Development of a Nonresidue Polymer-Based Fracturing Fluid
Abstract: TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractGood fracture conductivity is essential to the success of fracturing operations. It has become an important aspect in the development of fracturing fluid technology. To improve proppant conductivity, fracturing fluid systems with reduced polymer concentration have been developed. While reduced polymer concentration would result in less polymer residue upon polymer broken, the insoluble polymer residue generated from the broken polymer still causes blockage of… Show more
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Cited by 5 publications
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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.1 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.1 Guar and guar derivatives; HPG (hydroxypropyl guar), and CMHPG (carboxymethyhydroxypropyl guar), are the most commonly used polymers to prepare water-based fracturing fluid.2 High viscosity is generated by crosslinking polymer molecules with a crosslinker (B(III), Ti(IV), or Zr(IV)).1 Borate gels have been used in the oil industry as fracture fluids and zone isolation.3 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.4 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.5 Until recently, characterization of fracturing fluid cleanup could only be simulated in the laboratory and can't be monitored in the field.6
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.1 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.1 Guar and guar derivatives; HPG (hydroxypropyl guar), and CMHPG (carboxymethyhydroxypropyl guar), are the most commonly used polymers to prepare water-based fracturing fluid.2 High viscosity is generated by crosslinking polymer molecules with a crosslinker (B(III), Ti(IV), or Zr(IV)).1 Borate gels have been used in the oil industry as fracture fluids and zone isolation.3 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.4 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.5 Until recently, characterization of fracturing fluid cleanup could only be simulated in the laboratory and can't be monitored in the field.6
Carboxymethylcellulose a Cost Effective Alternative to Guar, CMHPG and Surfactant-Based Fluid Systems
The first fracture treatment using crosslinked guar was performed in 1969. Since then guar and its derivative polymers have dominated hydraulic fracturing. But because of volatility and supply issues with guar gum that have surfaced during peak activity years, industry has turned to alternatives. One of those is Carboxymethylcellulose (CMC) that just like guar comes from food industry. CMC is also used in pharmaceuticals as a thickening agent, and in the oil and gas industry as an ingredient in drilling mud. Use in hydraulic fracturing is surprisingly limited. The objective of this paper is to demonstrate successful cases of CMC based treatments over traditional guar and surfactant based treatments used in linear and foamed applications. This paper presents several cases from treatments performed on formations such as Cardium, Montney, Belly River, and Dunvegan. Presented production comparison will demonstrate that wells treated with CMC based hydraulic fracturing fluid system yield similar performance when compared to wells treated with guar, its derivatives, and surfactant based fluid systems. Cost savings realized when switching to CMC based fluid systems are also discussed in the paper. Laboratory tests described, performed, and results shared to demonstrate the performance of CMC compared to guar, Carboxymethylhydroxypropyl guar (CMHPG), and surfactant systems. The paper attempts to provide degree of confidence to the operators looking for cleaner alternatives to industry established fluid systems and shows that these can be successfully implemented without additional risk or cost.
The properties of novel supramolecular complex fracturing fluid are discussed in this paper. Based on the supramolecular polymer thickener (SMPT), the thickening system forms a gel with viscoelastic surfactant (VES) wormlike micelles through experimental design. The resultant gel contains very efficient cross-links between the wormlike micelles and polymer chains that can be advantages in elastic and viscous properties of the fluid. The fracturing fluid contains nearly twentieth of conventional surfactant fracturing fluid. Both VES and SMPT synergistically enhance the shear-tolerant property in high-temperature much more than the single. The electron microscopy photos of the solution microstructure and rheological results reveal the suitable ratio of SMPT and VES forms a supramolecular network honeycomb structure, which is built by strong hyper-branched compound structures through noncovalent interactions. Meanwhile, the physical model can legitimately expound the gelation mechanism of the supramolecular viscoelastic gel. Moreover, proppant suspension behavior, gel breaking test and the permeability damage rate of core matrix were studied. Laboratory data showed that the viscosity of new fluid could be maintained above 50 cp with the formation of 0.8%SMPT and 0.5%VES. The steady shear viscosity test has been conducted for 2 hours at 150 °C and 170s−1. Shear restoration experiment proved the new supramolecular viscoelastic fluid was in high viscosity at low shear rate and a strong reversible shear thinning behavior. The dynamic rheological properties showed high viscoelasticity, while elastic modulus was higher than loss moduli at an oscillation frequency 0.01Hz. The result of sand sedimentation experiment with 20% sand ratio was well. The supramolecular viscoelastic fluid was completely broken and gel breaking liquid was transparent with no water insoluble residue. The permeability damage rate of core matrix caused by this fracturing fluid was 20% less than guar fluid. The supramolecular viscoelastic fluid presents in this paper could be a total or partial alternative to VES and guar for hydraulic fracturing whose price is subjected to harvest areas. Results show that the new supramolecular viscoelastic fluid is an effective fracturing fluid satisfies high temperature tight gas reservoir.
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