One element of DOE's produced water program focuses on produced water and the many issues associated with it. Several recent developments deserve notice.

Produced Water Management Information System (PWMIS) (http://web.evs.anl.gov/pwmis/). DOE's National Energy Technology Laboratory, in partnership with Argonne National Laboratory, has developed the web-based PWMIS. The new system offers critical information on current technologies and best practices, summaries of relevant state and Federal regulations and a decision tree for technology options to deal with produced water issues. PWMIS is an easily navigable web tool that consolidates all the required information in one location.

Desalination Unit. In a DOE-supported project Texas A&M University has developed a new technology to remove salts and minerals from brackish coproduced water, yielding safe drinking water. The project's mobile desalination unit can process as much as 238 bwpd. It enables one to re-use about 30 percent of a well's wastewater stream, reducing the volume and costs of salt water disposal. The technology has been licensed to GeoPure Water Technologies LLC to commercialize. View further information in DOE's Techline online at www.netl.doe.
gov/publications/press/2007/
070720-Oil_and_Gas_Produced-Water.html.

Guide to Management of Produced Water. The Interstate Oil & Gas Compact Commission (IOGCC) in cooperation with ALL Consulting has completed a comprehensive new guidebook to the current best management practices for produced water from conventional gas and oil operations. The guidebook, entitled A Guide to Practical Management of Produced Water from Onshore Oil & Gas Operations in the United States, is available through IOGCC's website (www.iogcc.state.ok.us/
projects.aspx). The project also developed an online geographic information system (GIS)-based analysis tool to help producers understand watershed-related regulations and permits and calculate the impacts of produced water in specific areas according to various oil and gas field development scenarios. The online guidebook and GIS tools will help regulatory agencies devise more effective regulations to make water management easier while still maintaining environmental protection.

being more costly than traditional  pits, that is not necessarily so. Cimarex Energy Co. described their experience using an engineered on- site drilling waste treatment system on nearly 40 wells in Lea and Eddy Counties, New Mexico. Cimarex found that the average cost of using a pit and hauling the waste elsewhere for disposal is about 45% more compared to following the same process without a reserve pit. When burying the waste on-site, costs are about 24% higher when using a reserve pit. Cuttings volumes are significantly less, some 60 to 70% less. To top it off, the footprint of the drilling operation is reduced.

Inc. (Englewood, Colo.), Fugro Airborne Surveys  (Mississauga, Ontario, Canada) and LaSen, Inc. (Las Cruces, N.M.), employs magnetic and methane sensors deployed on helicopters to accurately locate abandoned and leaking wells. Finding these wells is valuable for secondary and tertiary recovery projects, but it is absolutely critical in future CO2 sequestration projects. SEQURE, along with two other technologies developed in DOE-supported R&D projects, received an R&D 100 Award from R&D Magazine for 2007.

During a May 2007 EPA Natural Gas STAR workshop, Devon Energy Corp. shared their experience with reduced-emission or "green" completion practices in their Fort Worth Basin operations. With conventional practices, a well is flowed back to frac tanks until clean up is completed. Tubing is then snubbed in the hole while venting gas to atmosphere. Gas during required open flow potential tests is also vented to atmosphere. With reduced-emission completions, a temporary flowline and meter run is on location during completion. The well is flowed back to frac tanks until gas is encountered, at which time the well is turned to sales and revenue realized during further cleanup, snubbing and testing. In their Fort Worth Basin operations Devon's incremental costs are about $6,000 per well—but the incremental revenue from sale of captured gas is more than 10 times that. The work environment is safer and wells can be cleaned up longer. Since starting the practice in March 2004 through 2006, Devon had captured and sold about 3.7 Bcf of natural gas, realizing about $20 million in profits.