water on the southwestern limb and other margins of this asymmetric basin.
No pressure discontinuity between gas and water exists at the updip edge of the gas accumulation; hence, no seal in the usual sense exists, and there is no need for one. The hard seal of a shale or an evaporite formation is replaced by a capillary soft seal caused by a transition from low-permeability downdip rocks to high-permeability updip rocks.
Hydrodynamic trapping, an explanation that has been cited for many years, is not required. Instead, the gas is just sitting in a pancake-shaped volume bounded by a low-permeability base, a gentle stratigraphic rise on one side, and more steeply dipping monoclines on the other three sides. The gas does not escape from the edges of the basin because no excess gas pressure can exist in the absence of an underlying aquifer.
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Understanding, Exploring, and Developing Tight-gas Sands
The 2005 Vail Hedberg Conference was convened to gain a better understanding of the tight-gas sand resource life cycle by encouraging a free exchange of cross-disciplinary discussion among leading scientific and engineering experts. The results of the conference have led to improved exploration models and development and completion strategies required to exploit the vast North American tight-gas sand potential and emerging international tight-gas sand plays. This third volume in the AAPG Hedberg Series is recommended for geologists and engineers involved in exploring, developing, and appraising tight-gas sand plays for a comprehensive updated view of this important natural-gas resource.