Currently, there is no direct method to quantify performance of a stimulation program after hydraulic fracture treatment. Stimulated Reservoir Volume (SRV) is widely used out of convenience; however, incongruities regarding SRV makes it difficult to ascertain fracture effectiveness. This paper presents a novel approach employing only production rate and pressure to derive the reservoir behavior and predict production performance to quantify hydraulic fractures using the Connected Reservoir Storage Model (CRSM), predicated on pressure diffusivity theory. The CRSM can predict the capability of a stimulation program by analyzing the normalized production rate and the normalized cumulative production. This paper proposes the utilization of the CRSM in lieu of SRV for multiple stage fracture characterization. CRSM directly characterizes the stimulation performance, only utilizing actual production which is free of subsurface uncertainties and can be used efficiently in characterizing the flow regimes and reservoir boundaries. The CRSM allows for the estimation of the efficiency of a stimulation program through production decline and reservoir pressure response from production data and is strongly physics-based. A real field shale gas production case will be used.
Unconventional reservoirs are reservoirs that require specialized recovery methods outside of conventional means to produce hydrocarbons efficiently and economically. The principal objective of completing unconventional reservoirs is to increase the effective surface area of the well to maximize production (Bybee 2011). Shale gas reservoirs are the focus of this study, which are usually characterized as a tight formation with very low permeability characteristics - generally on the order of 1 – 100 nd (Kim and Lee 2015). Shales contain organic content in high quantities and are the source rock as well as the reservoir. The gas is deposited in the pore space of the rock formations and some of the gas may be absorbed by the organic material within the source rock. The matrix permeabilities of shales have been an obscure characteristic to measure. As such, it is difficult to fully understand how gas migrates through the formation during production. Economic production cannot be achieved unless large conductive surface areas are created to allow for contact with the matrix, through existing complex natural fracture networks composed by natural fractures and hydraulic fractures (Warpinski et al. 2009). Currently, the physics governing shale gas reservoirs, specifically the flow characteristics in shales, is still not well understood, which poses a great challenge for accurately predicting shale gas performance. Explicit characterization of fracture networks is still an ambiguous science and cannot be determined with accurate precision; therefore, current ways to characterize fractures use direct far-field and direct near-wellbore methods, which consist of microseismic, tiltmeters, tracers, temperature logs and well testing theory (Clegg 2007). Both direct far-field and direct near-wellbore methods are respectable tools to help in the characterization of fractures; however, the technology for some of these methods is still undergoing development and may reveal diminutive information regarding the geometry of the actual factures. In addition, it should be emphasized that rock-mechanics only allows for the understanding of the likely crack-growth due to the heterogeneous nature of the rock formation and does not give meticulous characterization of a fracture (Stefik and Paulson 2011). Moreover, there are various in-direct methods in the literature that are used in direct fracture diagnosis for post-fracture well test analysis. Some classical approaches include the Gringarten type curve, (Gringarten et al. 1974), Agarwal type curve (Agarwal et al. 1979), Barker-Ramey type curve (Ramey Jr and Gringarten 1975) and Cinco-Ley type curve (Cinco et al. 1978) and many others. All these methods are used in some form to determine post-fracture analysis through constant production or bottom-hole flowing pressure, wellbore storage and have various applications in buildup and drawdown analysis. More recent developments in rate transient behavior regarding tight formations to allow for the quantification of hydraulic fracture treatment in the last decade has been conducted by (Pang et al. 2016) looking at actual to optimal designs of hydraulic fractures, numerical modeling of complex fracture patterns in tight formations (Olorode et al. 2013), trilinear flow solution to simulate pressure transient and production behaviors of fractured horizontal wells in unconventional shales (Brown et al. 2011), comprehensive studies of high performance fracture completions (Zhang et al. 2010) and comparison of fracture horizonal wells conducted by (Ozkan et al. 2011) to name just a few.