Temporal analysis of flowback and produced water composition from shale oil and gas operations: Impact of frac fluid characteristics Seongyun Kim a , Pinar Omur-Ozbek a , Ashwin Dhanasekar a , Adam Prior b , Ken Carlson a,n a Colorado State University, Dept. of Civil and Environmental Engineering, Fort Collins, CO, United States b Noble Energy, Inc., Houston, TX, United States article info Article history: Received 8 November 2015 Received in revised form 30 March 2016 Accepted 9 June 2016 Available online 10 June 2016 Keywords: Flowback water Hydraulic fracturing Mass balance Water quality Well age abstract Flowback/produced water reuse cannot be optimized without a thorough understanding of the quality of the water that needs to be treated for reuse, including the temporal variability. Samples for flowback/ produced water were collected over a 200-day period (day 0 refers to when flowback began) from two wells. One of the frac fluids had an initial pH greater than 10 and used a guar-based gel and the second fluid contained a non-guar polysaccharide based polymer with an initial pH of less than 6. Total dissolved solids (TDS) and total organic carbon (TOC) were used as macro-indicators and key ions (barium, calcium, chloride, magnesium, sodium, strontium, boron and iron) were compared to TDS with the different frac fluids and there were significant positive correlations observed between the key ions and TDS with relatively high values of the coefficient of determinant (over 0.85). The concentrations of calcium, chloride, sodium and strontium are statistically equivalent between the two fluids. A mass balance ap- proach was applied to evaluate the quantity of mass of injected additives that was recovered over the 200-day period. Recoveries of zirconium, potassium and aluminum ranged from 3% to 33% after 200 days, and notable differences were observed between frac fluids. & 2016 Elsevier B.V. All rights reserved. 1. Introduction Energy demand is estimated to increase at an annual rate of 0.2% from 2010 through 2035, and electricity demand will grow by 0.8% per year (AEO, 2012). The successful development of the shale gas industry in the United States is expected to meet an increasing fraction of the energy demand and has spurred an interest in its potential in other parts of the world (Geopolitics and Natural Gas, 2012). In the U.S, the technically recoverable reserves of shale gas are greater than 1452 trillion cubic feet (USEIA, 2013), a supply that could potentially power this country for up to 100 years. The primary advantages of utilization of natural gas are its widespread accessibility, easy transport and relative to coal, clean combustion (Gregory et al., 2011; Jaramillo et al., 2007). However, the hydraulic fracturing process, used to enable economical pro- duction from low permeability unconventional reservoirs such as shale oil and shale gas formations, can place increased pressure on the use of finite natural resources such as fresh water, raising so- cial concerns in the community. Even though statewide estimates of water withdrawal for hydraulic fracturing has been estimated to be less than 0.1% of total water usage in Colorado (COGCC, 2012), there have been local issues related to water sourcing and com- petition. Recycling of flowback and produced water for beneficial use is being pursued in many parts of the country and this trend is expected to minimize concerns related to hydraulic fracturing and regional water depletion. The water demands for drilling and hydraulic fracturing are different depending on the formation depth, formation perme- ability, in-situ stress in the pay zone, in-situ stresses in the sur- rounding layers, reservoir pressure, formation porosity, formation compressibility, and the thickness of the reservoir (USDOE, 2004). In addition, fracturing fluid formulations may influence the vo- lume of water required for a particular fracturing treatment. On average, water consumption to complete horizontal wells is be- tween 2–5 milion gallons of water (Goodwin et al., 2012; Hick- enbottom et al., 2013; Lee et al., 2011; Nicot and Scanlon, 2012; Rahm, 2011; Stephenson et al., 2011; Suarez, 2012). The flowback/produced water recovered from fracturing op- erations during the completion of the well vary greatly in char- acter depending on location of the wells due to different forma- tions (spatial variation), the time the water is collected after well completion (temporal variation) (Barbot et al., 2013). The injected different frac fluid might also be expected to affect flowback/ produced water quality. However, there is no study investigating the flowback/produced water quality based on different frac fluid with temporal variation in Wattenberg field in Colorado. Reusing Contents lists available at ScienceDirect journal homepage: www.elsevier.com/locate/petrol Journal of Petroleum Science and Engineering http://dx.doi.org/10.1016/j.petrol.2016.06.019 0920-4105/& 2016 Elsevier B.V. All rights reserved. n Corresponding author. E-mail address: kcarlson@engr.colostate.edu (K. Carlson). Journal of Petroleum Science and Engineering 147 (2016) 202–210