Predicting Reserves and Forecasting Flow Rates Of Relatively Tight Gas Wells Using Limited Performance Data
- E.N. Bennett (Amoco International Oil Co.) | C.D. Forgerson (Amoco Production Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- May 1975
- Document Type
- Journal Paper
- 543 - 551
- 1975. Society of Petroleum Engineers
- 1 in the last 30 days
- 399 since 2007
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A method for obtaining original gas in place and reserves for relatively low liquid-recovery wells in volumetric gas reservoirs is presented. The method uses semisteady-state flow-test data and current gas reservoir engineering technology, along with a stabilized backpressure curve.
Current energy requirements and the increased value of gas provide favorable economics for drilling and completing relatively low-permeability gas reservoirs previously evaluated as uneconomical.
The increased need for natural gas reserves requires accurate estimates of gas in place and of reserves early in the life of a well for evaluating offset development or in-fill drilling, economic well spacing, and design of proper facilities for collecting and distributing the gas. proper facilities for collecting and distributing the gas. Much effort has been directed to estimating the gas initially in place and to predicting well performance. The increased demand for natural gas has resulted in active development of new reserves in relatively tight, low-permeability reservoirs (0.05 to 0.5 md). Most previous studies have dealt with calculating steady-state pressure distribution and stabilized interwell flow data with data collected during unsteady-state conditions.
With the current demand for gas, most wells in relatively tight gas reservoirs are flowed almost continuously. Therefore, relatively long-term flow data, using the techniques in this study, should provide a better approximation of semisteady-state conditions than would a short-term shut-in pressure. Collection of pressure data requires longer shut-in times, resulting in loss of current income from gas sales.
The most commonly used methods for estimating original gas in place (OGIP) and expected reserves are the pore-volume volumetric determination and the material-balance method. The volumetric calculations are usually based on limited valid parameters, especially the drainage area, and for tight reservoirs, parameters, especially the drainage area, and for tight reservoirs, these reserve calculations may not be realistic approximations.
The best method for determining OGIP and reserves for wells completed in relatively tight gas reservoirs is the material-balance method. This method involves plotting measured or calculated static pressures (either bottom-hole or surface wellhead pressures) for relatively low liquid-recovery wells, corrected for compressibility, vs cumulative production reported at standard conditions. The study discussed in this paper is not applicable to a water drive reservoir or where there paper is not applicable to a water drive reservoir or where there is a significant change in pore volume caused by rock compressibility.
Most pressure data available on gas wells are pressures obtained after 24 to 72 hours of shut-in time. Unfortunately, for low-permeability reservoirs, this shut-in time is insufficient for obtaining a true static pressure. A plot of the short-term nonstatic pressures corrected for compressibility vs cumulative production over pressures corrected for compressibility vs cumulative production over the early history of the well results in an initial extrapolation of low estimates of OGIP and reserves, as shown in Fig. 1. The relatively short-term pressures obtained during the latter life of the well usually define another slope, and it is a common practice to extrapolate this slope to define estimates of OGIP and reserves. However, these extrapolations may not always be valid, since there are many instances where the second slope indicates little, if any, pressure decline. pressure decline. JPT
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