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An improved method determines vuggy carbonate permeability on the basis of specific surface area per unit pore volume and a flow zone indicator (FZI). Comparisons of fit standard error estimates show that this approach is superior to the multivariable empirical correlations of Chilingarian, et al., and to the ANN-estimated permeabilities.
Reserve growth is a major component of the remaining U.S. natural gas resources. Historical data support this premise, as do estimates of technically recoverable and of economically recoverable gas resources remaining in the U.S. However, reserve growth is still poorly understood. Hence, much work remains to be done on the phenomenon of reserve growth.
The discovery of large gas hydrate accumulations on the North Slope of Alaska and off the U.S. southeast coast has heightened interest in gas hydrates as a possible energy resource of the future. However, significant geological uncertainties and possibly insurmountable technical issues need to be resolved before gas hydrates can be counted as a viable option for future, affordable supplies of natural gas.
An evaluation of thermal maturity, pore pressures, source rocks, reservoir quality, present-day temperatures, and fluid recovery data indicates the presence of a large basin-centered gas accumulation in the Dnieper-Donets basin (DDB) and Donbas foldbelt (DF) of eastern Ukraine (Fig. 1).
In this article, some of the trends in the estimates of the oil and gas resources are examined, with a view toward better understanding world oil and gas resources in the context of the next few decades. Quantitative assessments facilitate recognition of the big picture, which is necessary for purposes of planning and investment, and also form the foundation for periodic adjustments to the big picture made necessary by changes in technology and scientific understanding.
This final article on the outlook for U.S. future natural gas supplies expands on the concept of the natural gas resource pyramid. A series of poorly understood but potentially significant emerging gas plays is introduced. These plays reside at various levels within the resource pyramid. These emerging resources include sub-volcanic gas, shale gas, deep coalbed methane, and unrecognized tight gas sands.
The U.S. Geological Survey (USGS) estimated in 1995 that 1,412 tcf of technically recoverable natural gas remained to be discovered or developed in U.S. onshore areas. A significant part of that resource base, 114 tcf, is undiscovered gas in deep sedimentary basins assessed by the USGS in onshore areas and state waters. These deep gas accumulations, at or below 15,000 ft, occur in numerous, widely differing geologic settings (Fig. 1 [138,549 bytes]).
The US Geological Survey (USGS), in response to potential geohazards, energy resource potential, and climate issues associated with marine gas hydrates, has developed a laboratory research system that permits hydrate genesis and dissociation under deep-sea conditions, employing user-selected sediment types and pore fluids. The apparatus, GHASTI (gas hydrate and sediment test laboratory instrument), provides a means to link field studies and theory and serves as a tool to improve gas hydrate recognition and assessment, using remote sensing techniques. GHASTLI's use was proven in an exploration well project led by the Geological Survey of Canada and the Japanese National Oil Corp., collaborating with Japan Petroleum Exploration Co. and the USGS. The site was in the Mackenzie Delta region of the Northwest Territories (Mallik 2L-38 drillsite). From tests on natural methane hydrate-bearing sand recovered at about 1,000 m subsurface, the in situ quantity of hydrate was estimated from acoustic properties, and a substantial increase in shear strength due to the presence of the hydrate was measured. 1 2 GHASTI can mimic a wide range of geologic settings and processes. Initial goals involve improved recognition and mapping of gas hydrate-bearing sediments, understanding factors that control the occurrence and concentration of gas hydrates, knowledge of hydrate's significance to slope failure and foundation problems, and analysis of gas hydrate's potential use as an energy resource.
The observed `field growth' for the period from 1992 through 1996 with the US Geological Survey's (USGS) predicted field growth for the same period are compared. Known field recovery of field size is defined as the sum of past cumulative field production and the field's proved reserves. Proved reserves are estimated quantities of hydrocarbons which geologic and engineering data demonstrate with reasonable certainty to recoverable from known fields under existing economic and operating conditions. Proved reserve estimates calculated with this definition are typically conservative. The modeling approach used by the USGS to characterize `field growth phenomena' is statistical rather that geologic in nature.
Carbon dioxide (CO 2 ) enhanced oil recovery (EOR) may be the key to recovering hundreds of millions of bbl of trapped oil from the mature fields in central Kansas. Preliminary economic analysis indicates that CO 2 EOR should provide an internal rate of return (IRR) greater than 20%, before income tax, assuming oil sells for \$20/bbl, CO 2 costs \$1/Mcf, and gross utilization is 10 Mcf of CO 2 /bbl of oil recovered. If the CO 2 cost is reduced to \$0.75/Mcf, an oil price of $17/bbl yields an IRR of 20%. Reservoir and economic modeling indicates that IRR is most sensitive to oil price and CO 2 cost. A project requires a minimum recovery of 1,500 net bbl/acre (about 1 million net bbl/1-mile section) under a best-case scenario. Less important variables to the economics are capital costs and non-CO 2 related lease operating expenses.
This article is a summary of Arizona geological survey circular 29, which addresses the petroleum geology of Arizona, USA. Eight areas have been identified with fair to excellent oil and gas potential, and some Tertiary basins have evidence of source or reservoir rocks. The following are considered here: production history, lands status and services, regulation and permitting, petroleum geology, hydrocarbon indications, and areas with hydrocarbon potential and their petroleum geology and characteristics. The full report contains detailed figures of each of these basin areas, a descriptive tabulation of seeps and petroliferous rocks and extensive references.
Massive salt formations and their proximity to pipeline systems and power plants make Arizona attractive for natural gas storage. Caverns dissolved in subsurface salt are used to store LPG at Ferrellgas Partners LP facility near Holbrook and the AmeriGas Partners LP facility near Glendale. Three other companies are investigating the feasibility of storing natural gas in Arizona salt: Copper Eagle Gas Storage LLC, Desert Crossing Gas Storage and Transportation System LLC, and Aquila Inc. The most extensive salt deposits are in the Colorado Plateau Province. Marine and nonmarine salt deposits are present in Arizona.
Coalbed gas from Middle Pennsylvanian rocks in eastern Kansas is an emerging new energy play. Many of the critical geological parameters that will prove to be the major controls on the production fairways of this potential new resource have yet to be determined. Nevertheless, preliminary analyses indicate that recent leasing and exploration may translate into long-term production of new gas resources in what was hitherto considered a supermature petroleum province.
Temperature anomalies associated with oil-producing structures in the US Midcontinent and similar cratonic areas probably can be used reliably as a passkey for petroleum exploration in mature areas, and thus the concept of hot anticlines could be a key to discovery. Analysis of accumulated data during the past several decades allows a definition of the problem of hot anticlines. A possible solution for migration and entrapment of petroleum can be explained by the Roberts temperature differential model and the Walters fluid-flow paradigm. In fact, if the Roberts model is valid, higher shallow temperatures, temperature gradients, or heat flow could indicate the entrapment of hydrocarbons at depth. The recognition and promotion of shallow "hotspots" as an exploration key is not new and was proposed years ago by Haas and Hoffmann, Kappelmeyer, and as recently as 1986 by Blackwell.
The US Geological Survey (USGS) periodically conducts subjective probabilistic assessments of the technically recoverable undiscovered hydrocarbon resources of the US and of the world. In addition, the USGS prepares forecasts of that portion of the technically recoverable resources that may be economic under specified conditions of supply, demand, and price. Depending on priorities, regional hydrocarbon assessments of the US are revised every 5 to 10 years. These assessments of undiscovered hydrocarbons supplement the data on hydrocarbon reserves that are reported annually by the US Department of Energy, Energy Information Administration. In between assessments, USGS assessment geologists conduct research and compile geologic and production data that may be used to improve future assessments. This new information commonly effects changes in the way the USGS defines "plays" or "assessment units" from assessment to assessment. Furthermore, USGS assessment methodology is in a constant state of evolution and changes to some degree from assessment to assessment.
The last 20 yr of the Rocky Mountains oil and gas exploration and production business have been turbulent. Most of the major companies have left; they have been replaced with, independents and small to larger private and public companies. Natural gas become the primary focus of exploration. A discussion covers the shift of interest from drilling for oil to gas exploration and development in the Rockies since 1980; resource pyramid, showing relative volumes, reserves, resources, and undiscovered gas; the Wyoming fields that boost US gas supply, i.e., Jonah (6-12 tcf), Pinedale Anticline (10-20 tcf); Big Piney-LaBarge (15-25 tcf), Madden (3-5 tcf), and Powder river (24-27 tcf); and the future.
Crude oil, natural gas and natural gas liquids/condensate resources are important for the redevelopment of Afghanistan's infrastructure. Improved living and economic conditions in Afghanistan require increasing the availability of energy particularly by exploitation of Afghanistan's petroleum resources. The four total petroleum systems are subdivided into units with homogeneous geologic traits and exploration efforts that include sufficiently homogeneous field-size populations for resource assessment. The greatest volume of undiscovered crude oil is estimated to be in the Afghanistan Eastern Suprasalt Thrusts and Folds Assessment Unit. The greatest volume of undiscovered natural gas is estimated to be in the Afghanistan Jurassic Evaporite Basin Subsalt Carbonates Assessment Unit.
Petroleum reserves are classified for the assessment of available supplies by governmental agencies, management of business processes for achieving exploration and production efficiency, and documentation of the value of reserves and resources in financial statements. Up to the present however, the storage capacity determinations made by some organizations in the initial CO2 resource assessment are incorrect technically. New publications should thus cover differences in mineral adsorption of CO2 and dissolution of CO2 in various brine waters.