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SPE International Symposium on Oilfield Chemistry | 2011

Case Study: Evaluation of an Oxidative Biocide During and After a Hydraulic Fracturing Job in the Marcellus Shale

Shawn McCleskey Rimassa; Paul R. Howard; Bruce Mackay; Kristel A. Blow; Noel Coffman

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. Introduction Control of microbial growth is an essential consideration in the design of fracturing fluids. (Brandon, et al., 1995) Because of their ability to rapidly degrade biopolymers such as guar, bacterial enzymes can seriously affect the rheology of traditional gels. Slickwater fracturing fluids, where viscosity is not critical and the (typically synthetic) drag-reducing polymers are unaffected by bacterial enzymes, also require a biocide strategy to prevent well damage. The re-use of produced water (PW) in slickwater campaigns raises the risk of introducing anaerobic bacteria to the well, because PW is generally less oxygenated (Seright, et al., 2009) and is often rich with inorganic nutrients. Acid-producing bacteria (APB), and sulfate-reducing bacteria (SRB) can cause problematic localized corrosion to completions and tubular goods. (Nemati and Voordouw, 2000) The latter can also be responsible for well souring and iron sulfide precipitation in the low-oxygen wellbore environment. (Carpenter and Nalepa, 2005) These and other general heterotrophic bacteria (GHB) can form biofilms that damage proppant packs and impair production flow, and can be problematic for surface equipment and even pipelines. (Bottero, et al., 2010). * BASF Corporation, Oilfield and Mining Division, as of 2010


Archive | 1997

Control of particulate flowback in subterranean wells

Roger J. Card; Paul R. Howard; Jean-Pierre Feraud; Vernon G. Constien


Archive | 1996

Suspension and porous pack for reduction of particles in subterranean well fluids, and method for treating an underground formation

Simon James; Paul R. Howard


Archive | 2007

Friction reduction fluids

Alex Ahrenst; Bernhard Lungwitz; Christopher N. Fredd; Carlos Abad; Nihat Gurmen; Yiyan Chen; John Lassek; Paul R. Howard; William Troy Huey; Zakir Azmi; Donald Hodgson; Oscar Bustos


Archive | 2006

Differential Filters for Stopping Water during Oil Production

Paul R. Howard; Philip F. Sullivan; Timothy Lesko


Archive | 2008

Polymer delivery in well treatment applications

Philip F. Sullivan; Gary John Tustin; Yenny Christanti; Gregory Kubala; Bruno Drochon; Yiyan Chen; Marie Noelle Dessinges; Paul R. Howard


Archive | 2009

Composition and method for fluid recovery from well

Syed Ali; Leiming Li; Paul R. Howard; Sumitra Mukhopadhyay


Archive | 2008

Method of treating subterranean formation with crosslinked polymer fluid

Leiming Li; Paul R. Howard; Carlos Abad; Michael D. Parris; Lijun Lin; Andrey Mirakyan; Richard D. Hutchins; Baudel William Quintero


Archive | 2011

TREATMENT AND REUSE OF OILFIELD PRODUCED WATER

Leiming Li; Paul R. Howard; Michael D. Parris; Bernhard Lungwitz; Kevin W. England; Richard D. Hutchins; Jack Li


Archive | 2010

Aqueous solution for controlling bacteria in the water used for fracturing

Kristel A. Blow; Syed Ali; Paul R. Howard; Shawn McCleskey Rimassa; Bruce Mackay; Leiming Li; Noel Coffman; Richard D. Hutchins

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