This paper presents a simple diagnostic tool to identify reservoir flow behavior from a Cartesian pressure/rate graph. Some of the benefits of the proposed tool are its simplicity without requiring any calculations, leading to understanding of reservoir compartmentalization and application of an appropriate material-balance technique.

Data diagnosis entails graphing pressure with rate and discerning trends; positive slope signifies the pseudosteady-state (PSS) flow period, whereas the negative slope implies infinite-acting (IA) flow. Constant-rate production exhibits infinite slope whereas constant-pressure production produces zero slope. Mathematical justifications for these diagnostic signatures are presented. During PSS flow, wells belonging to the same container will exhibit the same slope.

Differences in slope are an indication of reservoir compartmentalization, lateral or vertical. Equally important we provide mathematical proof of why different wells in a multiwell reservoir system should have the same slope. Field examples from multiple gas and gas/condensate systems show how the proposed tool works in practice.


With increasing usage of permanent downhole and/or surface sensing, the need for simple diagnostics becomes imperative so that actions can be taken just in time for reservoir management. Studies have shown that motivations for real-time sensing revolve around on-time action to maximize benefits.

Various analysis techniques exist to analyze production rate data for estimating in-place fluid volume and remaining reserves. These methods entail from traditional decline curve analysis, such as those offered by Arps (1945) and Fetkovich (1980) to more sophisticated techniques (Agarwal et al. 1999; Blasingame et al. 1991; Blasingame et al. 1989; Mattar and McNeil 1997) involving both flowing bottomhole pressure and rate. Most of these methods apply to single wells in volumetric reservoirs producing single-phase fluids from a fixed drainage boundary. Mattar and Anderson (2003) provide a comprehensive treatment of the pertinent methods. Analytic methods (Marhaendrajana 2005; Marhaendrajana and Blasingame 2001) have also been proposed to handle well interference in multiwell reservoirs. Gringarten (2005) showed that the reservoir-compartmentalization question can be addressed by deconvolving simultaneously measured pressure/rate data for wells across a perceived fault barrier. Multidisciplinary approach has also been reported to address the compartmentalization question (Bigno et al. 1998).

Changes in well performance may often be attributed to condensate banking, reservoir subsidence, fines migration precipitating changing skin, and a host of completion and/or wellbore-lift issues, besides depletion. Our challenge is to decipher the real reason for premature production decline. In this regard, Anderson and Mattar (2004) offer a few diagnostic clues about wellbore loading and changing skin, changing well productivity, and identifying external pressure support or interference.

This study offers a simple methodology to diagnose long-term well performance, especially those that are influenced by outer boundaries. In particular, whether wells belong to the same or different compartments become quite evident. Because we are solving an inverse problem, independent methods must be used to eliminate potential reservoir, wellbore, and surface flowline network issues before reaching reasonable conclusions. Mathematical proofs are presented in support of the contentions presented in this study.

Theoretical Considerations

When production is initiated in a well, various flow regimes are encountered as transition from IA to PSS flow, with possible intervening transitional flow, occurs. Fig. 1 schematically depicts such a scenario on a Cartesian pwf-q graph. Of course, the size of the connected-pore volume (CPV) within a well's drainage boundary and the rate of fluid withdrawal dictate the decline rate during PSS flow in a closed system.

One complicating factor during the boundary-dominated flow is a well's ever-changing outer boundaries precipitated by changing rates of neighboring wells, drilling infill wells, injecting fluids, and encroaching aquifer, to name a few. For a perspective, Fig. 1 is intended as a practical diagnostic tool in a closed system for reservoirs with significant mobility producing gas or oil, and is not intended for tight-gas reservoirs.

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