Determining Well Drainage Pore Volume and Porosity From Pressure Buildup Tests
Authors: Denson A.H. , Smith J.T. , Cobb W.M. 
Published: December 2007

Abstract
Well drainage pore volume and effective porosity can be determined using the results of a pressure buildup test. The procedure uses theoretical, dimensionless Horner type curves to analyze the buildup test data. Limitations and applications of the procedure are discussed, and an example is given.

Introduction
Knowledge of the well drainage pore volume and effective porosity of a reservoir is of vital importance to the petroleum engineer. These values, when combined with the associated hydrocarbon saturation, are necessary for estimating the reserves of a particular reservoir. Furthermore, these reserves are particular reservoir. Furthermore, these reserves are used to plan additional wells, to establish operating procedures, and to study the feasibility of various procedures, and to study the feasibility of various enhanced recovery processes. The need for an accurate value of the hydrocarbon pore volume is obvious.
The use of geologic and well logging data to estimate both effective porosity and well drainage pore volume is well established. Unfortunately, pore volume is well established. Unfortunately, these methods are limited to a determination of rock properties at or near the wellbore. Accordingly, many important decisions affecting reservoir performance are based on information that performance are based on information that represents, at best, a minute fraction of the total reservoir system. A method of analysis that encompasses a larger portion of the reservoir is clearly needed.
It has long been recognized that the pressure response of a well following a disturbance in flow rate is indicative of the reservoir properties within the drainage volume of the test well. This idea has led to the development of several types of transient pressure tests that can be used to determine, among pressure tests that can be used to determine, among other things, the average permeability and volumetric average pressure associated with the well. Unfortunately, the effect of porosity on pressure response is not as explicit as the effect of permeability. Consequently, only moderate success has been achieved in calculating porosity from the results of a pressure test. The pressure drawdown test is currently the only transient pressure test commonly used for obtaining well drainage pore volume.
Although the pressure drawdown test offers the advantage of surveying a large fraction of the well drainage volume, its application is severely restricted by a number of factors. First, this test must be conducted for a longer time than that necessary to achieve pseudosteady state within the drainage volume of the well. The producing time required to meet this condition, particularly in low-permeability reservoirs, often makes the test impractical. Second, the test requires that a constant flow rate be maintained. From an operational standpoint, this can be very difficult for the long test times required. Third, for large drainage volumes the rate of pressure change may be too small to measure during the pseudosteady-state flow period. This is a major limitation since the pore volume is inversely proportional to the rate of pressure decline. Finally, if the reservoir is in communication with an aquifer, the test will give optimistic and misleading results. Therefore, this method has very limited application in the determination of reservoir pore volume. The design and analysis, as well as the limitations of the pressure drawdown test have been detailed in the pressure drawdown test have been detailed in the literature.
A more versatile and commonly used transient pressure test for evaluating reservoir properties is pressure test for evaluating reservoir properties is the pressure buildup test. The two methods most commonly used to evaluate pressure buildup tests were published by Horner and Miller et al. Horner showed that plotting buildup pressure vs the logarithm of the time ratio, (t + delta t)/delta t, yields a straight line with slope inversely proportional to the average formation permeability. Horner assumed an infinite reservoir to develop his method of analysis.
SPEJ
P. 209