Safe Boundaries of High-Temperature Fracturing Fluids
- Tony Ogunsanya (Aramco Services Company) | Leiming Li (Aramco Services Company)
- Document ID
- Society of Petroleum Engineers
- SPE Western Regional Meeting, 22-26 April, Garden Grove, California, USA
- Publication Date
- Document Type
- Conference Paper
- 2018. Society of Petroleum Engineers
- 3 Production and Well Operations, 5 Reservoir Desciption & Dynamics, 5.2.2 Fluid Modeling, Equations of State, 2.4 Hydraulic Fracturing, 4 Facilities Design, Construction and Operation, 2 Well completion, 4.2.3 Materials and Corrosion, 4.1.2 Separation and Treating, 4.1 Processing Systems and Design, 5.2 Fluid Characterization, 2.5.2 Fracturing Materials (Fluids, Proppant)
- high temperature, hydrogen sulfide
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In successful hydraulic fracturing operations, fracturing fluids should possess sufficient viscosity in order to transmit high pumping pressure downhole. This pressure creates fractures in formation and transports proppants that help to keep the fractures open after treatment. Fluid viscosity may drop when polymers in fracturing fluids suffer degradation due to, for example, oxidative species, especially in wells with elevated bottomhole temperatures. Fluid stabilizers are often needed in fracturing fluids to mitigate this effect.
Commonly used fluid stabilizers in oil field operations are thiosulfate oxygen scavengers, such as sodium thiosulfate. Thiosulfate can quickly neutralize oxidative molecules, thus protecting polymers from being decomposed and extending the lifetime of fracturing fluids. Thiosulfate, however, may react to release hydrogen sulfide, especially at elevated temperatures. Hydrogen sulfide is poisonous to human and can also damage oil field assets by corrosion and scaling. To minimize hydrogen sulfide release, a series of lab tests were conducted to study hydrogen sulfide generation in high-temperature fracturing fluids.
Extensive lab tests suggested that the hydrogen sulfide generation in fracturing fluids could be influenced by factors including test temperature, oxygen scavenger concentration, fracturing fluid formula, etc. At test temperatures of 350°F or below, the hydrogen sulfide generated was well below 10ppm. Without cooldown, most fracturing fluids prepared with crosslinked polysaccharides are limited to downhole temperatures up to 350°F. It is therefore less risky to use thiosulfate in these fluids without much concern for generating hydrogen sulfide. We observed that the dosage of thiosulfate influenced the outcome of the hydrogen sulfide generated at elevated temperatures above 350°F. Usually the more thiosulfate was added, the more hydrogen sulfide was produced. Without using excessive dosage of thiosulfate, the hydrogen sulfide generated, for example, could be less than 10ppm even at about 375°F or higher. With optimized selection of the fluid compositions, the amount of hydrogen sulfide produced could therefore be reduced significantly.
The illustrative experiments include the search for safe boundaries of fracturing fluids used at high temperatures without producing hydrogen sulfide over regulatory permissible exposure limit. Guidelines on how to mitigate hydrogen sulfide generation will be recommended based on lab results.
|File Size||752 KB||Number of Pages||8|
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