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| Fig. 1: Multistage hydraulic fracturing in a horizontal well. (Source: Wikimedia Commons) |
Meeting the ever-growing world energy demand requires innovative solutions. Hydraulic fracturing is largely claimed as the very solution to unleash the potential of unconventional reservoirs. Typically, directional drilling and multistage hydraulic fracturing have been widely employed in conjunction to develop unconventional resources as shown in Fig. 1. Hydraulic fracturing works by injecting a fracturing fluid into the formation to create cracks as new passages for fluid transport, thus significantly improving permeability in tight formations. To maximize well stimulation effects, engineers must thoroughly consider fracturing fluid type, injection rates, proppant size, pumping schedule, and many other crucial factors. An effective fracture design is selected by monitoring changes in productivity index (PI). By adjusting related parameters separately, operators learn the effects of each parameter and thus can find the optimal solution to maximize PI. Hence, the first parameter that must be carefully evaluated and selected is the fracturing fluid type.
Fracturing design is significantly influenced by reservoir conditions and economic limitations. Important reservoir parameters considered include wellbore diameter, porosity and permeability. There are many available fracturing fluids in the market, but they can usually be classified into slick water, linear gel, liquefied petroleum gas (LPG), CO2-foam, and N2-foam. [1] All properties of fracturing fluids to be tested are measured at 43.3°C (110°F) and 34,474 kPa (5000 psi), and they are listed in Table 1.
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| Table 1: Fracturing Fluid Properties. [2] |
Petroleum engineers utilize fracture mechanics, pressure, and fractional flow equations to predict the final fracture geometry and productivity index. Productivity index is defined as the amount of oil produced in a day per drop in pressure and usually measured in bbl/psi-day or in SI units as m3/Pa/s. The best fracturing fluid is selected based on the highest productivity index observed for the reservoir. As shown in Table 2, the highest calculated productivity index was observed when liquefied petroleum gas (LPG) was used. Since the productivity index of LPG is 1.7 times larger than the one for slick water, and because oil production is directly proportional to the productivity index, using LPG as the fracturing fluid will lead to 1.7 times more oil recovery.
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| Table 2: Fluid selection based on productivity index. [3] |
Under the constraint of keeping a constant injected proppant mass, an operator can optimize the given fracture design by changing 4 main factors, which are fluid type, proppant size, injection rate, and proppant loading.
When selecting the fluid type, the options investigated are slick water, linear gel, liquefied petroleum gas (LPG), CO2-foam, and N2-foam. Using LPG as the fracturing fluid proved to be the best option because it created the largest fracture area and produced the highest productivity index.
© Fatimah AlNasser. The author warrants that the work is the author's own and that Stanford University provided no input other than typesetting and referencing guidelines. The author grants permission to copy, distribute and display this work in unaltered form, with attribution to the author, for noncommercial purposes only. All other rights, including commercial rights, are reserved to the author.
[1] S. Tong, R. Singh, and K. K. Mohanty, "Proppant Transport in Fractures with Foam-Based Fracturing Fluids," SPE Annual Technical Conf. and Exhibition 2017, One Petro SPE-187376-MS, 9 Oct 17.
[2] S. A. Holditch, "Fracturing Fluids and Additives: Properties and Selection", in Tight Gas Reservoirs, ed. by Stephen A. Holditch et al. (Society of Petroleum Engineers, 2020).
[3] H. Ohtani, H. Mikada, and J. Takekawa, "Hydraulic-Fracturing Simulation in Different Differential Stresses and Anisotropic Media," SEG Intel. Exposition and Annual Meeting 2017, One Petro SEG-2017-17745119, 24 Sep 17.
