The purpose of this paper is to provide a more relevant solution to the diffusivity equation than the conductive disc/zero potential flow (Exponential Integral) solution, especially for use in predictions of the time that is required for an interference effect to reach an observation well. After explaining the assumptions and theory behind the method, a direct integration of the radius of investigation will be presented, along with a physical explanation of what it is. While presenting multiple examples to support the theory, the results from Exponential Integral method for predicting interference arrival at an observation well will be compared. Finally, it will be demonstrated that the classic radius of investigation equation is more appropriate in interference/communication testing, and that rate, gauge resolution, and the total system pressure drop do not affect the arrival of the interference effect.

To reduce the capillary model to the traditional diffusion potential model one only has to declare that all initiating pressures have broken down. A theory or physical model is only as good as its performance. Experiment is the traditional approach to test a model. Every well test should be treated as an experiment. Blind testing compared with a standard is the traditional path to advancing technology. This requires a model to be run against geologic maps and geophysical images. In the case of a reservoir model, it must be judged against geology and a track record established.

Reservoir boundary information is gleaned from a steadyflowrate-drawdown test and/or a subsequent buildup following the steady flow period. Singularities are observed to be present in virtually all transient pressure data that can provide direct information about the limits around a well. Multiple limits can be detected discretely and described by distance from the well and angular shape at the point of contact. The input information required is pressure data acquired while flowing on a fixed choke, petrophysical properties from cores and electric logs, and fluid production rates and compositions during the flow period.

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Much of the technology developed in the oil industry today is the result of cooperative engineering research efforts between operating companies with a problem and a technology developer with a potential solution. Often all parties discover the unexpected in the course of making physical measurements. In this case, the data captured showed the advancement in time of the limit singularity associated with a gas/water contact. The purpose of this paper is to share knowledge that may be useful to other operators, particularly those with permanent pressure gauge completions in oil and gas wells, or those operators who may use precision pressure gauges to monitor the flowing tubing pressure of a gas well. The author's companies have engaged in joint reservoir evaluation efforts to resolve rapidly declining production behavior in gas wells. The efforts were based upon pressure transient well evaluations utilizing the capillary shock front theory to map the gas cap at the time of the test. Two examples are presented that illustrate water contact boundary progression just prior to the onset of water production in each of the wells. The joint efforts have resulted in a better understanding of how to use operational shut-ins to monitor gas/water contacts from the inception of flow to the point of water encroachment. The goals of this effort are to see the end coming and perhaps delay the end in order to maximize well production. The secondary goal is to predict the end so as to avoid unnecessary post mortem efforts to repair a well that has watered-out. The first case is a test of a deep well in Louisiana that was being evaluated for rapidly declining pressure and flow rate. The second well was offshore in the Gulf of Mexico that was being evaluated for geology and remaining reserves. The movement of the limit contacts over time is illustrated with a sequential limit mapping presentation. A second test is presented to show an overlay of two tests performed two weeks apart, just before the well watered out. Introduction Since the introduction of the first mechanical pressure gauge, pressure transient data has shown segmentation when plotted on a semi-log plot of pressure vs. log10 t. This led to early observations of specific abrupt changes in slope that were best described as mirror image wells or offset wells that appear to "turn on" when the boundary is contacted by the cone of influence. Often these singularity slope changes were noted as abrupt or "turning on a single data point." This was originally ascribed to friction in mechanical gauges. The advent of accurate electronic pressure gauges eliminated the argument for gauge friction and led to an investigation for other causes.