Abstract The objectives of this chapter are threefold: (1) to provide a historical perspective on considerations of pervasive tight-gas accumulations, (2) to provide some observations on the present understanding of these accumulations, and (3) to anticipate where the industry is headed in the future. From 1979 to about 1987, various workers (industry, government, and academe) discussed pervasive tight-gas accumulations and established important relationships for source rock, maturity, expulsion and migration, pressures, rock quality, and fluid content. Their main conclusion was that the hydrocarbons in these reservoir systems were dynamic and not static as in conventional structural and stratigraphic traps. The paradigm shift made by 1987 concluded that these accumulations were continually adjusting to existing conditions in both time and space. In more recent years, additional examples have been documented, and questions have arisen about the validity of the original model, noting the presence of more water in some systems than the model would predict. The close proximity of the mature, gas-generating, and gas-expelling source rock to the reservoirs is critical. The amount and richness of mature source rock has to be adequate for the volume of reservoir rock being charged. The proper combination of these circumstances produces more gas than can be contained under normal pressure. The quantity of this gas charge relative to available pore space in the reservoir system will dictate the reservoir pressure. Pervasive tight-gas accumulations have now been documented in more than 20 North American basins and are the targets for major ongoing exploration and development programs. The average reservoir porosity for these producing units is in the 8–9% range, with average in-situ permeabilities of hundredths of a millidarcy. We believe the industry will likely move forward in four directions: (1) revisit older mature basins, (2) expand into new basins, (3) move into carbonate reservoirs, and (4) continue to develop tighter and tighter rock. With continuing technology improvements (especially in drilling and completing) and robust gas prices, the industry will access vast new reserves farther down into the resource pyramid.

Abstract One means of evaluating the effectiveness of a surface geochemical method for petroleum exploration is to compare the results of the method used with the drilling success. Four case histories show how one surface geochemistry technique, which measures the concentration of iodine in soils, relates to postsurvey wildcat and development success. The four cases are in separate basins in the onshore U.S.A.: the Denver-Julesburg Basin in Colorado, the Powder River Basin in Wyoming, the Williston Basin in North Dakota, and the Illinois Basin in Illinois. In each case, properly processed soil-iodine data demonstrate a correlation between soil-iodine anomalies and petroleum accumulations. The distribution of iodine values in the soil is not straightforward. Evidence indicates that some spurious samples may be taken that are not attributable to sampling or laboratory error. A method of defining a soil-iodine anomaly that partially compensates for this effect is presented. This method relies on a moving weighted average of the data, in which substitute values (indicator values) are averaged, rather than the iodine data themselves. The thresholds for the different indicator values are selected from histograms and cumulative-frequency plots. In the Dolley field area in the Denver-Julesburg Basin, all producers and dry holes are correctly predicted by the iodine method. In the Prairie Creek area in the Powder River Basin, all dry holes and one of two producers are correctly predicted by the method. In the Eland field area in the Williston Basin, all producers are correctly predicted, but three of the four dry holes are on soil-iodine anomalies. In the Springfield East area in the Illinois Basin, all but one dry hole is correctly predicted, but only two of the six producers are correctly predicted. Overall, a correlation between soil-iodine anomalies and hydrocarbon accumulations is strongly indicated by the cases presented in this paper.

Abstract The Greater Rocky Mountain Region covers approximately one-fifth of the contiguous 48 states. The United States Geologic Survey recognizes 22 “provinces” or “areas” in the region, of which 18 produce oil or gas. It estimates that 10.4 billion barrels of oil and condensate and 259.8 trillion cubic feet of gas remain to be discovered in the region. Known source and reservoir rocks extend throughout a thick sedimentary section ranging from Precambrian to Tertiary in age. Virtually every conceivable type of tectonic and sedimentary environment known is present in some areas of the region. Additional oil production from established plays is not expected to be large. Greatest potential exists in unconventional plays and in sparsely drilled deeper sections of individual basins. Gas discoveries will be more important than oil discoveries. Most of the gas potential is related to sources in coal-bearing Cretaceous and Tertiary sediments. Much of this gas will be found in coal-bed reservoirs or in low-permeability sandstones. The deeper and lessexplored parts of many basins will contain gas because of advanced thermal maturity of the sediments. Much of the potential production will fall in the middle and lower ranges of “Masters’ resource triangle,” which, in the case of the Rocky Mountain region, has a broader base than many other areas of the world. Exploration and development will be greatly influenced by technical, economic, and political factors. Examples of recent significant discoveries that may serve as analogs for the future include Jonah, Cave Gulch, Cedar Hills, Drunkard’s Wash, and the Powder River Basin coal-bed methane fields. Many of these “discoveries” are unconventional accumulations and have resulted from the application of new technology to areas of previously abandoned, noncommercial, or subcommercial wells.

Abstract The Dimple limestone (Atokan) of the Marathon region represents a period of carbonate deposition which interrupted the deposition of a thick terrigenous flysch section in the Ouachita geosyncline. It consists of laterally adjacent “shelf,” slope, and basin facies from north to south. The “shelf” facies is characterized by cross-bedded fossil and oolith lime grainstones. The slope and basin facies consist of sequences of distinctive limestone turbidites. Paleocurrent analysis indicates a uniform paleoslope dipping southward, with no apparent slope break. A southern source with less contribution to the basin is also indicated based on paleocurrent evidence. Slope facies limestones (proximal turbidites) may be graded, partly graded, or nongraded. Many beds are nongraded in their lowest parts but grade rapidly in their upper parts. Basal portions are often conglomeratic, and lime mudstone upper portions are often absent. “Floating” pebbles are common, as are large-scale convolutions. Small-scale cross-bedding is rare, and occasional medium-scale (up to 3 feet thick) cross-bedding has been observed, which is interpreted as “dune” bed forms. Associated rocks are subaqueous slump conglomerates and spicular lime mudstones. The slope facies is 5 miles wide. Basin facies limestones (distal turbidites) are nearly always graded. Pebbles are rare; the coarsest size being generally sand or silt. Lime mudstone beds are well-developed, and were deposited from turbidity currents because (1) thick mudstone beds overlie thick graded beds, and (2) the normal pelagic sediment is radiolarian-bearing mudstone (marl) with a large terrigenous mud component. Convolutions are common, and small-scale cross-bedding is abundant. Associated rocks are black radiolarian-bearing shales and spicular cherts. The portion of the Ouachita geosyncline revealed in the Marathon region is believed, in Dimple time, to have been a basin about 40 miles wide and perhaps a few hundred feet deep. Turbidity currents moving down a gently-sloping bottom from the north deposited limestones on the slope as well as in the basin. These proximal and distal turbidites display distinctive characteristics, and an awareness of them may assist in reconstructing facies patterns elsewhere.