Selecting appropriate proppants is an important part of hydraulic fracture completion design. Proppant selection choices have dramatically increased in recent years as regional sands have become the proppant of choice in many liquid-rich plays. But are these new proppants the best long-term choices to maximize production? Do they provide the best well economics?
As the shale revolution pushed into lower-permeability reservoirs, the concept of dimensionless fracture conductivity has pushed our industry to use ever lower-conductivity materials—away from ceramics and resin-coated proppant to white sand in some Rocky Mountain plays and more recently from white sand to regional sand in the Permian and Eagle Ford plays.
Proppant selection is historically based on the particles crush resistance to stress loading and fracture conductivity under various flow conditions, all while ideally having the lowest possible cost. The article explains how much fracture conductivity is adequate for a given effective fracture length and reservoir permeability and then looks at the economics of achieving “just-good-enough” target conductivity.
Laboratory testing and results
Among the main findings, Liberty Oilfield Services sees no clear evidence that higher conductivity proppants (either white sand versus regional sand or ceramic proppants versus white sand) result in better well performance and economics (Figure 1). The exception may be in the deeper, higher-stress Eagle Ford formation where white sand could provide slightly better economics. It should be noted that well location with respect to local sand mines has a large impact on the economics.
Laboratory conductivity testing shows that the median 100 mesh and 40/70 mesh white sand has 1.8 times and 2.4 times conductivity, respectively, as compared to the same size regional sand (Figure 2). This clearly shows that, using the same laboratory test conditions, white sand provides higher conductivity than regional sand. Proppant mesh size is even more important. Laboratory data show that 20/40 white sands have the highest median conductivity (Figure 2) being about eight times higher than the 100 mesh regional sand. These laboratory results may tempt operators to use the highest conductivity proppant, but the more important question is if these higher conductivities are actually needed relative to the very low flow capacity of unconventional reservoirs.
While laboratory conductivity measurements and comparisons provide important baseline information, they cannot fully answer the question about required conductivity to provide “just-good-enough” proppant economics. This question can be answered with production modeling tools such as numerical reservoir modeling, which was used to determine the minimum fracture conductivity needed (“good-enough fracture conductivity”) to maximize short-term oil production (one to three years) for a given fracture half-length, fracture spacing and reservoir permeability.
In this study the numerical reservoir model was intentionally kept simple to focus on first order effects of fracture conductivity by assuming a single reservoir layer, single 10,000-ft wellbore in the center of a 2,000-ft by 11,000-ft drainage area flowing at a constant bottomhole pressure (BHP) of 1,000 psi.
The following steps were performed in the modeling:
- Assuming a base case of 300 ft effective fracture half-length and fracture spacing of 18 ft (25-ft cluster spacing with 45-degree frac angle relative to wellbore), multiple scenarios of reservoir permeability ranging from 0.00005 md to 0.1 md were modeled for one year and three years of production.
- For each reservoir permeability scenario, different fracture conductivities were explored to determine the minimum fracture conductivity needed to have less than 1% difference in cumulative oil production from the maximum achievable in the given time frame. It is important to note that these criteria do not represent an economic optimization of conductivity.
- Repeated steps 1 and 2 for a fracture spacing of 36 ft (50-ft cluster spacing with 45-degree frac angle relative to wellbore) to demonstrate the effect of fracture spacing.
The results in the plots in Figure 3 provide a comparison of two different cluster (frac spacings) versus reservoir permeability and producing time (one year versus three years). It shows that high-intensity horizontal completions in unconventional reservoirs with very small cluster and frac spacing require much less fracture conductivity (generally below 10 md-ft) than previous widely spaced clusters or vertical well completions. Also, the move to reduce fracture driven well interference with shorter frac lengths will additionally reduce fracture conductivity requirements for most unconventional permeability scenarios.
Summarizing the above results in a qualitative way, Liberty Oilfield Services sees that the minimum fracture conductivity needed for the range of permeabilities encountered in unconventional plays decreases with tighter fracture spacing and shorter fracture half-lengths (the current trend in high-intensity completions as well as offset well frac hit mitigation).
The results also indicate that the minimum fracture conductivity needed based on the concept of having sufficient dimensionless fracture conductivity is probably too conservative and represents an upper bound. This is because the traditional definition of dimensionless fracture conductivity assumes constant reservoir deliverability during the early time flow period, which is very high. With time, as fracture interference sets in and flow starts to transition away from linear flow, reservoir deliverability declines, and therefore the required fracture conductivity decreases as well (left plot in Figure 3). Although the traditional concept of FcD can be used for a rough initial conductivity estimate, it is a “moving optimum target” in unconventional horizontal wells since it is also a function of production time, cluster spacing and well spacing.
This implies that more detailed reservoir and fracture modeling in conjunction with net present value analysis using actual completion costs must be performed for each specific case to truly optimize required fracture conductivities.
The Midland Basin covers a wide range of reservoir conditions with estimations of regional sand usage exceeding 80% of the total sand in the basin. A Lower Spraberry modeling scenario (Figure 4) produces from a mid-length lateral with a modern completion design. The flow control uses a constant BHP for the term of the simulation. Three-year cumulative oil volumes are within 3% for the regional and white 100 mesh sand cases.
Though the white sand well produces slightly more oil, the economics for the regional sand well are superior, given the difference in proppant cost. At the time of this analysis, white sand was 3.5 times the cost of regional sand.
This article shows the benefit of using a combination of Big Data statistical tools, laboratory test results, fracture diagnostics and detailed physical modeling for holistic well performance evaluation with respect to proppant selection and completion optimization, which will be critical for the success of future unconventional oil and gas development.
This story was originally published on March 19.
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