Estimating the Recovery From an Average Well in a Tight Gas Formation
- S.A. Holditch (Texas A and M U.) | Z-S. Lin (Natl. Cheng Kong U.) | J.P. Spivey (S.A. Holditch and Assocs. Inc.)
- Document ID
- Society of Petroleum Engineers
- SPE Gas Technology Symposium, 22-24 January, Houston, Texas
- Publication Date
- Document Type
- Conference Paper
- 1991. Society of Petroleum Engineers
- 2.2.2 Perforating, 6.5.4 Naturally Occurring Radioactive Materials, 5.1.5 Geologic Modeling, 1.6 Drilling Operations, 5.5 Reservoir Simulation, 5.4.2 Gas Injection Methods, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 5.5.2 Core Analysis, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 5.8.1 Tight Gas, 2.4.3 Sand/Solids Control, 5.2.1 Phase Behavior and PVT Measurements
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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.
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.
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