Induced Fracture Complexity - When is it Needed?

This is a synopsis of SPE 168976 (Sierra, L & Mayerhofer, M). In typical horizontal completions induced fracture complexity is clearly beneficial for the productivity of nanodarcy shales. Reservoir simulations for a range of reservoirs of permeability 10 nd to 1 microdarcy (0.001 millidarcy) help establish the criteria necessary for fracture complexity. Results show that fracture complexity – with complex (secondary) fracture conductivity in range of 1 to 5 mdft – is generally essential for reservoir permeabilities less than 100 nd for gas and 500 nd for liquids.

For low permeability reservoirs increasing the contact of the pay-zone with the wellbore is critical to economically produce the hydrocarbons. Typical methods used are the drilling of long horizontal wellbores, optimizing the landing depth to maximize vertical coverage, perforating the most brittle sections and engineering stimulation fluids to induce complex fracturing.

Fig 1: Setup showing the primary fracture and fracture complexity (transverse to primary fracture)

Simulations were performed with fracture complexity represented as branching fractures with 1 – 5 mdft conductivity distributed transverse to the primary planar fracture in reservoirs at different permeability levels (Fig 1). A fracture complexity ratio (FCR) was defined as the total length of orthogonal branch fractures/2Xf. FCR ranges from 0.25 to 3.33 were studied. Reference initial fracture conductivity was considered using 40/70 mesh and effective stress of 2500 psi with decrease in conductivity with increasing effective stress. A stimulation efficiency (SE) was also defined as Connected Fracture Volume (CFV)/Gross Reservoir Volume (GRV). An SE of 1 implies that all perforation clusters have identical fractures while an SE of 0.5 implies that only 50% of the perf clusters have a created fracture.

Original simulations with just the planar fractures were performed and a Recovery Factor (RF) vs time in days was plotted for both oil and gas reservoirs with representative properties. Curves were obtained as a function of SE and reservoir perm so that for any un-simulated case, the RF could be obtained simply by knowing reservoir perm, SE and time in days. The effect of induced fracture complexity was evaluated by adding FCR to the previous planar simulations. The increase in RF for both oil and gas reservoirs as a function of SE, time, reservoir perm, and FCR was obtained and displayed as plots. Plots of the increase in RF for varying reservoir perm are shown in figure 2.

Fig 2: Incremental Recovery Factor for different reservoir permeabilities for Gas (left) and Oil (Right)

The primary benefit is acceleration in recovery and for this study a benchmark of performance at 6000 days is taken. For gas reservoirs a meaningful benefit of induced fracture complexity (more than 10% increase in RF) is obtained upto a perm of 100 nd. For oil (more than 2.5% increase in RF) the reservoir perm is about 500 nd. Of course, for reservoir with perms lower than these the benefits of increased fracture complexity are greater. More details of this study are available in the paper (SPE 168976).