Currently 20-30 billion barrels of formation water are co-produced annually in the USA with conventional oil and natural gas. The large database on the geochemistry of this produced water shows salinities that vary widely from ~5,000 to >350,000 mg/L TDS. Chloride, Na and Ca are generally the dominant ions, and concentrations of Fe, Mn, B, NH3 and dissolved organics, including, BTEX, phenols and poly aromatic hydrocarbons (PAHs) may be relatively high. Hazardous concentrations of NORMs, including Ra-226 and Rn-222 have been reported in produced water from several states.

Coal-bed methane (CBM) wells currently produce close to a billion barrels of water and deliver ~8% of total natural gas. The salinity of this produced water generally is lower than that of water from petroleum wells; salinity commonly is 1,000-20,000 mg/L, but ranges to150,000 mg/L TDS. Most CBM wells produce Na-HCO3-Cl type water that is low in trace metals and has no reported NORMs. This water commonly has no oil and grease and has relatively low DOC, but its organic composition has not been characterized in detail. The water is disposed of by injection into saline aquifers, through evaporation and/or percolation in disposal pits, road spreading, and surface discharge. Water that has an acceptable salinity and sodium absorption ratio (SAR) is considered acceptable for surface discharge and for injection into freshwater aquifers.

As an alternative to costly disposal, low salinity produced water is being considered for reclamation, especially in the arid western USA. The cost of reclaiming this water to meet irrigation, industrial and drinking water standards was evaluated in a 10 gpm pilot field study at Placerita oil field, California. This produced water had a low salinity of ~8,000 mg/L, but high concentration of Si and organics. Removal of B, Si, NH3 and especially organics from this water proved difficult, and the estimated treatment cost was high at $0.08-$0.39/bbl for water treated for industrial and municipal uses.