As mature fields produce larger quantities of water, operators and service companies find themselves challenged with disposing flowback and produced water to reduce costs, handling the logistics of getting enough water to hydraulically fracture the well, as well as complying with stricter governmental regulations. As produced water is recycled and used in fracturing applications, each cycle of re-used water returns with a more complex chemical make up than before. Therefore, the usable lifetime of the recycled water is shortened or requires expensive cleaning or dilution with fresh water to make it a viable solvent base for fracturing fluids. This paper describes the process to properly design fracturing fluids using flowback and produced water. The importance of flowback water analysis is highlighted for optimizing fluid performance downhole. Recent developments in proper selection of fluid additives and viscosifiers for slickwater and crosslinked fluids are discussed. We will describe in detail how the salinity, biological activity, and scaling tendency of these waters can impact fluid performance. Other factors, including organics and suspended solids will be included in the discussion. Laboratory examples will be shown to demonstrate the importance of following a systematic approach. Ultimately, this paper focuses on how to optimize well performance using recycled waters in stimulation applications. Introduction The exploration and production (E&P) industry in the United States generates approximately 210 bbls/day in produced water (Arnold et al., 2004). Other reports suggest that for every barrel of oil produced in the United States, 10 barrels (bbl) of produced water is generated (Khatib and Verbeek, 2002). Even though some of this material can be managed at the well site, many operators in the United States seek offsite management options for their waste. Offsite disposal companies must comply with state and federal laws including the Resource Conservation and Recovery Act (RCRA), the Environmental Protection Agency (EPA), the Clean Water Act (CWA), and the Safe Drinking Water Act. For instance, to discharge into surface water in Pennsylvania and Wyoming, the company must do so under a National Pollutant Discharge Elimination System (NPDES) permit or into a publicly owned treatment work (POTW). Typical costs associated with disposal range from $0.30 to $10/bbl for injection or cavern disposal to $15 to $22/bbl for solidification and burial in a landfill (Puder, 2007). Operators in the United States have reported that disposal and treatment costs for their produced water exceeded $400 MM/yr (Khatib and Verbeek, 2002). Finding alternative uses for flowback water in the E&P industry is both an economic as well as an environmental issue. In an effort to circumvent some of the extra costs, operators have reported the use of recycled produced waters in reservoir management processes (Khatib and Verbeek, 2002). Water treatment options have been discussed that include desalination, reverse osmosis, and 'floc 'n drop' methods but trucking costs associated with moving water to treatment facilities often make this an expensive option for operators (Kaufman et al., 2008, Horn, 2009). Literature has also been documented on the use of untreated recycled waters in high rate, low permeability shale reservoirs (Arthur et al., 2009). Water volumes for a typical slickwater hydraulic fracture treatment can average 715 m3 (6,000 bbl) per stage with 6 to 10 stages per horizontal well. Large treatment volumes for these applications offer a unique opportunity for cost savings if flowback water can be used in place of other fresh water sources. This approach saves on logistical problems as the water source is near the next treatment site.
Effective microbiological control is an important aspect of a successfully executed fracturing job. Control of bacterial growth is often accomplished through the use of biocides such as glutaraldehyde, particularly in the multi-stage, high-volume fracturing of unconventional shale gas reservoirs. Biocidal additives, which are toxic by necessity, can persist in flowback water, so their use in shale fracturing has come under increasing scrutiny since high biocide concentrations in flowback water increase fluid cost and limit the options for disposal. The case for designing a bactericide program to match, and not exceed, the required amount of bacterial control is clear, but rarely is the bacterial load determined during and after the job to verify this balance. Herein, we report a case study undertaken to evaluate the bacterial load of field mix water and flowback water during and after a large hydraulic fracturing job in the Marcellus Shale. A novel oxidative biocide product was used during the fracturing job that has both an effective fast kill and a low toxicity profile (e.g. HMIS rating of 1,0,0). Because of its rapid biodegradability, there was concern that the effective kill of this biocide would not persist beyond a few days. Industry standard techniques (NACE Std. TMO194-94) for quantifying bacteria were applied to water samples taken during the job and over several weeks of production. The biocide was also evaluated for compatibility with common fracturing additives and for its corrosivity to surface equipment and tubular goods. This study determines that the new biocide does not persist in flowback water beyond a few days. However, analysis of flowback water samples reveals that the bacteria count stays low (less than 10 cells/mL) for up to 81 days after application of this biocide in a slickwater fluid. Additionally, genetic fingerprinting using Denaturing Gradient Gel Electrophoresis Analysis (DGGE) was applied to the bacteria in the initial field mix water to allow comparison to any bacteria detected in the flowback samples. This paper will describe the details of this case study. Since the completion of this case study, we have successfully deployed this technology on treatments in the Barnett, Haynesville, Marcellus, and Granite Wash shale regions. This paper reveals details of a field test and of the efficacy of this biocide as tested in flowback waters from the Piceance and Marcellus Shale basin. The results of the bacteria enumerated from each job site sample are presented. Finally, dosage requirements for biocidal efficacy were optimized for slickwater hydraulic fracturing applications are described.
Slickwater fracturing is a large portion of current stimulation treatments in tight gas reservoirs. The fluids typically contain only friction reducer and biocide. They are considered incredibly simple, with little attention paid to their composition beyond the effects of water quality. In many cases, the biocides are sold and added to the fluid stream by production chemical companies while the friction reducers are added by the service company performing the fracture treatment. The paper reviews the chemical interactions between the typical anionic friction reducers and the cationic biocides such as quaternary ammonium compounds. The impact of these biocide-friction reducer interactions is that both materials are consumed and therefore prevented from performing their desired functions. During a treatment this is not obvious, but additional friction reducer eventually must be added to control pumping pressure. Further, the biocide is expected to be unavailable to control bacteria. The goal of any stimulation fluid should be that all components are compatible. As expected, some biocides complex with the oppositely charged friction reducers. This results in the formation of flocks of insoluble polymers in the fluid. Laboratory testing and a field example indicate that the quaternary ammonium biocides reduce the drag reduction seen with the common friction reducer. In comparison, nonionic biocides such as gluteraldehyde do not interact with the friction reducer. The paper also reviews studies with compatible scale inhibitors. Introduction Many key technologies have lead to the economic development of low permeability shale reservoirs (Boughal, 2008, Cramer, 2008, Palisch et. al., 2008). These include horizontal drilling, multiple fracture treatments, real time microseismic mapping, and simultaneous fracturing treatments (Daniels et. al., 2007, Fredd et. al., 2004, Penny et. al., 2006). The preferred fluid for most of these fracture treatments has been slickwater with low concentrations of proppant: usually 20/40 or smaller size sand. Slick water fracturing fluids have been unique successful due to the low leakoff present in most shale reservoirs. Shale is typically several hundred nano-darcy in permeability. Typical hydraulic fracture treatment volumes of are 715 m3 (6000 bbl) per stage with 6 to 10 stages per horizontal well. Slickwater fluids consist of friction reducer, biocide, and sometimes scale inhibitor. The friction reducer polymers are typically acrylamide co-polymers. Biocides are used to prevent souring of wells (Paulus, 2005). The most prevalent class of acrylamide friction reducers are the anionic copolymers. These polymers often contain acrylic acid which gives them their anionic nature (Sitaramaiah and Smith, 1969). Cationic friction reducers are used in acidizing, and can also be used in hydraulic fracturing fluids, but their cost is significantly higher than the common anionic types. Uncharged polysaccharide polymers like guar will give friction reduction, but the necessary concentrations are an order of magnitude greater resulting in significantly higher cost. So the industry has settled on anionic polymers as the friction reducer of choice. Friction reducer concentration is in many cases adjusted during the treatment "by feel" to try to lower pumping pressure or raise rate while staying within the working limits of the equipment. While the concentration of friction reducer is low, the cost to treat 715 m3 (6000 bbl) of fluid amounts to thousands of dollars. It appears that a large amount of this adjusting is not based on data or technical understanding. The friction reduction from an anionic polyacrylamide will be effected by the factors such as water quality and salinity of the water. It will also be affected by any other additives in the fluid which interact with the polymer.
Recovery of injected fluids from aqueous hydraulic fracturing applications can be enhanced by the use of flowback aids. These additives are typically surfactants or co-solvents that reduce capillary pressure and water blocks. A range of different types of flowback aids, which contain water-wetting nonionic to amphoteric and oil-wetting components, are commercially available for use in hydraulic fracturing applications. This paper evaluates various environmentally acceptable non-ionic and anionic surfactants for application as flowback aids in hydraulic fracturing applications. Fluid recovery was increased significantly with different alkyl polyglucosides and alkyl ethoxylates. Fluid recovery could be improved from 10% with base fluid up to 89% with the addition of a surfactant. Performance in fluid recovery corresponds best with surface tension data and capillary pressure reduction data, calculated from the surface tension and contact angle. Contact angle measurements alone cannot be used as screening tools for flowback aid evaluation. Heightened concerns about the environmental impact of chemical additives used in fracturing fluids along with new and pending environmental requirements have led to a demand for chemistries with reduced environmental impact. Products tested meet or exceed U.S. Federal or state environmental chemical compliance guidelines.
Successful matrix acidizing of carbonate reservoirs depends on the selection of optimal stimulation fluids. Because of the rapid reaction rate and corrosive nature of HCl in downhole conditions, other alternatives are much in demand. Organic acids, particularly methanesulfonic acid (MSA), offer a viable alternative to HCl in terms of being less reactive as well as less corrosive and environmentally benign. However, MSA is expensive. To reduce the cost, this study proposes to use blend of HCl and MSA for carbonate stimulation, while enhancing the properties of HCl. Coreflood studies were performed and the results were compared to those obtained by equivalent concentrations of the individual acids. Three different ratios of HCl and MSA were used to conduct coreflood experiments on 6-in. long Indiana Limestone cores at 250°F. The volume of acid required to reach breakthrough was recorded, and the cores were analyzed using CT scans. Wormhole structures were identified, and their tortuousities were determined. The effluent samples were analyzed for pH, calcium concentration, and unconsumed acid concentration. Coreflood studies indicated that 5:5 wt% HCl:MSA blend was the most suitable candidate for matrix acidizing among the three blends tested (2.5:7.5 and 7.5:2.5 wt% HCl:MSA being the other two blends investigated). At the optimum injection rate of 7.5 cm3/min, both 2.5:7.5 and 5:5 wt% HCl:MSA mixture required lesser pore volumes (PVs) of acid to reach breakthrough, compared to their individual acid controls. A single, straight, and dominant wormhole was observed with no branching and less tortuousity in both the cases. The control experiments with equivalent concentrations of HCl and MSA required higher PVs of acid to reach breakthrough with branching during wormhole propagation. Calcium ion dissolution was least for the 5:5 wt% mixture among the three blends tested. Higher unconsumed acid concentration was noted in case of 5:5 wt% compared to 2.5:7.5 wt% blend, thus promising greater penetration depth with the same PV of acid. On the other hand, the wormhole formed by the acid blend of 7.5:2.5 wt% HCl:MSA required almost the same PV of acid to reach breakthrough as its corresponding HCl control, and it was more enlarged and tortuous than its corresponding MSA control. 5:5 wt% HCl:MSA blend creates deeper wormholes and retards the HCl reaction with the rock matrix. Major advantages rendered by the new acid mixture include: (1) deeper wormholes that will ultimately result in enhanced well productivity, and (2) cost effectiveness in carbonate stimulation compared to standard systems currently used in the market.
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