The categories of fracturing fluids available consist of:
Reasons for selecting between these fluid types will depend on a variety of factors. For most reservoirs, water-based fluids with appropriate additives are most suitable, due to the historic ease with which large volumes of mix-water can be acquired. In some cases, foam generated with N2 or CO2 can be used to stimulate shallow, low-pressure zones successfully. When water is used as the base fluid, the water should be tested for quality due to some sensitivity of certain fluid chemistries to the mix-water composition. Table 2 presents generally accepted levels of water quality for use in hydraulic fracturing.
The ideal fracturing fluid should:
The viscosity of the fracturing fluid is an important point of differentiation in both the execution and in the expected fracture geometry. Many current practices, generally referred to as “slick water” treatments, use low-viscosity fluids pumped at high rates to generate narrow, complex fractures with low-concentrations of propping agent (0.2-5 lbm proppant added (PPA) per gallon). In order to minimize risk of premature screen out (SO), pumping rates must be sufficiently high to transport proppant over long distances (often along horizontal wellbores) before entering the fracture. By comparison, for conventional wide-bowing fractures the carrier fluid must be sufficiently viscous (normally 50 to 1000 cp at nominal shear rates from 40-100sec-1) to transport higher proppant concentrations (1-10 PPA per gallon). These treatments are often pumped at lower pump rates and may create wider fractures (normally 0.2 to 1.0 in.).
The density of the carrier-fluid is also important. The fluid density affects the surface injection pressure and the ability of the fluid to flow back after the treatment. Water-based fluids generally have densities near 8.4 ppg. Oil-base fluid densities will be 70 to 80% of the densities of water-based fluids. Foam-fluid densities can be substantially less than those of water-based fluids. In low-pressure reservoirs, low-density fluids, like foam, can be used to assist in the fluid clean-up. Conversely, in certain deep reservoirs (including offshore frac-pack applications), there is a need for higher density fracturing fluids whose densities can n up to > 12ppg.
A fundamental principle used in all fracture models is that “the fracture volume is equal to the total volume of fluid injected minus the volume of fluid that leaks off into the reservoir.” The fluid efficiency is the percentage of fluid that is still in the fracture at any point in time, when compared with the total volume injected at the same point in time. The concept of fluid loss was used by Howard and Fast to determine fracture area. If too much fluid leaks off, the fluid has a low efficiency (10 to 20%), and the created fracture volume will be only a small fraction of the total volume injected. However, if the fluid efficiency is too high (80 to 90%), the fracture will not close rapidly after the treatment. Ideally, a fluid efficiency of 40 to 60% will provide an optimum balance between creating the fracture and having the fracture close down after the treatment.
In most low-permeability reservoirs, fracture-fluid loss and efficiency are controlled by the formation permeability. In high-permeability formations, a fluid-loss additive is often added to the fracture fluid to reduce leak off and improve fluid efficiency. In naturally fractured or highly cleated formations, the leak off can be extremely high, with efficiencies down in the range of 10 to 20%, or less. To fracture treat naturally fractured formations, the treatment often must be pumped at high injection rates with fluid-loss additives.
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