Reservoir Limit Test on Gas Wells
Authors: Jones Park 
Published: December 2007

During a reservoir limit test, the rate of production is held constant and the bottom-hole flowing pressure is measured. Field examples for a closed reservoir, a sealing fault, a gas-water contact and a nonsealing fault are included. The interpretation of field data is made with the aid of the observed rate of pressure decrease per unit rate of production. Graphs and equations are presented for the pressure interferences commonly found in gas reservoirs. The thousand cubic feet of gas in place proved and possibly explored during a reservoir limit test, the distance to a fault, the angle between two intersecting faults, the interference from a gas-water contact, the evaluation of the formation constants and the effect of anisotropic permeability are considered.

Introduction

The reservoir limit test is a transient-flow method of evaluating in- place gas, productive limits and deliverability. Background for the test is threefold: the constant (psi/bbl) pressure decline for steady flow in a closed reservoir; the pressure interferences between wells under a transient flow condition as, for example, those in the paper by Elkins; and the Laplace transformation paper by van Everdingen and Hurst. Under a transient-flow condition, the constant pressure decline mentioned before is replaced by a constant drawdown increase. The drainage radius can be evaluated in the field by noting the time of arrival, at shut-in observation wells, of a perceptible drawdown from a producing well. The pressure interferences at a producing well caused by external boundaries can be duplicated by the method of images which was first applied to oil and gas production by Muskat.

Examples of Interpreted Field Data

Interpretations of field data on four wells are presented. Fig. 1A is for a well in a closed reservoir. All productive limits were reached during a one-day test. Fig. 1B is for a well near a sealing fault. The 10-day test on this well shows no productive limit other than the fault. Fig 1C is for a well near a gas-water contact. The test was stopped at 1.5 days due to the interference from water. Fig. 1D is for a well near a nonsealing fault. The test was stopped at the end of the first day of production because the rate of gas flow across the nonsealing fault was equal to the rate of production from the well. Additional reserves cannot be detected after the rate of leakage becomes equal to the rate of production. Interpretation of the field data obtained during a reservoir limit test is made with the aid of certain equations developed by Jones.

Coefficient of Expansion for Reservoir Gas

When a well is placed on production, a pressure drawdown is propagated into the reservoir, and the drainage radius for the well increases with time. The drawdown within the drainage radius causes the in-place gas to expand. The coefficient of expansion, for a gas is defined by

............................(1)

Solutions of Eq. 1 are plotted in Fig. 2 for 150F reservoirs, gas gravities from 0.6 to 1.05, and pressures from 1,000 to 15,000 psia. Similar data are available for 250 and 350F gas reservoirs. The Eg values were calculated from the compressibility factors of Brown, et al. The effective coefficient of expansion for high-pressure gas reservoirs includes the expansion of interstitial water and rock compressibility as listed in the Appendix.

JPT

P. 613^