Transient Tests and Long-Range Performance Predictions in Stress-Sensitive Gas Reservoirs
- J.F. Evers (U. of Wyoming) | E. Soeiinah (U. of Wyoming)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- August 1977
- Document Type
- Journal Paper
- 1,025 - 1,030
- 1977. Society of Petroleum Engineers
- 4.6 Natural Gas, 5.3.1 Flow in Porous Media, 1.6.9 Coring, Fishing, 5.5.2 Core Analysis, 5.6.4 Drillstem/Well Testing
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This paper investigates the use of a simplified stress characterization in the real-gas-potential expression and the application of "succession of steady states" techniques for test analysis and performance prediction in stress-sensitive reservoirs. The technique is shown to give good results with numerical data and with data from a laboratory model.
Rising prices and declining reserves have stimulated interest in deep, low-permeability gas reserves and have added a new dimension to the interpretation of transient pressure tests. How does the well-test engineer or pressure tests. How does the well-test engineer or reservoir engineer recognize and account for stress-sensitive permeability? Fatt et al. measured this stress sensitivity permeability? Fatt et al. measured this stress sensitivity about 25 years ago and several others have presented data during the intervening years; fortunately, however, the increase in effective overburden pressure with declining reservoir pressure is not an important flow-reducing mechanism for most wells. If we consider the net confining pressure or overburden pressure to be the total overburden pressure minus the pore pressure (an assumption we will justify later), Fig. 1 will show why this is true. A normally pressured reservoir at 6,000 ft would have a net confining pressure of about 3,000 psi at discovery and 5,500 psi at abandonment. The top curve in Fig. 1 shows a permeability change of 4 percent (from 0.81 to 0.78) and the lower curve shows a change of 14 percent (from 0.58 to 0.50). The latter number is becoming percent (from 0.58 to 0.50). The latter number is becoming significant and permeability changes near the wellbore would be even greater; however, when this effect is compared with other uncertainties over the 15- to 20-year life of a gas reservoir, it probably can be ignored. However, recent data on low-permeability gas sands show much greater permeability reductions (see Fig. 2). This, along with the possibility of abnormal pressures shifting the initial net confining pressure toward the left, creates a situation where permeability changes cannot be neglected. For example, if a reservoir represented by Fig. 2 was discovered with poB= 10,000 psia, pi= 8,000 psia, and pub= 1,000 psia, the change in confining pressure would be from 2,000 to 9,000 psia over the life of the field. The permeability change would be several-fold (0.6 to 0.2 for Core I and 0.3 to 0.05 for Core H).
Vairogs and Rhoades have used a numerical model to demonstrate the errors introduced into transient test analysis and long-term performance predictions. This paper attempts to simplify their theory and to eliminate paper attempts to simplify their theory and to eliminate the need for core data and a numerical model for making performance predictions. Data are presented from a performance predictions. Data are presented from a numerical model and a laboratory model to support the suggested techniques.
Three factors must be considered: (1) a mathematical characterization of stress sensitivity, (2) a nondimensional means for representing what is basically a threedimensional stress problem, and (3) modification of the real gas potential to include the stress-sensitive permeablility. permeablility. Permeability Characterization Permeability Characterization If we are to avoid the expensive process of obtaining laboratory, core data for every well, we must look for a means for characterizing a typical permeability reduction curve. Wyble suggested that the curves represent an exponential decline approaching a limiting value.
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