The development of unconventional fields has experienced major efficiency gains. One main breakthrough in efficiency is the introduction of viscous slickwater fracturing fluids. Viscous slickwater enables placement of higher proppant concentration than conventional slickwater and is less damaging than guar-based fluid, leading to aggressive fracturing designs and improved production. High viscosity friction reducer is the main component in viscous slickwater, which can replace hybrid and crosslinked fracturing fluids in unconventional reservoir completions. The successful application of high viscosity friction reducing fluid requires proper fluid hydration and adequate viscosity, which depends on water salinity and proppant concentration. We developed techniques for improved testing of friction reducers and friction reducer selection guidelines to support optimum placement of the fracturing design. A comparison of production results of wells fractured by viscous slickwater to those offset wells demonstrated the effectiveness of aggressive design with viscous slickwater fluids. A high viscosity friction reducer was tested in the laboratory and applied in the field. Experimental data demonstrate a good correlation between low shear viscosity and proppant transport capability. Static and dynamic proppant transport data were used to design viscous slickwater to replace linear gel. The friction reducer has been successfully applied in the field in more than 3,000 stages. Formations that were traditionally fractured with crosslinked gel were successfully fractured using viscous slickwater with ease. Replacing conventional slickwater with viscous slickwater enables the transport of higher proppant concentration with little change in operations. Aggressive designs deliver a boost in production, thus confirming viscous slickwater as the fluid of choice. Improved chemistry enables easier operations, faster well completion, and improved initial production, as confirmed by case studies. This study provides information for the application of viscous slickwater and the rigorous testing that is required and often overlooked.

A series of surfactants were evaluated in this study and the results were compared with conventional foaming agents used in fracture fluids. These surfactants were examined by surface tension measurements, bench-top foam height and half-life experiments, and viscosity measurements on a circulating foam rheometer. The foam rheometer allowed viscosities to be measured under conditions that are representative of those found in formations. Both nitrogen (N2) and carbon dioxide (CO2) foams were investigated. This paper presents detailed results obtained from laboratory experiments, which led to the identification of foamer A that exhibited excellent performance in the presence of nitrogen and carbon dioxide over a wide range of temperatures. Foamer A was found to be superior compared with conventional foamers, particularly at high temperatures. It is compatible with linear gels as well as crosslinked fluids commonly employed for fracturing treatments. Numerous fracturing treatments with foamer A have been successfully executed in the field. It is emphasized in the paper that the type of foamer used in fracturing treatments has a great impact on the resulting foam stability and viscosity. In addition, bench-top foam height and half-life experiments can give an indication of the performance of a specific surfactant, but its behavior under downhole conditions cannot necessarily be inferred accordingly. Introduction Foams are stable mixtures of a gas dispersed in a liquid base material with the gas constituting the internal phase and liquid the external phase. The gas phase typically is nitrogen (N2) or carbon dioxide (CO2), and the liquid is often a viscous fluid for oilfield fracturing applications. Foamed fluids have been used in hydraulic fracturing since the 1970s (Schramm 1994). Among many benefits foamed fluids offer over nonfoamed fracturing fluids is that they have stored compressed gas for quick cleanup, efficiently returning the injected fracturing fluid to the surface. Thus, foamed fluids are particularly suitable for depleted or underpressured gas wells. Foams also minimize the amount of water injected into a well while providing superior rheology (Reidenbach et al. 1986), making them excellent treatment fluids in water-sensitive formations (Ward 1986). Furthermore, foams provide good fluid-loss control, improving the fluid efficiency. In addition to applications in hydraulic fracturing, foams can also be utilized as diverting agents (Burman and Hall 1986; Parlar et al. 1995) and employed in wellbore cleanout applications (Ozbayoglu et al. 2003). For optimal performance, the foam must remain stable throughout the treatment. Several factors affect its stability, including the viscosity of the base fluid, the type and concentration of the foaming agent or foamer, the formation temperature, and the type and volume percentage of the gas phase. Water without a polymer is not commonly used as the liquid phase because of limited stability. Improved stability can be achieved by using linear polymer fluids or cross-linked gels. The foamer is a surfactant that facilitates dispersion of the gas into the liquid phase by lowering the interfacial tension. Furthermore, the foamer stabilizes the thin liquid films surrounding the bubbles and inhibits the coalescence of bubbles. As temperature increases, the drainage of the liquid phase in the foam structure accelerates due to thermal thinning of the liquid, leading to reduced foam stability. For this reason, maintaining the foam stability becomes increasingly challenging at high temperatures. The challenge further increases for CO2 foams because the high solubility of CO2 in aqueous media facilitates mass transfer between bubbles. Selecting foaming agents is critical in formulating stable foams, especially at elevated temperatures.

On 1 June 2007, a new era of chemical regulations began. The European Union (EU) consolidated approximately 40 pieces of existing chemical legislation and transformed them into one comprehensive chemical regulation called REACH (Registration, Evaluation, Authorisation, and Restriction of Chemicals). This new approach to chemical management puts a greater burden on importers and manufacturers. It also changes how the oilfield and gas service industry conducts business in not only the EU but also in the global chemical products marketplace. For the oilfield and gas service industry, REACH poses significant challenges requiring the reexamination of current practices in the import and manufacturing of oilfield service products. The regulatory requirements go far beyond the function of the HSE manager. Continuous interaction between the business functions of supply chain, logistics, HSE, IT, trade control, product development, sales and marketing, legal, and field operations is imperative to comply with this complicated, vastly encompassing piece of legislation. Lessons learned during the pre-registration phase in 2008 offered a clearer perspective on future registration requirements under REACH and have necessitated the reevaluation of chemical formulations in oilfield service products. This effort also requires the development and implementation of an ongoing chemical management system that continuously tracks the import and manufacturing of chemical substances found in numerous oilfield service products. Additional variables further complicate this tracking of substances are legal entities, management of chemical suppliers, communication between internal databases, and protection of confidential business information. This paper shares the process currently being developed and implemented by an oilfield services company towards compliance with REACH.

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