First response to large-scale water flooding in the fractured very low permeability Spraberry sand has led to a new unique cyclic operation. Capacity water injection is used to restore reservoir pressure. This is followed by many months production without water injection and the cycle repeated. Expansion of the oil, rock and water during pressure decline expels part of the fluids but capillary forces hold much of the injected water in the rock. At least with reservoir pressure restored and with partial water flood development, field performance has proved this cyclic operation is capable of producing oil from the matrix rock at least 50 per cent faster and with lower water percentage than is imbibition of water at stable reservoir pressure.

Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 301–304 Abstract Inclusion of anisotropic permeability in mathematical analysis of pressure transients observed during development of the huge Spraberry field indicates a major fracture trend which is in good agreement with that observed by fluid-injection tests spread over a 12- by 17-mile area. Delineation of this trend is important in selecting a pattern of injection for the pending large-scale water flooding in this field. Determination of reservoir parameters yielding best agreement between calculated pressures and observed reservoir pressures in newly completed wells was made using an IBM 650 computer. Introduction The Spraberry field covering 400,000 acres is a tight sand of less than 1-md permeability cut by an extensive system of vertical fractures. Primary recovery dominated by capillary retention of oil in the fractured sand matrix blocks is less than 10 per cent of oil in place. Strong forces of capillary imbibition of water into the sand, coupled with water flow under dynamic pressure gradient, indicate considerable increase in oil recovery can be achieved through water flooding. Best results will occur if the pattern of water injection is selected to force the water flow across the grain of the major fracture system. Existence of an oriented vertical fracture system in the Spraberry, observed first in cores, was highlighted more recently by the 144-fold contrast in permeability along and at right angles to the major fracture trend required to match relative water breakthrough times in Humble Oil and Refining Co.'s waterflood test there. Spraberry Operators since have conducted two gas-injection tracer tests for further areal confirmation of the fracture trend. Re-analysis of early reservoir pressure transients for evidence of anisotropic permeability has permitted many more local determinations of major fracture trend without resort to further field tests. This paper is limited to updating analysis of reservoir pressure transients to include anisotropic permeability as a test for orientation of the major fracture trend in the Spraberry. The reader is referred to Ref. 1 and 2 for information about general Spraberry reservoir performance and to Refs. 3 and 4 for information about significance of fracture orientation in selection of the injection well pattern for water flooding the Spraberry.

This paper was prepared for presentation at the 1999 SPE Hydrocarbon Economics and Evaluation Symposium held in Dallas, Texas, 20-23 March 1999.

Today's total world energy demand is near 200 million BOEPD, up five-fold from 1950; over 80% is supplied by fossil fuels and nearly 60% by oil and gas. Many forecasters believe oil and gas production will decline before mid-century, but population growth and economic development combine to drive energy demand ever upward. Dramatic changes must occur in both the nature and magnitude of the various sources of energy supply, and of the various natures of demand, beyond 2050. Yet, vast sources of energy exist. About 1.4×1019 BTU of solar radiation hits Earth's cross sectional area daily, 13,000 times current total energy use. Another 5 to 8×1014 BTU, roughly equal to current use, is conducted to Earth's surface daily from its interior. Einstein's equation assures that every pound of material on earth is equivalent to nearly 4×1013 BTU. Thus, the mass in each barrel of oil contains over 2 billion times more energy than is available by its combustion. Fully exploited as "atomic energy," 0.1 BOPD, about 4 gallons, could meet current total world energy demand. Major problems exist in effectively capturing, converting, storing, transporting, and utilizing these forms of energy while meeting society's diverse and changing economic, environmental, political, cultural, geographic, and aesthetic needs and desires. Development and application of technology, though difficult, is required and almost certainly achievable. This paper analyzes perceived world energy supply and demand beyond 2050, using a range of existing and new forecasts for fossil fuel availability and prospects for other forms of energy. Scenarios are developed for demand based on projected relationships between energy use and world economic and population growth. Responses to some earlier energy shortages are analyzed, and the pace and sweep of technological innovation needed are described in broad terms. Introduction Many forecasters predict an imminent shortage of oil and gas, which supply nearly 60% of the world's energy needs. A recent book1 even predicts world oil production will peak between 2004 and 2008, only 2 to 6 years from now, and then decline. Others have made similar predictions in recent years3,9,10, often based upon Hubbard's4 mathematical "curve fit" method for predicting future oil production peaks, a method that once worked well for the U.S. lower 48 states. In an older but more comprehensive long-term prediction by Bookout2, Figure 1, peak world oil production occurred in 2020. By contrast, in the latest EIA (U.S. DOE) forecast8, oil and gas production increases continuously and monotonically through 2020, the forecast period. Absent geopolitical or environmental constraints, current forecasts of early peaks in oil supply are likely as wrong as so many others have been since 1875 when the Pennsylvania Geological Society issued one of the first such warnings. Nonetheless, someday an actual physical limit, or "shortage" of oil and gas, and perhaps of coal, too, will be experienced, and even though this may not happen in the next two decades, it seems likely that it might occur at least by 2050, if population growth and economic development continue. One likely scenario is that a growing concern about global warming thought to be exacerbated by carbon dioxide released from burning fossil fuels may limit their use in the future. Hence, we must consider how to meet energy demand in the second half of this century, and prospects for coping with either diminished availability or use of fossil fuels. The term "shortage of fossil fuels" isn't entirely appropriate. In the real world, supply and demand are equal, forced so by price in a free market economy, or by government edict in an un-free one, or a combination of both. But temporary interruptions can and do cause genuine economic problems. A free and thriving market economy likely offers better assurances that emerging technologies will alleviate periods of economic pain resulting from spiking energy costs.

Ten to possibly thousand fold ratios of horizontal permeability to vertical permeability are required in two "clean" sand reservoirs to match actual water-free product ion of oil and. gas of wells having bottom water. Layer models with average permeabilities of cores at similar stratigraphic position in the reservoir rather than values selected from the permeability frequency distribution and with highly restricted cross flow yield the best match between actual and calculated dilution of wet gas by injected gas in two cycling projects. These same reservoir modeling concepts yield reasonable agreement with actual performance of the Seeligson enriched gas drive test without assumption of serious viscous fingering with gravity segregation. Introduction The effects of heterogeneity off reservoir rocks on fluid displacement efficiency remain as a very important unsolved problem in this period of rapidly growing application of fluid injection for increased recovery of oil. Hypotheses of reservoirs ranging from non-connecting layers characterized by permeability frequency distribution, irrespective of spatial origin of cores, to reservoirs so heterogeneous they are nearly homogeneous have been offered as bases for evaluation of actual oil recovery projects. Since we are forever barred from knowing the actual variation arid continuity of rock properties, it is imperative that we test our simplified models against performance of actual reservoirs to select those assumptions most appropriate as guides to judgment. This paper presents two types of field observations having a bearing on these models:Determination that 10 to possibly1000 fold ratio of horizontal permeability to vertical permeability is required to match water coning performance of a number of wells in "clean" sand reservoirs in contrast with very low ratios usually observed in small core plugs. Possibly cross flow between layers in laboratory fluid flow models or calculated mathematically for multilayer systems with equal horizontal and vertical permeabilities may not be representative of actual reservoirs in which gross anisotropy appears to be much greater than that of small cores.Agreement between actual dilution of gas streams by injected gas in two cycling projects and that calculated with assumption of parallel flow in separate layers is reasonable if permeabilities assigned to individual layers are average permeabilities of cores from different wells at the same relative vertical position in the reservoir section rather than values from the permeability frequency distribution. Most performance features of the current Seeligson enriched gas drive project are adequately matched by this parallel layer type analysis.