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Abstract
Performance prediction of wells producing from tight microdarcy formations is a daunting task. Complexities of geology (the presence/absence of naturally occurring fractures and contribution from different lithological layers), completion and fracture geometry complexities (multiple transverse and/or longitudinal fractures in long horizontal boreholes), and two-phase flow are impediments to simple performance forecasting.

We demonstrate the use of various analytical and numerical tools to learn about both short- and long-term reservoir behaviors. These tools include (a) traditional decline-curve analysis (Arps formulation), (b) Valko’s stretched-exponential method, (c) Ilk et al’s power-law exponential method, (d) rate-transient and transient-PI analyses to ascertain the stimulated-reservoir volume, and (e) numerical simulation studies to gain insights into observed flow regimes.

The benefits of collective use of analytical modeling tools in history-matching and forecasting both short- and long-term production performance of tight-oil reservoirs are demonstrated with the use of real and simulated data. Diagnosing natural fractures, quantifying stimulated-reservoir volume, and assessing reliability of future performance predictions, all became feasible by using an ensemble of analytical tools.

Introduction
Production data analysis for tight or unconventional reservoirs has gained considerable interest as development of some unconventional oil reservoirs has accelerated over the past few years. Various methods have come to the fore to understand the decline behavior and the ability to forecast performance from data of various quality and quantity. Methods espoused by Ilk et al. (2008, 2010), Valko (2009), and Valko and Lee (2010) offer excellent modern analysis techniques for long-term performance forecasting. Because of relatively high uncertainty associated with estimating expected ultimate recovery (EUR), a continuous-EUR method has been proposed by Currie et al. (2010). In fact, systematic approaches (Rushing et al. 2007) have emerged for handling life-cycle reserves appraisal. Tight gas has been the focal point of interest in these studies.

Besides the usual complexities associated with completion and geologic uncertainty, oil reservoirs present another dimension to forecasting challenge when two-phase flow becomes part of the production mechanism. Some studies have reported successful drilling, stimulation, and operational strategies in the tight-oil reservoirs. Studies of Warpinski et al. (2008) and Besler et al. (2007) are cases in point. Detailed studies of Cipolla et al. (2009) in shale-gas reservoirs suggest that stress-dependent network fracture conductivity can have adverse effect on recovery factor. However, very few studies have reported performance of primary production and modeling.

In this study, we attempted to assess the long-term forecasting ability of various empirical methods that are applied in tight-gas wells. These methods include Arps (1945), Ilk et al. (2008, 2010), and Valko (2009). To gain insights with various tools, we started with a synthetic example, where the solution is known beforehand. Thereafter, four field examples were examined to represent different degrees of production maturity. In these cases, we estimated the apparent in-place volume associated with each well using various analytical tools before applying the forecasting methods. In terms of analytical tools for estimating in-place volume, we used the transient-PI (Meidiros et al. 2010), rate-transient analysis (Palacio and Blasingame 1993), and pressure-derivative to ascertain apparent closed-reservoir boundary, which is associated with stimulated-reservoir volume or SRV.