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Tight gas is the term commonly used to refer to low permeability reservoirs that produce mainly dry natural gas. Many of the low permeability reservoirs that have been developed in the past are sandstone, but significant quantities of gas are also produced from low permeability carbonates, shales, and coal seams. Production of gas from coal seams is covered in a separate chapter in this handbook. In this chapter, production of gas from tight sandstones is the predominant theme. However, much of the same technology applies to tight carbonate and to gas shale reservoirs.
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Obtaining and analyzing cores is crucial to the proper understanding of any layered, complex reservoir system. To obtain the data needed to understand the fluid flow properties, the mechanical properties and the depositional environment of a specific reservoir requires that cores be cut, handled correctly, and tested in the laboratory using modern and sophisticated laboratory methods. Of primary importance is measuring the rock properties under restored reservoir conditions. The effect of net overburden pressure (NOB) must be reproduced in the laboratory to obtain the most accurate quantitative information from the cores. To provide all the data needed to characterize the reservoir and depositional system, a core should be cut in the pay interval and in the layers of rock above and below the pay interval. Core from the shales and mudstones above and below the pay interval help the geologist determine the environment of deposition.
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SPE Members Introduction Many tight gas formations consist of numerous reservoir layers that are dispersed both vertically and laterally in a thick, complex sand dispersal system. A typical well will encounter layers of sandstone, siltstone, and shale. Depending upon the depositional and diagenetic history of the formation, these different layers of sandstone and siltstone can have significantly different values of permeability, porosity, and gas saturation. In many formations, like permeability, porosity, and gas saturation. In many formations, like the Travis Peak in east Texas, the Wilcox in south Texas, the Frontier in Wyoming, or the Mesa Verde in Colorado, a well can encounter over one thousand feet of sandstone layers that contain gas. These complex reservoirs can be very difficult to produce because of low permeability and poor lateral continuity of the productive layers. permeability and poor lateral continuity of the productive layers. In these complex reservoir systems, one needs to be able to forecast both flow rates and ultimate gas recoveries to properly predict the economics of developing the formation. An engineer predict the economics of developing the formation. An engineer must evaluate existing wells to obtain a distribution of reservoir properties. This distribution of reservoir properties, if properly properties. This distribution of reservoir properties, if properly interpreted, can be used to predict well performance and compute the economics of drilling additional wells in a particular geographic a tea. The knowledge of how reservoir properties are distributed is very important to the petroleum engineer. The most important properties are formation permeability, formation porosity, net pay properties are formation permeability, formation porosity, net pay thickness, and the areal size and distribution of the sandstone units. Once the distribution of these properties is known, one can determine the proper method of averaging these properties so that one can accurately predict the performance of additional wells drilled to this formation. The most important factor that controls the production of gas is the formation permeability. Assuming that gas-bearing layers of rock can be located and perforated, then the formation permeability will control the rate of gas flow and the cumulative gas recovered from a particular layer. Therefore, the distribution of permeability will control the distribution of reserves and the economics of producing a particular formation. producing a particular formation. fashion. We have analyzed several data sets from the Travis Peak formation in east Texas. These data sets illustrate typical distributions of permeability, porosity, and met pay thickness. The objectives of this paper are to discuss these distributions in detail and illustrate how one can apply reservoir simulation to estimate ultimate gas recovery from an average well in a tight gas formation. In our analysis, we are referring to the areal distribution of reservoir properties, such as permeability. We want to review these areal distributions and determine the proper "average" value to use in predicting gas flow rate and gas reserves per well. The primary factor we are considering is permeability. Obviously, permeability will vary from layer-to-layer in the vertical direction. To obtain an average permeability for a simple well in a layered formation, a thickness-weighted arithmetic mean value of permeability is the proper average. This value can be used in Darcy's Law to predict the flow rate for the well. However, after the average permeability for each well has been determined, one must then look at the areal distribution of permeability. The areal distribution is needed to predict the behavior of the "average" well in the formation. LITERATURE REVIEW One of the first companies that began specifically exploring for low permeability gas reservoirs was Canadian Hunter Exploration in Calgary, Canada. In 1977 and 1978, Jim Gray and John Masters published the concept of a resource triangle. Masters and Gray published the concept of a resource triangle. Masters and Gray stated that it is reasonable to suggest that most natural resources are distributed as in a triangle (see Fig. 1). The high grade deposits occupy the peak, the smallest part of a triangle. In general, as the grade of the resource decreases, the size of the resource increases. However, to produce gas from the lowest grade reservoirs, one needs high gas prices and better technology. Most geologists are familiar with the concept of large, low grade ore deposits vs. small, high grade deposits. However, most engineers and geologists are not so accustomed to thinking about oil and gas reservoirs in these terms. The resource triangle does clearly describe the gas resource in formations such as the Travis Peak in east Texas. P. 201
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- North America > United States > Texas > Travis Peak Formation (0.99)
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Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering. Introduction Tight gas is the term commonly used to refer to low-permeability reservoirs that produce mainly dry natural gas. Many of the low-permeability reservoirs developed in the past are sandstone, but significant quantities of gas also are produced from low-permeability carbonates, shales, and coal seams. In this paper, production of gas from tight sandstones is the predominant theme. However, much of the same technology applies to tight-carbonate and gas-shale reservoirs. In general, a vertical well drilled and completed in a tight gas reservoir must be successfully stimulated to produce at commercial gas-flow rates and produce commercial gas volumes. Normally, a large hydraulic-fracture treatment is required to produce gas economically. In some naturally fractured tight gas reservoirs, horizontal wells can be drilled, but these wells also need to be stimulated. To optimize development of a tight gas reservoir, a team of geoscientists and engineers must optimize the number and locations of wells to be drilled, as well as the drilling and completion procedures for each well. Often, more data and more engineering manpower are required to understand and develop tight gas reservoirs than are required for higher-permeability conventional reservoirs. On an individual-well basis, a well in a tight gas reservoir will produce less gas over a longer period of time than one expects from a well completed in a higher-permeability conventional reservoir. As such, many more wells (closer well spacing) must be drilled in a tight gas reservoir to recover a large percentage of the original gas in place compared with a conventional reservoir. Definition of Tight Gas Reservoir In the 1970s, the U.S. government decided that the definition of a tight gas reservoir is one in which the expected value of permeability to gas flow would be less than 0.1 md. This definition was a political definition that has been used to determine which wells would receive federal and/or state tax credits for producing gas from tight reservoirs. Actually, the definition of a tight gas reservoir is a function of many physical and economic factors. The physical factors are related by Darcy's law, as shown in the stabilized, radial-flow equation, Eq. 1, (Lee 1982).
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Tight gas is the term commonly used to refer to low permeability reservoirs that produce mainly dry natural gas. Many of the low permeability reservoirs that have been developed in the past are sandstone, but significant quantities of gas are also produced from low permeability carbonates, shales, and coal seams. Production of gas from coal seams is covered in a separate chapter in this handbook. In this chapter, production of gas from tight sandstones is the predominant theme. However, much of the same technology applies to tight carbonate and to gas shale reservoirs. Tight gas reservoirs have one thing in common--a vertical well drilled and completed in the tight gas reservoir must be successfully stimulated to produce at commercial gas flow rates and produce commercial gas volumes. Normally, a large hydraulic fracture treatment is required to produce gas economically.
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