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In the past, solutions to many well test problems considered the well to be produced at constant rate. While still so in many cases, the constant rate production is difficult to maintain. Gas wells, producing through separators at the wellhead or constant back pressure, in corporate constant pressure behavior. Also during large portions of the production life of tight reservoirs, wells produce at constant bottomhole pressure rather than at constant rate.
Several methods have been proposed in the literature for analyzing pressure behavior in vertically fractured wells producing at constant pressure. In most cases type curve producing at constant pressure. In most cases type curve analysis was presented as the only valid approach for obtaining solutions. In these cases, however, unique solutions are difficult to obtain.
In the present study semi-analytic solutions are presented for unsteady-state flow behavior of a well intersecting a vertical fracture. Analytic solutions are also presented for defining certain portions of the early time data for various types of fracture conductivity. A graphical technique is provided to analyse rate data by plotting a graph of 1/q versus provided to analyse rate data by plotting a graph of 1/q versus 4/t to yield a straight line with a slope which is proportional to the fracture conductivity. An example is presented to illustrate this technique.
New analytical pressure-transient solutions for a horizontal well intersecting multiple random discrete fractures in both an infinite and a bounded reservoir are presented. The horizontal well is assumed to penetrate multiple randomly distributed vertical fractures. The infinite reservoir Containing the horizontal well is bounded at the top and at the bottom. For the case of a bounded reservoir, all exterior boundaries are non-flow boundaries. New source functions for a random vertical fracture are first derived. The pressure-transient solutions are then obtained using the derived source functions, as well as superposition principles. A uniform flux is assumed along all fracture faces. An averaging technique is used to approximate the wellbore pressure.
The new solutions provide a theoretical basis for the analysis of the pressure transient behavior of a horizontal well intersecting multiple random discrete fractures. Different flow regimes are identified. The effects of fracture characteristics, such as fracture orientation and length, on the pressure transient behavior of a horizontal well are investigated. New evaluation techniques using the derived pressure-transient solutions can be developed to determine reservoir properties and fracture characteristics from horizontal well test data.
A hydraulic fracture treatment is the most common method used to stimulate the gas flow rate of a well completed in a low permeability gas reservoir. Hydraulic fracturing is accomplished by pumping a proppant laden fluid into the formation at high injection rates. Once the minimum principle stress in the formation is overcome, a fracture is induced and principle stress in the formation is overcome, a fracture is induced and begins to grow. The vertical fracture will continue to grow until pumping is stopped. After the fracture treatment, fracture fluid will leak off and imbibe into the formation around the fracture as the fracture closes. After the fracture has closed, the well will be placed on production in order to clean up the fracture fluid around the fracture and begin producing gas. producing gas. Prior to performing a hydraulic fracture treatment, a complete reservoir description should be developed by the engineer and geologist. The reservoir description should include properties such as formation permeability, porosity, net pay, reservoir pressure, skin permeability, porosity, net pay, reservoir pressure, skin factor, and other information needed to properly describe oil and gas flow from the reservoir.
In addition, the mechanical properties of the formation layers above and below the productive zone should be evaluated. The mechanical properties are needed to compute the estimated shape properties are needed to compute the estimated shape and dimensions of the hydraulic fracture that will be created. After the reservoir description has been completed, the hydraulic fracture treatment can be designed and pumped. During the fracture treatment design, the engineer should optimize the fracture length and the fracture conductivity based upon the pre-fracture reservoir description. In order to improve the productivity of future wells, each existing well should be analyzed after the fracture treatment to determine how to improve the fracture treatment design.
The best method of evaluating the hydraulic fracture is to run and analyze a post-fracture pressure buildup best. It is well known that analyzing post-fracture pressure transient tests can be very difficult. Even if only a single-phase fluid is flowing, the analysis of the data can be complicated. It can be difficult to determine unique values for formation permeability, fracture half-length, and fracture conductivity. The evaluation of these parameters can be complicated even more if fracture fluid cleanup is impaired by factors such as damage around the fracture and proppant crushing in the fracture, due to closure stress. Only by combining a rigorous engineering effort with a complete formation evaluation prior to the stimulation treatment can one properly evaluate a well containing a vertical hydraulic fracture.
If the reservoir produces substantial volumes of either fracture fluid or formation water, along with oil and gas, the analysis of post-stracture behavior becomes even more complex. The use of a post-stracture behavior becomes even more complex. The use of a three-phase, three-dimensional model maybe required to rigorously analyze all production data. In addition, producing pressures and pressure buildup (PBU) test data are required for a thorough understanding of both the reservoir and the hydraulic fracture.
In general, most operating companies do not spend the money nor the time to gather and analyze the data needed to properly characterize the hydraulic fracture. Occasionally, an operating company will run a post-fracture pressure buildup test. However, if that test is not run long post-fracture pressure buildup test. However, if that test is not run long enough or analyzed properly, the results may not be meaningful.
The objectives of this paper are to present information concerning (1) how fracture fluid invades the formation around the fracture, (2) the factors that affect fracture, fluid cleanup, (3) when a post-fracture pressure buildup test should be run to obtain useful data, and (4) how to pressure buildup test should be run to obtain useful data, and (4) how to best analyze post-fracture pressure buildup data to obtain the most accurate estimates of formation permeability, fracture half-length, and fracture conductivity.
FIELD DATA ILLUSTRATING THE PROBLEM
Field data from several GRI wells that exhibited slow cleanup are presented to illustrate the problem. The wells are completed in either the Travis Peak or the Cotton Valley formation in East Texas. The cleanup performance of these wells was monitored very closely after the hydraulic performance of these wells was monitored very closely after the hydraulic fracture treatment. All of these wells exhibited slow fracturing fluid cleanup. These field data provide information on early cleanup performance, which is not usually measured in the field nor reported in the performance, which is not usually measured in the field nor reported in the petroleum literature. The data on cleanup performance is, however, petroleum literature. The data on cleanup performance is, however, important in determining the fracture properties and estimating the long-term well performance.
Abstract The purpose of well stimulation is to increase the contact area of the wellbore in the reservoir to maximise production rates. This is achieved through fractures penetrating the reservoir. These fractures tend to show either infinite conductivity with double lines half slope or finite conductivity with quarter slope on the log-log plot of pressure change versus elapsed time depending on the permeability and other parameters of the formation. These flow behaviors are clear indications of a stimulated well. However, observations in some post frac tests where a single slope line is reported indicate non-fractured well response. The objective of this paper is to investigate the unusual flow behavior associated with fractured well tests following a proppant frac job. To author’s knowledge, this behavior has been referred to briefly in a limited number of publications with no clear explanation. The aim of this study is to address this problem in detail and suggest that this behavior is due to a variety of reasons assuming the frac job has targeted the reservoir interval of interest. The controlling factors are fracture lengths, fracture conductivity, the damage caused by the fracture operation including choke fracture effect and less importantly, fracture face skin and non-Darcy effect in the case of gas wells. The study utilizes 3-D numerical simulation black oil and compositional models comprising of single and multi- layered reservoirs. Study results show that the investigated problem is likely to be associated with damaged fractures of short lengths and low fracture conductivity values. Knowledge obtained from the study is applied to the analysis of well tests from actual fractured wells. The importance of this paper is that understanding the behavior of fractured wells is important to operator and service companies.
This paper was prepared for presentation at the 1999 SPE Annual Technical Conference and Exhibition held in Houston, Texas, 3–6 October 1999.