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Fracturing fluids and additives: Difference between revisions
Fracturing fluids and additives (view source)
Revision as of 14:13, 3 November 2014
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Fracturing fluids are pumped into the well to create conductive fractures and bypass near-wellbore damage in hydrocarbon-bearing zones. | Fracturing fluids are pumped into the well to create conductive fractures and bypass near-wellbore damage in hydrocarbon-bearing zones. The net result is an expansion in the productive surface-area of the reservoir, compared to the unfractured formation. A series of chemical additives are selected to impart a predictable set of properties of the fluid, including viscosity, friction, formation-compatiblity, and fluid-loss control. | ||
==Overview== | ==Overview== | ||
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* Be cost-effective. | * Be cost-effective. | ||
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 "slickwater" 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). | 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 "slickwater" 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 screenout (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-biwing fractures the carrier fluid must be sufficiently viscous (normally 50 to 1000 cp at nominal shear rates from 40-100sec<sup>-1</sup>) 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 cleanup. Conversely, in certain deep reservoirs (including offshore frac-pack applications), there is a need for higher density fracturing fluids whose densities can span up to > 12ppg. | 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 cleanup. Conversely, in certain deep reservoirs (including offshore frac-pack applications), there is a need for higher density fracturing fluids whose densities can span up to > 12ppg. | ||
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===Water-based fracturing fluids - uncrosslinked polymers and "slickwater"=== | ===Water-based fracturing fluids - uncrosslinked polymers and "slickwater"=== | ||
A common practice in the hydraulic fracturing of gas-producing reservoirs is the use of nonviscous "slickwater" fluids pumped at high rates (> 60bpm) to generate narrow fractures with low concentrations of proppant. In recent years, these treatments have become a standard technique in fracture stimulation of several U.S. shales, including the Barnett, Marcellus, and Haynesville and yield economically viable production. The low proppant concentration, high fluid-efficiency, and high pump rates in slickwater treatments yield highly complex fractures. Additionally, compared to a traditional bi-wing fracture, slickwater fractures often find the primary fracture | A common practice in the hydraulic fracturing of gas-producing reservoirs is the use of nonviscous "slickwater" fluids pumped at high rates (> 60bpm) to generate narrow fractures with low concentrations of proppant. In recent years, these treatments have become a standard technique in fracture stimulation of several U.S. shales, including the Barnett, Marcellus, and Haynesville and yield economically viable production. The low proppant concentration, high fluid-efficiency, and high pump rates in slickwater treatments yield highly complex fractures. Additionally, compared to a traditional bi-wing fracture, slickwater fractures often find the primary fracture connected to multiple orthogonal (secondary) and parallel (tertiary) fracture networks as described by Fisher (2002). Coupled with multistage fracture completions and multiple wells collocated on a pad, complex fracture networks yield a high degree of reservoir contact. | ||
The most critical chemical additive for slickwater-fracture execution is the friction reducer (FR). The high pump rates for slickwater treatments (often 60-100 bbl/minute) necessitate the action of FR accitives to reduce friction pressure up to 70%; this effect helps to moderate the pumping pressure to a manageable level during proppant injection. Common chemistries for friction reduction include polyacrylamide derivatives and copolymers added to water at low concentrations. Additional additives for slickwater fluids may include biocide, surfactant (wettability modification), scale inhibitor, and others. The performance (friction reduction) of slickwater fluids are generally less sensitive to mix-water quality, a large advantage over many conventional gelled fracturing fluids. However in high-salinity mix-water, many FR additives may see a loss in achievable friction reduction. Other advantages and disadvantages of slickwater fluids and execution (compared to that of gelled fracturing fluids) are detailed below: | The most critical chemical additive for slickwater-fracture execution is the friction reducer (FR). The high pump rates for slickwater treatments (often 60-100 bbl/minute) necessitate the action of FR accitives to reduce friction pressure up to 70%; this effect helps to moderate the pumping pressure to a manageable level during proppant injection. Common chemistries for friction reduction include polyacrylamide derivatives and copolymers added to water at low concentrations. Additional additives for slickwater fluids may include biocide, surfactant (wettability modification), scale inhibitor, and others. The performance (friction reduction) of slickwater fluids are generally less sensitive to mix-water quality, a large advantage over many conventional gelled fracturing fluids. However in high-salinity mix-water, many FR additives may see a loss in achievable friction reduction. Other advantages and disadvantages of slickwater fluids and execution (compared to that of gelled fracturing fluids) are detailed below: | ||