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Difference between revisions of "Fracturing fluids and additives"
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[http://www.flotekind.com/Assets/getting-it-right-the-first-time.pdf Getting it Right the First Time by Kevin Fisher]
[http://www.flotekind.com/Assets/getting-it-right-the-first-time.pdf Getting it Right the First Time by Kevin Fisher]
Revision as of 10:39, 29 May 2014
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.
To create the fracture, a fluid is pumped into the wellbore at a high rate to increase the pressure in the wellbore at the perforations to a value greater than the breakdown pressure of the formation. The breakdown pressure is generally believed to be the sum of the in-situ stress and the tensile strength of the rock. Once the formation is broken down and the fracture created, the fracture can be extended at a pressure called the fracture-propagation pressure. The fracture-propagation pressure is equal to the sum of:
- The in-situ stress
- The net pressure drop
- The near-wellbore pressure drop
The net pressure drop is equal to the pressure drop down the fracture as the result of viscous fluid flow in the fracture, plus any pressure increase caused by tip effects. The near-wellbore pressure drop can be a combination of the pressure drop of the viscous fluid flowing through the perforations and/or the pressure drop resulting from tortuosity between the wellbore and the propagating fracture. Thus, the fracturing-fluid properties are very important in the creation and propagation of the fracture.
Properties of a fracturing fluid
The ideal fracturing fluid should:
- Be able to transport the propping agent in the fracture
- Be compatible with the formation rock and fluid
- Generate enough pressure drop along the fracture to create a wide fracture
- Minimize friction pressure losses during injection
- Be formulated using chemical additives that are approved by the local environmental regulations.
- Exhibit controlled-break to a low-viscosity fluid for cleanup after the treatment
- 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). 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-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 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.
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 leakoff and improve fluid efficiency. In naturally fractured or highly cleated formations, the leakoff 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.
Categories of fracturing fluids
The categories of fracturing fluids available consist of:
- Viscosified water-based fluids
- Nonviscosified water-based fluids
- Gelled oil-based fluids
- Acid-based fluids
- Foam fluids
Table 1 lists the types of fracturing fluids that are available and the general use of each type of fluid. 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.
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 conected 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:
- High retained conductivity, due to no filtercake present.
- Reduced sensitivity to salinity and contaminants in mix-water.
- Reduced number of fluid additives required for slickwater fracturing fluid.
- Larger volumes of water often required for fracture design (compared to "gelleg" fracturing fluids).
- Larger horsepower requirement (to maintain high pump rates, 60-110bpm).
- Limited fracture-width (due to low maximum concentration proppant in low viscosity).
- Reduced %-flowback-water recovery (due to imbibement of fracturing fluid in complex fracture network far from wellbore).
- Limitation to fine-mesh propping agents (due to reduced ability of nonviscous fluids in transport of large proppants).
As the anticipated proppant-suspension capacity of slickwater fluids is quite low, a complementary solution is the use of linear (uncrosslinked) gels. These fluids, based on uncrosslinked solutions of polysaccharides (i.e., guar, derivatized-guar, HEC, xanthan), have viscosities of up to 100cP at 100sec-1 at surface temperature, which depend on polymer concentration. As this viscosity is several orders of magnitude higher than slickwater, linear gels have improved proppant-suspension. When uncrosslinked gels are used in late-slurry stages of a fracturing treatment (where the pad and early-slurry stages used slickwater), these are often referred to as "hybrid" fracturing treatments. [Note that "hybrid" may also refer to fracture treatments using crosslinked-gel to follow slickwater, crosslinked-gel following linear/uncrosslinked, and other variations]
Water-based fracturing fluids - alternatives
Typical additives for a fracturing fluid have been described in detail by Ely. Typical additives for a water-based polymer fluid are briefly described next. Table 3 presents additional information on additives.
Polymers are used to viscosify the fluid. Crosslinkers are used to change the viscous fluid to a pseudoplastic fluid. Biocides are used to kill bacteria in the mix water. Buffers are used to control the pH of the fracture fluid. Surfactants are used to lower the surface tension. Fluid-loss additives are used to minimize fluid leakoff into the formation. Stabilizers are used to keep the fluid viscous at high temperature. Breakers are used to break the polymers and crosslink sites at low temperature.
- Howard, C.C. and Fast, C.R. 1957. Optimum fluid characteristics for fracture extension. In API Drilling and Production Practice, 24, 261.
- Gidley, J.L., Holditch, S.A., Nierode, D.E. et al. 1989. Fracturing Fluids and Additives. In Recent Advances in Hydraulic Fracturing, 12. Chap. 7, 131. Richardson, Texas: Monograph Series, SPE.
Noteworthy papers in OnePetro
Fisher, M.K. et al. 2002. Integrating Fracture Mapping Technologies to Optimize Stimulations in the Barnett Shale. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 29 September-2 October. SPE-77441-MS. http://dx.doi.org/10.2118/77441-MS
King, G. 2010. Thirty Years of Gas Shale Fracturing: What Have We Learned?. Presented at the SPE Annual Technical Conference and Exhibition, Florence, Italy, 19-22 September. SPE-133456. http://dx.doi.org/10.2118/133456-MS
Schein, G. 2012. The Application and Technology of Slickwater Fracturing. Distinguished Lecture Presented 2004-2005. SPE-108807.
SPE 21033_A Case Study of High-Temperature Wells Fractured Using Multiple Fluids To Improve Conductivity and Well Performance
SPE 22838_New, Delayed Borate-Crosslinked Fluid Provides Improved Fracture Conductivity in High-Temperature Applications
SPE 24339_Chemistry and Rheology of Borate-Crosslinked Fluids at Temperatures to 300F
SPE 25463_High-Temperature, Borate-Crosslinked Fracturing Fluids A Comparison of Delay Methodology