Among the most difficult bacterial infections encountered in treating patients are wound infections, which may occur in burn victims, patients with traumatic wounds, necrotic lesions in people with diabetes, and patients with surgical wounds. Within a wound, infecting bacteria frequently develop biofilms. Many current wound dressings are impregnated with antimicrobial agents, such as silver or antibiotics. Diffusion of the agent(s) from the dressing may damage or destroy nearby healthy tissue as well as compromise the effectiveness of the dressing. In contrast, the antimicrobial agent selenium can be covalently attached to the surfaces of a dressing, prolonging its effectiveness. We examined the effectiveness of an organoselenium coating on cellulose discs in inhibiting Pseudomonas aeruginosa and Staphylococcus aureus biofilm formation. Colony biofilm assays revealed that cellulose discs coated with organoselenium completely inhibited P. aeruginosa and S. aureus biofilm formation. Scanning electron microscopy of the cellulose discs confirmed these results. Additionally, the coating on the cellulose discs was stable and effective after a week of incubation in phosphatebuffered saline. These results demonstrate that 0.2% selenium in a coating on cellulose discs effectively inhibits bacterial attachment and biofilm formation and that, unlike other antimicrobial agents, longer periods of exposure to an aqueous environment do not compromise the effectiveness of the coating.

Effectively stimulating multiple pay zones using separate fracturing treatments can be costly and time consuming. By contrast, multistage fracturing is a widely used technique that offers the advantage of stimulating significant portions of the reservoir by fracturing through multiple perforations simultaneously. While the multistage fracturing method known as "plug and perf" has been proven to be an effective method for developing unconventional resources, it presents the challenge of achieving even proppant distribution to all perforation clusters during each stimulation stage.It is commonly assumed that the plug and perforate multistage fracturing technique provides the planned fluid and proppant distribution among the fractures that are simultaneously taking fluid during pumping a single stage. However, parameters, such as the reservoir properties, fluid rheology, and proppant characteristics have demonstrated a strong influence on the actual proppant and fluid distribution into the various perforations.Field data indicates, in many cases, that some of the clusters do not contribute to production. This indication supports the hypothesis that actual proppant and fluid distribution along the stimulated clusters might be different from the assumed uniform distribution. Some believe that the amount of proppant appears to be heavily weighted toward the end of the perforated interval, which results in uneven proppant distribution. Empirical data as well as laboratory tests have yet to be challenged against the few studies that exist. This paper presents a first-of-its-kind large-scale investigation that was conducted to study proppant distribution among separated perforations along a horizontal interval. These experiments closely simulate any single stage during the plug-andperforate fracturing process. The effect of various fluid specific gravities, fluid viscosities, proppant specific gravities, proppant sizes, and slurry flow rates were investigated while keeping outside-casing parameters constant. The various aspects of proppant and fluid flow through a perforated interval are discussed. The experimental efforts discussed in this paper create a better understanding of fluid and proppant behavior in this widely used fracturing process to help achieve maximum efficiency.

The development of a high-temperature seawater-based fracturing fluid has received much attention because it offers a solution to fresh water shortages; however, the rheological properties suffer significantly as a result of interactions between dissolved ions with fluid components. Various strategies have been investigated to address this challenge, including seawater treatments that ultimately remove the highly soluble and insoluble ionic moieties to yield a fracturing fluid with reliable rheological characteristics. Most polymer-based fracturing fluids have limited salt tolerance. Interactions between the polymer and divalent cations in seawater inhibit proper polymer hydration, thus preventing generation of an elastic polymer network and potentially affecting the crosslinking mechanism. In this study, concentrations of critical ions in seawater were reduced using a reliable seawater treatment. This treatment allowed a reliable fluid at higher temperatures and also considerably reduced the scaling tendency of the fluid. The fluid presented herein, designed in the treated seawater, yields a stable elastic polymer network when used in conjunction with stabilizing additives and is capable of effectively delivering proppant down hole. This newly developed formulation uses a combination of instant and delayed crosslinkers and additional stabilizing additives required at optimum concentrations to yield a stable fluid system in the treated seawater. At high temperatures, the addition of typical ion sequestration agents failed to eliminate the negative interaction between dissolved ions and fluid stability, thus requiring water pre-treatment. The fluid system exhibits reliable rheological properties and yields a clean broken fluid for excellent proppant pack cleanup in high total dissolved solids (TDS) waters up to 350°F. Typical guar-based fracturing fluids require a high pH (greater than 10) to maintain rheological stability at high temperatures. The fracturing fluid presented herein was developed at pH 9 in treated seawater and maintained its elasticity and viscosity over a long period of time at temperatures up to 350°F. An added benefit of controlling the pH and not surpassing pH 9.5 was also revealed—scale control. This study discusses the development of a new seawater-based fracturing fluid for use in high-temperature wells. This can result in a paradigm shift in source water use for hydraulic fracturing.