A Laboratory Study of Low-Permeability Gas Sands
- F.O. Jones (Amoco Production Co.) | W.W. Owens (Amoco Production Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- September 1980
- Document Type
- Journal Paper
- 1,631 - 1,640
- 1980. Society of Petroleum Engineers
- 4.6 Natural Gas, 4.1.5 Processing Equipment, 5.4.2 Gas Injection Methods, 2.4.3 Sand/Solids Control, 1.6.9 Coring, Fishing, 1.14 Casing and Cementing, 1.8 Formation Damage, 2.5.2 Fracturing Materials (Fluids, Proppant), 5.8.1 Tight Gas, 4.1.2 Separation and Treating, 5.5.2 Core Analysis, 5.1 Reservoir Characterisation, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 1.6 Drilling Operations, 5.6.2 Core Analysis, 5.2 Reservoir Fluid Dynamics
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Routine permeabilities of tight gas sands are shown to be greater than under reservoir conditions, often by more than a hundred-fold, because of the great relief of stress, absence of connate water, and increased gas slippage. Correlations are presented that can be used to estimate in-situ permeability from routine data.
Yearly compilations of U.S. oil and gas reserves by the American Gas Assn.1 show that U.S. gas reserves reached a maximum in 1967 of nearly 290 Tcf (8×1012 m3). With the exception of the year 1970 when Prudhoe Bay reserves were added, gas reserves have declined at a near-constant rate of 10 Tcf (2.8×1011 m3) per year since then. To help moderate or reverse this trend, the industry is extending its exploration and development efforts to include horizons with permeabilities in about the same range as common cement - i.e., microdarcies. The design of stimulation treatments to achieve commercial rates of production and reliable assessment of potential reserves in such low-permeability rocks demands accurate knowledge of their permeability, porosity, and flow properties. Though meager, there is sufficient information already available in the literature to suggest that some of the flow properties of these rocks differ markedly from those of more permeable rocks and, thus, require closer study.
Results of several different studies of the properties of low-permeability gas-producing horizons have been published previously. A study by Thomas and Ward2 showed that the permeability of cores from the Pictured Cliffs and Fort Union formations were affected significantly by confining pressure. Porosities, however, were not altered greatly. They also reported that the presence of a simulated connate water saturation (about 500(0) reduced gas permeabilities to only 10% to 20% of the specific gas permeability. Vairogs et al.3 concluded that very low-permeability rocks are affected by stress to a greater degree than those having higher levels of permeability. This agreed with results reported earlier by McLatchie et al.4
Tannich5 mathematically studied liquid removal from fractured gas wells in low-permeability horizons and concluded that in very low-permeability rocks, cleanup times could be extensive but that permanent formation damage was not likely. The study, however, provided no measured experimental data of the flow properties of low-permeability rocks.
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