Notional Field Development Final Report - EBN

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EBN Notional Field Development Plan The Table above provides a summary of the additives, their main compounds, the reason the additive is used in a hydraulic fracturing fluid, and some of the other common uses for these compounds. Hydrochloric acid (HCl) is the single largest liquid component used in a fracturing fluid aside from water; while the concentration of the acid may vary, a 15% HCl mix is a typical concentration. A 15% HCl mix is composed of 85% water and 15% acid, therefore, the volume of acid is diluted by 85% with water in its stock solution before it is pumped into the formation during a fracturing treatment. Once the entire stage of fracturing fluid has been injected, the total volume of acid in a typical fracturing fluid for shale frac would be 0.123%, which indicates the fluid had been diluted by a factor of 122 times before it is pumped into the formation. The concentration of this acid will only continue to be diluted as it is further dispersed in additional volumes of formation water that may be present in the subsurface. Furthermore, if this acid comes into contact with carbonate minerals in the subsurface, it would be neutralized by chemical reaction with the carbonate minerals producing water and carbon dioxide as a byproduct of the reaction. 4.7.3 Flowback Water After a hydraulic fracture treatment, when the pumping pressure has been relieved from the well, the water‐based fracturing fluid, mixed with any natural formation water present, begins to flow back through the well casing to the wellhead. This flowback water may also contain dissolved constituents from the formation itself. The dissolved constituents are naturally occurring compounds and may vary from one shale play to the next or even by area within a shale play. Initial produced water can vary from fresh (
EBN Notional Field Development Plan Figure 4-72. Samples of flowback and produced water 4.7.4 Produced Water It is estimated that 97% + of the oil & gas waste generated (by volume) is produced water. After initial gas production begins to flow to the wellhead, the formation water is brought to the surface with the gas and is referred to as produced water. This natural formation water has been in contact with the reservoir formation for millions of years and contains minerals native to the reservoir rock. The salinity, TDS, and overall quality of formation water vary by geologic basin and specific rock strata. Produced water can vary from brackish (5,000 ppm to 35,000 ppm TDS), to saline (35,000 ppm to 50,000 ppm TDS), to supersaturated brine (50,000 ppm to >200,000 ppm TDS) and some operators report TDS values greater than 400,000 ppm. The variation in composition changes primarily with changes in the natural formation water chemistry. Treatment of produced water may be feasible through either self‐contained systems at well sites or commercial treatment facilities. Re‐use of fracturing fluids is being evaluated by service companies and operators to determine the degree of treatment and make‐up water necessary for re‐use. The practical use of on‐site, self‐ contained treatment facilities and the treatment methods employed will be dictated by flow rate and total water volumes to be treated, constituents and their concentrations requiring removal, treatment objectives and water reuse or discharge requirements. In some cases it would be more practical to first treat the water to a quality that could be reused for a subsequent hydraulic fracturing job, or other industrial use, rather than treating to discharge to a surface water body or for use as drinking water. © 2011 Halliburton All Rights Reserved 227
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