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Used extensively by the food, chemical, and pharmaceutical industries, the mechanical-vapor-recompression (MVR) process is viewed as a reliable method for recovering demineralized water from concentrated brines. Devon Energy has supported the operation of an advanced MVR system at a north-central Texas (Barnett shale region) treatment facility. At this facility, pretreatment included caustic addition and clarification for total-suspended-solids and iron control. Pretreated shale-gas flowback water was then sent to three MVR units, each rated at 2,000-2,500 B/D (318-398 m 3 /d). Data were collected during a 60-day period in the summer of 2010. Distilled-water recovery volume averaged 72.5% of the influent water to the MVR units. The influent total dissolved solids (TDS) fed to the MVR units averaged just under 50 000 mg/L. More than 99% of the TDS were captured in the concentrate stream. The fate of multivalent cations; total petroleum hydrocarbons (TPH); and benzene, toluene, ethylbenzene, and xylenes (BTEX) throughout the treatment system was determined. Most of the iron and TPH removal (90 and 84%, respectively) occurred during pretreatment. The total removal of iron, magnesium, calcium, barium, and boron from the distillate exceeded 99%. BTEX removal from the distillate exceeded 95%. Electric power at the facility was provided by two natural-gas generators, and compressors associated with the MVR units were driven by natural-gas-fueled internal-combustion engines. Energy requirements at the entire treatment facility were tracked daily by total natural-gas use. Best-fit correlations between treated water and distillate production vs. total plant use of natural gas indicated that there was a base power load throughout the facility of approximately 120 to 140 Mscf/D (3400 to 3960 m 3 /d) of gas. Approximately 48 scf natural gas/bbl influent water treated (270 m 3 /m 3 influent) or 60.5 scf/bbl distillate produced (340 m 3 /m 3 distillate) was required; this represents an energy cost of less than USD 0.25/bbl treated (USD 0.04/m 3 treated) and approximately USD 0.30/bbl of distillate product generated (USD 0.048/m 3 distillate), assuming a natural-gas cost of USD 5/million Btu (USD 4.72/GJ). Performance in terms of water recovery and product-water quality was stable throughout the 60-day test.

A major cost consideration in the use of anaerobic digestion to convert biomass and waste to utility-grade gas is the expense of separating CO(2) from the product gas. Anaerobic digestion has a number of inherent properties that can be exploited to increase the methane content of the gas directly produced by the digester, the most important of which is the high solubility of CO(2)(40-60 times that of methane) in water under digestion conditions. The methane enrichment concept examined in this study involved the recirculation of a liquid stream from the digester through a CO(2) desorption process and the return of the liquid stream back to the digester for absorption of additional CO(2) produced by the conversion of organic materials. A steady-state equilibrium model predicted that a digester gas methane content exceeding 94% could be achieved with this scheme using modest recirculation rates provided a desorption process could be designed to achieve a 60+% CO(2) removal efficiency in the degassing of the liquid recycle stream. Using fixed-film laboratory digesters operated on synthetic feedstocks, the technique of methane enrichment was tested under pressurized and unpressurized conditions. A 93 + 2% methane gas stream was produced from a volatile-acid-fed bench-scale digester simulating the methanogenic stage of two-phase digestion under conditions of (1) a pH swing achieved without caustic addition that allowed digestion at pH 7. 5 and air stripping at pH 6. 5-7. 0, (2) digester pressurization to 30 psig, and (3) a recycle rate of 0. 33 L/L reactor/day. Significant but lower levels of methane enrichment were achieved with the single-stage digester at the low experimental recycle rate. However, the narrow range among all experiments of CO(2) desorption efficiencies achieved in air stripping the recycle stream (35-60% CO(2) removal) suggests that comparable methane enrichment-may be achieved with unpressurized single-stage digestion using greater recycle rates. A materials balance analysis of data from an unpressurized, single-stage digester employing no chemical addition and using laboratory degassing efficiencies indicated that 94% methane could be produced at recycle rates of less than 1. 4 L/L reactor/day with a methane loss of less than 2%.

Produced water accounts for greater than 80 percent by volume of the residual material generated in the natural gas industry. Cost-effective and environmentally acceptable disposal of these waters is critical to the continued economic production of natural gas. The Gas Research Institute (GRI) has recently completed a comprehensive assessment of the demographics of produced water characterized according to volumes and geographic location of the gas producing geologic provinces of the United States. This information in association with both the federal and state environmental regulations has been used to identify potential cost-effective produced water treatment research opportunities which are described in this paper. The study involved the use of a computer-based engineering- economic model, Produced Water Management Options Model (PWMOM), which combines engineering process models with a cost performance data base to predict the economics of a spectrum of unit water treatment processes and treatment trains. Various produced water scenarios, i.e., volumes, qualities and regulatory requirements, were evaluated and categorized to focus on the natural gas producing regions of the U.S. where produced waters could be surface discharged under the National Pollutant Discharge Elimination System (NPDES) Residual brines from produced water treatment would continue to be injected. Unit process technologies evaluated include deoiling (removal of free oil & grease), iron removal, dissolved organic removal (soluble organic treatment) and partial demineralization. Federal and state regulations were reviewed to identify where surface discharge could be or has been practiced to determine where cost-effective treatment could increase the opportunity for non-injection disposal alternatives. To complete this analysis, surface treatment costs were generated with PWMOM and compared to deep well injection costs. Costs for deep well injection were generated using Salt water Injection Model (SWIM), a model developed by GRI earlier in this research project. Promising technologies that have been identified include aerobic biological oxidation using fluidized beds, partial demineralization using electrodialysis and reverse osmosis, and a natural freeze-thaw evaporation process for cold climates. Laboratory and pilot studies that have been initiated to evaluate these processes are described here. Additional surface water discharge opportunities may exist where beneficial use such as irrigation or watering livestock is possible and where treatment will ensure that the release to surface waters will not violate water quality standards. Introduction The production of conventional natural gas and coal bed methane both result in the release of substantial volumes of water from the hydrocarbon bearing formation which is subsequently co-produced with the gas. This produced water is separated from the gas at or near the wellhead and must be disposed of in an environmentally acceptable manner. These waters are usually highly mineralized (containing total dissolved solids (TDS) concentrations in the range of 3,000 to greater than 100,000 mg/L for coal bed methane and conventional non-associated gas, respectively). More than 60% by volume of produced water is presently injected into specially designated injection horizons which are deemed to be geologically isolated from potential underground sources of drinking water (USDW). The percentage of produced water which is injected rises to greater than 90% if produced waters from oil, and oil and gas operations are also considered. P. 373