Pressure-Transient Performances of Hydraulically Fractured Horizontal Wells in Locally and Globally Naturally Fractured Formations

Abstract

Abstract This paper presents a discussion of diagnostic pressure and pressure-derivative plots for hydraulically fractured horizontal wells in locally and globally fractured formations. The discussions are based on pressure-transient responses generated by using a semi-analytical, heterogeneous reservoir simulator. Pressure-transient characteristics are discussed and documented. Performances of horizontal wells with longitudinal and transverse fractures are compared. It is shown that global and local natural fractures display distinct pressure-transient characteristics and, hence, significantly influence well performance. In general, conductive, interconnected natural fractures dominate the pressure-transient characteristics of horizontal wells in tight formations even in the presence of hydraulic fractures. Furthermore, the results also indicate that if the reservoir is naturally fractured, hydraulic fracturing might not improve productivity significantly, unless large hydraulic fracture conductivities can be achieved. Finally, if there is a significant contrast between the effective permeabilities of local natural fractures and surrounding homogeneous reservoir, it might be possible to estimate the volume of the naturally fractured region. Introduction Horizontal wells accelerate recovery and hence improve economics in a broad range of reservoir characteristics. In the last decade, horizontal wells have been instrumental in the development of unconventional reservoirs with very low permeability, such as tight gas sands and shales. When the matrix is tight, then economic production could be achieved if the horizontal well intercepts a natural fracture network. The fracture network might cover the entire reservoir or might be restricted to a smaller region around the horizontal well. The size and characteristics of the naturally fractured zone affect the pressure-transient response and performance of the horizontal well. Horizontal wells in tight formations are usually hydraulically fractured to increase the reservoir contact. These fractures may be created in transverse or longitudinal direction with respect to the horizontal well axis. The combination of artificial and natural fractures complicates the pressure-transient characteristics and productivity prediction of horizontal wells. Pressure-transient behavior of hydraulically fractured horizontal wells in tight, naturally fractured formations is important for two reasons. First, pressure-transient tests are instrumental to characterize both the reservoir and the hydraulic fractures. Complex interplay of the effects of horizontal well, hydraulic fractures, natural fractures, and tight matrix complicates the interpretation of pressure-transient responses. Therefore, for accurate interpretation of pressure-transient tests a thorough understanding of flow characteristics is essential. Second, the production of long, hydraulically fractured horizontal wells in tight formations takes place under transient flow regimes for long periods (Medeiros et al., 2007a). Therefore, the production performances of these wells are dominated by the characteristics of transient flow regimes. In this paper, we consider both global and local natural fractures around the well, as the latter is a common occurrence in tight-gas sands and shales. We base our discussions and conclusions on the pressure-transient responses generated by a semi-analytical model presented by Medeiros et al. (2006). After a brief introduction of the semi-analytical model, we will present, separately, the pressure behavior of horizontal wells stimulated with longitudinal and transverse fractures separately. We will also discuss the influence of natural and hydraulic fractures on pressure-transient characteristics for both cases. Finally, we will demonstrate the effect of local and natural fractures on pressure-transient behavior. A Semi-Analytical Model The semi-analytical model used in this work has been presented by Medeiros et al. (2006). The model is based on a boundary element approach derived from the Green's function solution of diffusivity equation in bounded, homogeneous porous media. The model divides the reservoir into regions (blocks) of internally uniform properties (in each block, properties are assumed to correspond to the local averages). The properties, however, can change from block to block to represent local heterogeneities. The blocks are coupled by assuming the continuity of pressure and flux at block interfaces.