Given the state of the oil & gas industry today, i.e., low hydrocarbon prices and a global health crisis still in high gear, making good business decisions is more crucial than ever. Deciding which wells to keep open for production, which wells to shut-in, which wells to re-stimulate for immediate production, and which new wells to drill, if any, may directly impact a business' financial survival. This is true for both conventional and unconventional assets, but of significantly more concern to the unconventional asset investor, because incremental production is already capital-intensive at the best of times. Over the last decade, unconventional resources have become a significant source of the total production output in various parts of the world, and the primary stimulation treatment used is hydraulic fracturing. This technique sections a wellbore into multiple stages into which highly pressurized fluid is pumped at various fracture initiation locations. Historically, the number of stages and the number of clusters per stage, has primarily been based on total lateral length, previous experience in the same or similar fields, and on investment considerations, with a strong tendency towards decreasing stage and fracture spacing (i.e., increasing stage and fracture count). Field experience showing non-productive and full-physics simulations suggest room for improvement and indicate that there must be an optimal stimulation treatment that maximizes profit. Beyond this point, adding another stage in the treatment becomes more expensive than what can be recuperated by incrementally increased production. Thus, in the current work, the problem is posed as a classic constrained optimization problem and solved using Monte Carlo methods. Results show that in general, profitability of the production revenue is very sensitive to the reservoir recovery factor, porosity, drainage volume for the lease window, and, ultimately, the market price. Introduction Unconventional wells are challenging in many ways, and significant capital investment combined with relatively short production periods makes exploitation of these types of reservoirs a balancing act between costs and profit. Wells can run in the millions when drilling and completion costs are accounted for, with completion costs accounting for more than half of the capital requirement (EIA 2016). Fortunately, the completion details are one of the few inputs that can be adjusted in the field, which allows for fine-tuning to local conditions. In this work, we employ hydraulic fracturing as the stimulation technique, and note that it is the most common type of completion technique currently in use. During hydraulic fracturing, fluid is injected into a wellbore at high pressure to create cracks in the sub-surface in the neighborhood of the wellbore, through which natural gas and oil flow more freely than through the low-permeability formations typical of unconventional reservoirs. The pressurized fluid typically carries propping material such as sand, which is intended to hold open fractures after fracturing pressure is relieved and shut-in begins. The origins of hydraulic fracturing date back to early experiments in the 1940s at the Hugoton gas field in Grant County of southwestern Kansas by Stanolind (Charlez 1997; Montgomery et al. 2010), and one of the first commercially successful applications of the new technology in the 1950s. As of 2012, about 2.5 million "frac jobs" had been performed worldwide on oil and gas wells; over one million of those within the U.S. (King 2012). In years past, such stimulation treatment was generally necessary to achieve profitable flow rates in shale gas, tight gas, tight oil, and coal seam gas wells (Charlez 1997), but in today's market environment, using the optimal stimulation treatment is all but economic requirement for economic survival.