We frequently hear that unconventional plays require massive amounts of stimulation to unleash hydrocarbon reserves, but how do we know if the number of fractures will result in the most profitable well design? Targeting the highest initial flow rate may not lead to the best economic outcome of a well development plan.
Recent developments in fracking technology have enabled year-over-year increases in fracking density for unconventional fields, and as a result we find that recently completed wells in unconventional plays show higher fracking density per well than older wells. This is the basic premise for the analysis that follows.
We can analyze how fracture density impacts the fluid recovery volume per well by examining Enno Peters’ excellent work published by OilPro in January and February 2017.
In the Niobrara Play (Fig. 1), we observe a tendency of higher oil recovery per well for recently completed wells with higher fracture density.
However, in the North Dakota, despite the higher initial flow rates from recently completed wells and the larger number of fractures, we can’t clearly observe a similar tendency.
These results suggest that reservoir and fluid conditions play an important role in defining the best fracture density in horizontal wells.
Today, a numerical well design software is available to simulate near wellbore coupling between reservoir and well completion architectures. With its use, we can accurately predict the performance of a specific well placed within a defined reservoir based on fluid conditions, number of fractures, gravel packs, and other characteristics. The use of numerical simulators can significantly reduce well development costs by eliminating the need to physically build several test wells before selecting the most profitable completion well design for the development plan.
Figure 3 below shows a 5-year production curve from a commercial well design simulator with the following theoretical reservoir and fluid parameters: Kh= 0.005 mD, Kv= 0.0015 mD, fluid= oil, viscosity=0.1 cp, Reservoir thickness= 150 ft, total compressibility= 1.5×10-5, a fixed downhole flow pressure, with a 7500 ft horizontal section inside a drainage area of 1200 ft x 9000 ft, and simulating several fracture densities.
The results show a large difference in produced volumes during the first 2 years when comparing wells with different fracture densities. However, the large differences decline rapidly over time until they become small by year 5. Despite the initial differences the overall production estimates for this well are not significantly impacted by the choice in fracking density.
Given these results, what is the optimal fracking density to maximize the well’s profitability? The most cost-effective completion choice can be identified by looking at the well’s cash flow estimates and the initial fracking cost based on fracture density.
Figure 4 shows similar production curves as the previous example, except for the reservoir permeability, which was reduced to: Kh= 0.0005 mD, Kv= 0.00015 mD.
These results show large differences in produced volumes throughout the period. In this case, it is clear that higher fracture density would significantly impact the well’s oil recovery volumes. Again, the most cost-effective completion alternative can be identified by the cash flow estimates and initial cost for each fracture density choice.
In unconventional field development, there is no “one solution for all cases”, or “the more fractures the better”, because a higher fracking density or the longer horizontal well does not necessarily result in the most profitable well.
Today, it is possible to identify a solution fit for each specific permeability, fluid viscosity, reservoir thickness, and other parameters, that would result in the most profitable well completion architecture to be used. This optimization process will help push the breakeven production cost of oil down, and promote sustainable activity for unconventional plays.