Water. desalination + reuse

TECHNOLOGY RECYCLiNG iN TiGHT OiL - CONTiNuEd fROm p 30 organics removal, selective ion reduction, desalination and disinfection. Keeping in mind these six treatment objectives and the limitations of various treatment technologies, a proposed Flowback and Produced Water Treatment Decision Tree methodology is outlined in Figure 3, page 30. By applying the decision tree methodology (Figure 3) in contrast with the analytical data obtained (Table 5, page 29) and the water quality guidelines (Table 4, page 28), we are able to evaluate the magnitude of treatment required. Knowing that the Carbonates average 40% flowback (Table 3, page 27), we are able to evaluate the reuse profile in two different scenarios: (1) 60% frac (fresh) water + 40% flowback (2) 60% produced water + 40% flowback. In scenario (1), the treatment intensity requires de-oiling and solids removal, pretreatment for H2S and residual gelling agent removal, possible filtration depending on the particle size of the suspended solids, and disinfection. In comparison to scenario (2), the treatment intensity increases to include the addition of hardness reduction and some component of desalination. In scenarios (1) & (2), CaCO3, FeS, FeCO3, and SrCO3 precipitation is anticipated to contribute to subsurface scaling and fouling if left untreated. NExT STEpS Future research evaluating the reuse requirements of flowback and produced waters for hydraulic fracturing in tight-oil might examine the reuse requirements for alternate water-based hydraulic fracturing fluid systems (Table 1, page 27). In doing so, the researcher will be able to identify potential variances in treatment intensity requirements for multiple water-based fluid systems. Additional research might also choose to investigate the validity of the proposed Flowback & Produced Water Treatment Decision Tree (Figure 3). The validity of the proposed treatment approach might be investigated by conducting field-based water reuse trials incorporating various treatment technologies. Additional treatment challenges and alternate treatment approaches are anticipated to become more apparent through field- based water reuse trials. As industry becomes more comfortable with recycling flowback and produced waters, three outcomes are anticipated. First, chemical suppliers are determined to develop hydraulic fracturing fluid programs with enhanced tolerance to salts and other constituents present within the reuse waters. As these chemistries are introduced to industry, the treatment intensity to facilitate reuse for hydraulic fracturing in tight-oil is expected to decline. Second, as these waters are used in subsequent hydraulic fracturing stimulations, the threshold limits identified in this paper may prove to be overly conservative. This too would indicate a relaxation in treatment intensity requirements. Lastly, despite the pressure from stakeholders to recycle flowback, the numerous treatment challenges may influence operators to shift their efforts on optimizing produced water reuse to support Improved Oil Recovery (IOR) production activities instead. In most cases, the treatment intensity to reuse produced water in waterflooding applications will prove to be much more manageable with considerably less overall variability. l References Environmental Protection Agency: www.epa.gov/.../uic/.../ cbmstudy_attach_ uic_append_a_doe_whitepaper.pdf. 1. National Energy Board. (December 2011). Tightoil Developments in the Western Canada Sedimentary Basin. Retrieved 13 January 2012, from National Energy Board: www.neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/l/ tghtdvlpmntwcsb2011/tghtdvlpmntwcsb2011-eng.html. 6. R Dusterhoft , J McGowen and A Ghalambor (2009). Frac-Pakc Fluids. In A Ghalambor, S A Ali and NW David, Frac Packing Handbook (pp. 33-64). Richardson: Society of Petroleum Engineers. 2. D Stonehouse. (19 September 2011). Perfect Storm: Technological, royalty and regulatory changes create flash flood of conventional and tight-oil projects across central Alberta. Retrieved 13 January 2012, from JuneWarren-Nickle's Energy Group: www.junewarren-nickles.com/feature.aspx?id=8913. 3. Canadian Association of Petroleum Producers. (29 November 2012). Responsible Canadian Energy 2012 Progress Report Summary, page 30. Retrieved June 20, 2013, from Canadian Association of Petroleum Producers: www.capp. ca/getdocaspx?Docid=217606&DT=NTV. 4. American Petroleum Institute. (June 2010). Water Management Associated with Hydraulic Fracturing. Retrieved 24 January 2012, from American Petroleum Insitute: www. shalegas.energy.gov/resources/HF2_e1.pdf. 5. US Department of Energy. (June 2004). Appendix A Hydraulic Fracturing White Paper EPA 816-R-04-003, pages 3 and 16. Retrieved 23 January 2012, from United States 7. Environmental & Regulatory Subgroup of the Operations & Environment Task Group. (15 September 2011). NPC North American Resource Development Study Paper #2-1 Water/ Energy NEXUS. Retrieved 18 January 2012, from National Petroleum Council:www.npc.org/Prudent_Development-Topic_ Papers/2-1_Water_Energy_Nexus_Paper.pdf 8. Canadian Society for Unconventional Resources. (5 May 2012). Understanding Hydraulic Fracturing, page 23. Retrieved 17 May 2012, from CSRU: http://www.csur.com/images/ CSUG_publications/Hydr_Frac_FINAL_CSUR.pdf. 9. Aqualon. (2007). Guar and Guar Derivatives Oil and Gas Field Applications. Retrieved 18 April 2012, from Ashland: http://www.ashland.com/Ashland/Static/Documents/AAFI/ PRO_250-61_Guar.pdf. 10. R LaFollette (9 September 2010). Key Considerations for Hydraulic Fracturing of Gas Shales. Retrieved 25 April 2012, from Petroleum Technology Transfer Council: http://www.pttc. org/aapg/lafollette.pdf. August-September 2013 | Desalination & Water Reuse | 53 |

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