Abstract
Hydraulic fractures play a central role in performance of multi-stage fractured horizontal wells (MFHW) in tight and shale reservoirs. Fracture conductivity variations and connection quality between fractures and wellbore (i.e. the choking skin) strongly affect well productivity. However, convincing and high-quality evaluation of hydraulic fractures for these reservoirs is scarce in literature because quantifying the fracture properties requires de-coupling them from fracture geometry and formation properties, which is difficult in most field conditions. A data gathering and hypothesis testing program was implemented using six multi-fractured horizontal wells in a pad in Delaware basin to improve our ability to reliably forecast well performance. A systematic approach utilizing production, shut ins, and bottom-hole pressure measurements (BHP) was conducted and used to evaluate the apparent flow capacity of hydraulic fractures. Two independent techniques were used in the data analyses. Pressure transients for individual wells and significant well-to-well interference signals are used to characterize the hydraulic fractures, respectively. Both techniques render similar decline rate interpretations for the sets of fracture conductivity/permeability from analysis of the pressure data, but the uncertainty of the estimated results from these two methods have large difference.
The first method used the radial-linear flow regime in successive pressure buildups in three of the six wells. Simulations and theoretical analysis show that this flow regime allows de-coupling fracture conductivity from fracture geometry and matrix properties. This flow regime yields the total apparent fracture conductivity (TAFC), which represents the lump sum effect of fracture conductivity. In addition, this technique characterizes the connection condition between the dominant fractures and bore-hole, which can be estimated from the early derivative horizontal line in pressure transient log-log diagnostic plot with minimum assumptions. Specifically, the estimated total apparent fracture conductivity ranges from 1140 – 1630 md*ft at early time of well life to 525 – 855 md*ft after 100 – 139 days in production, or about 45% to 61% reduction among these wells.
The second method uses time-lag of pulse interference response between an active and an observation well. With assumptions of low, mid, and high values of fracture porosity, fracture compressibility and fluid viscosity, characteristic fracture permeability can be estimated. Because of the large uncertainty related to the assumed fracture porosity and fracture compressibility, the pulse interference method is not likely to deliver the same certainty range as successive pressure buildups using the radial-linear flow regime.
The results of this work provide better understanding of the mechanisms of flow transport inside hydraulic fractures and at the connection between hydraulic fractures and wellbore. The estimated TAFC and its significant decline help improve hydraulic fracturing designs and build representative reservoir models for more reliable well performance modeling and forecasting.
