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Summary Hydraulic fracturing is a well-established process to enhance productivity of oil and gas wells. Fluids are used in fracture initiation and the subsequent proppant and/or sand transport. Several chemistries exist for these fluids. This paper summarizes the published literature over the last decade (more than 100 technical articles) and captures the advances in the design of water-based fracturing fluids for fracturing ultralow- to moderate-permeability reservoirs (nonfrac-pack applications). Guar-based polymers are still being used in fracturing operations for wells at temperatures of less than 300°F (148.9°C). To minimize the damage associated with this class of polymers, the industry has attempted several approaches. These included the use of a lower polymer concentration in formulating these fluids and alteration of the crosslinker chemistry so that one can generate higher viscosity values with lower polymer loadings. Moreover, the industry shifted toward the use of cleaner guar-based polymers because commercial guar contains a minimum of 5 wt% of residues, which can cause damage to proppant packs. The review has also revealed that shear and pressure effects on the rheological behavior of borate-crosslinked gels is significant. Although these fluids recover their viscosity after shear, they have been observed to lose a significant portion of their viscosity under high pressures. When fracturing deeper wells in hotter reservoirs, the need arose for a new class of thermally stable polymers. Thus, the industry shifted toward polyacrylamide- (PAM-) based polymers. These synthetic polymers offer sufficient viscosity at temperatures up to 450°F (232°C). Examples include 2-acrylamido-2-methyl-propanesulfonic acid (AMPS) and copolymers of partially hydrolyzed PAM-AMPS-vinyl phosphonate. To address the challenge of high-pressure pumping requirements on the surface, high-density brines have been used to increase the hydrostatic pressure by 30%. Breakers’ chemistry has seen introduction of new materials. These breakers decrosslink the gel by reacting with the crosslinker. They form ligands with the metallic crosslinkers and displace them from the crosslinking bonds with the guar-based polymers. Examples of these breakers include polysuccinimides and lignosulfonates. To minimize the environmental impact of using massive amounts of fresh water and to minimize costs associated with treating produced water, the use of produced water in hydraulic-fracturing treatments has been reported. In addition, the paper captures the advancements in the use of slickwater, which uses drag-reducing agents (PAM-based polymers) to minimize friction. The paper highlights the first use of breakers that were introduced to improve the cleanup of these drag reducers. For foamed fluids, new viscoelastic surfactants that are compatible with carbon dioxide are discussed. The paper also sheds light on the use of emerging technologies, such as nanotechnology, in the design of new, efficient hydraulic-fracturing fluids. For example, nanolatex silica was used to reduce the concentration of boron found in conventional crosslinkers. Another advancement in nanotechnology was the use of 20-nm silica particles suspended in guar gels. The paper provides a thorough review of all these advancements.
Abstract Hydraulic fracturing is a well-established process to enhance productivity of oil and gas wells. Fluids are used in fracture initiation and the subsequent proppant and/or sand transport. Several chemistries exist for these fluids. This paper summarizes the published literature over the last decade (90+ technical articles) and captures the advances in the design of water-based fracturing fluids. Despite their old introduction, guar-based polymers are still being used in fracturing operations for wells at temperatures less than 300°F (148.9°C). In order to minimize the damage associated with this class of polymers, the industry attempted several approaches. These include the use of lower polymer concentration in formulating these fluids. Another approach was to alter the crosslinker chemistry so that one can generate higher viscosity values with lower polymer loadings. Moreover, the industry shifted towards the use of cleaner guar-based polymers. The reason is the fact that commercial guar contains a minimum of 5 wt.% residues that cause damage to proppant packs. With fracturing deeper wells in hotter reservoirs, the need arose for a new class of thermally stable polymers. Thus, the industry shifted towards polyacrylamide-based polymers. These synthetic polymers offer sufficient viscosity at temperatures up to 232°C (450°F). Examples included 2-acrylamido-2-methylpropanesulfonic acid (AMPS) and copolymers of partially hydrolyzed polyacrylamide (PHPA)-AMPS-vinyl phosphonate (PAV). To address the challenge of high pressure pumping requirements on the surface, high density brines have been used to increase the hydrostatic pressure by 30%. On the breakers chemistry, new breakers were introduced. These breakers decrosslink the gel by reacting with the crosslinker. In order to minimize the environmental impact of using massive amounts of fresh water and to minimize costs associated with treating produced water, the use of produced water in hydraulic fracturing treatments has been reported. In addition, the paper captures the advancements in the use of slickwater where use is made of drag reducing agents (PAM-based polymers) to minimize friction. The paper highlights the first use of breakers that were introduced to improve the cleanup of these drag reducers. For foamed fluids, new viscoelastic surfactants (VES) that are compatible with CO2 are discussed. The paper also sheds light on the use of emerging technologies such as nanotechnology in the design of new efficient hydraulic fracturing fluids. For example, nanolatex silica was used to reduce the concentration of boron used in conventional crosslinkers. Another advancement in nanotechnology was the use of 20 nm silica particles suspended in guar gels. The paper provides a thorough review on all of these advancements.
The materials and chemistry used to manufacture hydraulic fracture fluids are often confusing and difficult for the practicing hydraulic fracturing engineer to understand and optimize. Many times the failure of a particular fracturing treatment is blamed on the fluid because that is a major unknown from the design engineer's viewpoint. Many of the components and processes used to manufacture the fluid are held proprietary by the service company which adds to the confusion and misunderstanding. This paper makes an attempt to describe the components used in fracturing fluids at a level that the practicing frac engineer can understand and use. The paper is intended as a companion paper to the Fracturing Fluids design paper which describes how to use the fluids and viscosity generated by the fluids to design a fracturing treatment.
Historically, the application of breakers in fracturing fluids at elevated temperatures has been a compromise between maintaining proppant transport and achieving the desired fracture conductivity. Conventional oxidative breakers react rapidly at elevated temperatures, potentially leading to catastrophic loss of proppant transport. Encapsulated oxidative breakers have experienced limited utility at elevated temperatures due to a tendency to release prematurely or to have been rendered ineffective through payload self-degradation prior to release.
Enzymes, from a theoretical perspective, are known to provide superior performance relative to oxidative breakers. This is due to the inherent specificity and the "infinite" polymer-degrading activity of enzymes However, the application of enzymes has historically been limited to low-temperature fracturing treatments due to the perceived pH and temperature constraints. Recent developments in biotechnology have resulted in the isolation of hyper-thermophilic organisms, which led to the separation and purification of extreme temperature-stable, polymer-specific enzymes Laboratory evaluations utilizing these enzymes as gel breakers have demonstrated exceptional performance capabilities over a pH range of 3-11 and temperatures exceeding 300 F.
Performance properties of systems incorporating the new breakers are provided, including rheology, proppant transport, and retained permeability. Case histories of fractured wells in several moderate to high-temperature reservoirs are provided to validate the utility of this technological breakthrough The data illustrate that the enzyme breakers can be successfully incorporated without compromising proppant transport capabilities, yielding improved productivity relative to observations in offset cases treated with conventional breakers.
Abstract High pH borate gels have been used in fracturing deep gas reservoirs in Saudi Arabia. Guar and hydroxypropyl guar are used at various concentrations up to 45 lb/1000 gals. A breaker (regular or encapsulated oxidizers, guar-specific enzyme, or combinations of these breakers) is usually used to degrade the gel after the fracturing treatment. Field results indicated that the cleaning time following fracturing treatments was too long. Unbroken gel was noted in the flow back samples of some wells. This study was conducted to assess the effectiveness of various breakers that are used in the field, and determine other parameters that may affect the time needed to clean-up fractured wells. This paper presents the results of a detailed study done to evaluate the performance of several breakers at typical field conditions. The apparent viscosity of various borate gels was measured as a function of breaker type and concentration. Gel degradation was followed in a high temperature/high pressure see-through cell. The surface tension of various gel filtrates was measured as a function of temperature up to 150°C. Viscosity measurements indicated that all oxidizers degraded high pH borate gels, however the time needed to degrade the gel was found to be a function of breaker type and concentration; temperature and polymer loading. All guar-based gels produced a residue after reacting with the breaker. This residue was noted irrespective of the type and concentration of the breaker used. The residue was noted with gels formed using either guar gum or hydroxylproply guar. This residue may adversely affect the conductivity of the fracture. Surface tension measurements indicated for the first time that the surface tension of borate gels is high, which will enhance water blockage and hence reduce gas production. This paper examines factors affecting gel degradation, surface tension of borate gel filtrate, and their impact on well productivity. Introduction Hydraulic fracturing is often necessary for oil and gas wells to enhance well productivity. The fracturing fluid is one of the most important components in hydraulic fracturing treatments. The fluid is used to create fracture and transport proppant down the created fracture. To make the fracturing operation successful, the fracturing fluids need to possess certain properties such as sufficiently viscous to suspend and transport proppants, suitable at pumping temperature, having low friction pressure, having moderate efficiency, resistant to shear degradation, can be removed efficiently from the fracture, and economically realistic. Guar and guar derivatives; HPG (hydroxypropyl guar), and CMHPG (carboxymethyhydroxypropyl guar), are the most commonly used polymers to prepare water-based fracturing fluid. High viscosity is generated by crosslinking polymer molecules with a crosslinker (B(III), Ti(IV), or Zr(IV)). Borate gels have been used in the oil industry as fracture fluids and zone isolation. This study, however, will focus on guar gum and HPG polymers cross-linked with monoborate ions. Pre-Khuff sandstone reservoirs in Saudi Arabia produce sweet gas for more than ten years. Many of wells drilled in these reservoirs are hydraulically fractured. Guar gum and HPG are used to prepare the gels used in hydraulic fracture treatment. Both polymers are cross-linked with monoborate ions. The source of this ion is either boric acid or borax or organoborate salts. The sandstone reservoirs are clean sand with illite as the main clay present in the formation. Potassium chloride is used all drilling and completion fluids to avoid fines migration problems. The reservoir temperature and pressure are 300°F and 8,535 psi, respectively. Analysis of well flow back samples following fracture treatments highlighted the presence of very viscous fluids and gel fragments. Also, the time needed to clean the fractured wells was too long. These trends indicated the gels used in these treatment did not break completely. They also indicate that the surface tension of gel filtrate was high, which resulted long cleaning time. The detrimental effects of fracture conductivity reduction resulting from incomplete fracturing fluid flowback/cleanup are well documented in literature. Until recently, characterization of fracturing fluid cleanup could only be simulated in the laboratory and can't be monitored in the field.