This paper presents a new method for history matching production of shale gas wells and future forecasting. The method is based on linear dual porosity analytical solutions which includes horizontal wells with multistage fractures. A linear dual-porosity model assumes hydraulic fractures as a secondary porosity system and conduit to flow. Homogeneous matrix blocks are sources of primary porosity that feed fluids to the hydraulic fractures. A Systematic analysis was done to determine the main parameters affecting transient flow regimes. Since main flow regimes observed in the field are Bilinear and Linear, more attention was given to those regimes to match with the field data. Analytical solutions are modified for gas properties and desorption of gas from matrix surface. Besides constant bottomhole pressure production, variable bottomhole pressure cases are also included in this paper. The proposed method was applied to history match the production of shale gas wells from the Barnett, Woodford, and Fayetteville plays. The main parameters found from history matching are effective matrix and fracture permeabilities and fracture half-length. In wells with successful matches, future production can be forecast with some confidence.

As interest in exploiting shale gas/oil reservoirs with multiple stage fractured horizontal wells increased, complexity of production analysis and reservoir description have also increased. The main objective of this paper is to present and demonstrate type curves for production data analysis of shale gas/oil wells using a Dual Porosity model.Dual Porosity model is based on Bello and Wattenbarger's (2010) mathematical model where hydraulic fractures act as a secondary porosity system where matrix is the primary porosity system. Samandarli et al. (2011) showed application of this model on history matching and forecasting of shale gas wells with multiple fractures by doing regression on effective fracture and matrix permeability and half length. This type of regression is as rigorous as simulation, however much faster than it. On the other hand for "quick look interpretation" having type curves will make the production analysis even more convenient for practical purposes.With this method production of shale gas/oil well can be matched with developed type curves which vary with effective permeability. Once the production data is matched with one of the type curves, effective permeability and match points are recorded. By using dimensionless equations developed for Dual Porosity model fracture half-length can be determined. In order to use type curves, good estimate for effective porosity and matrix permeability should be predetermined.Type curves developed in this paper were applied to synthetic and field data examples. Early results show that method works well in determining effective fracture half-length which is the most important parameter in evaluation of stimulated reservoir volume (SRV).

Unconventional reservoirs, shale gas and oil for instance, have proven to be an important contributor to hydrocarbon production in North America. Horizontal wells with multiple transverse fractures unlocked these unconventional resources by attaining profitable production rates and increasing gas reserves for future years. A critical challenge in these types of reservoirs is characterizing the stimulated reservoir volume (SRV), by estimating the effective productive volume created during stimulation and quantifying the permeability of the formation.Recent approaches for rate and pressure data deconvolution have emphasized the benefits of using buildup responses acquired whenever the well is shut-in, often for operational reasons, to assess significant insights about heterogeneity and compartmentalization in conventional reservoirs. However, deconvolution performs poorly when the initial reservoir pressure is unknown and might generate ambiguous results when pressure data accuracy is questionable.Regular measurements of daily production rates and wellhead flowing pressures can provide important information about well completion, stimulation, and formation parameters. With effective data processing, rate-normalized pressure (RNP) converts variable-rate and variable-pressure data to an equivalent of the drawdown pressure response to constant-rate production. This reveals flow regimes that enable direct estimation of the formation permeability and the productive fracture extent in the SRV. Subsequently, observed field rates and pressures can be matched with a global model to refine the estimates from the flow regime analysis. Although numerical models can be used to match the data, in this study we employed an analytical flow regime equations that provides fast and accurate results that can be easily programmed.The proposed methodology was applied to production data from Barnett shale wells providing excellent results and demonstrating an efficient, fast, and cost effective method to estimate critical well and formation parameters in unconventional reservoirs. The same methodology can be used to diagnose wells from other unconventional resources.