By: Andy Maslowski
July/August 2009

What would you rather have in your possession? One thousand barrels of oil or 1,000 barrels of water? That’s an easy question to answer. You’d take the oil! However, what would you do if you had to take them together, and not separately?

Unfortunately, oil and gas producers often face this dilemma. They have to deal with produced water at some point. It just comes with the territory. But depending where a company operates, there are still a number of choices of what to do with the stuff.

Disposal methods
There are many crude oil and natural gas wells that do not make any water when they start producing. That’s a beautiful thing! But after a certain amount of time, probably most wells start producing some associated water too. Due to the nature of most oil and gas reservoirs, the materials are not mutually exclusive. So formation water usually gets into the borehole and rises to the surface.

Countless laws regulate oilfield wastes — federal and state. To understand all of them, a company would need a bevy of regulatory law attorneys to accompany their fleet of water hauling trucks! In lieu of that, it’s safe to say that some kind of permit is required before attempting to dispose of oilfield water, or a company may choose to use a licensed and certified commercial waste hauler to do this necessary job.

Produced water is not a hazardous material, as defined by the federal government — at least not yet. In 1980, the U.S. Congress exempted oil and gas E&P wastes, including produced water, from the hazardous waste management requirements of Subtitle C of the Resource Conservation and Recovery Act (RCRA). But every year there are groups trying to reverse this legislation.

Federal laws like the Safe Drinking Water Act and the Clean Water Act requires that all discharges of pollutants to surface waters (streams, rivers, lakes, bays and oceans) must be authorized by a permit issued under the National Pollutant Discharge Elimination System (NPDES). Furthermore, the U.S. Environmental Protection Agency (EPA) has developed underground injection control (UIC) regulations to guide the states in establishing their own programs.

Normally, oilfield water is injected into wells that are categorized as Class II injection wells. These are wells used to dispose of “oil and gas waste,” a term that is defined to cover “saltwater and other produced fluids, wastes associated with the underground storage of hydrocarbons, enhanced recovery of oil and gas, and wastes arising out of, or incidental to, the operation of gasoline plants, natural gas processing plants, and pressure maintenance plants.”

Each producing state can add its own regulations above and beyond the federal EPA’s UIC guidelines. For example, the Texas Railroad Commission (RRC) has been active in the regulation of underground injection activities for more than 70 years. The first permit to inject water into a productive reservoir was issued in 1936.

The RRC has broad authority to do so under the Texas Natural Resources Code and the Texas Water Code. This gives the agency oversight of injection, disposal and hydrocarbon well permits already issued, as well as the processing of new permit applications. It works in coordination with the EPA and other federal and state agencies “in a concerted program to protect fresh water resources in Texas.”

Because Texas is a leading drilling and producing state, it is also a big water injection state. For February 2009, the RRC reported there were more than 148,000 producing oil wells and 91,000 producing natural gas wells in the Lone Star state. To help service these, there were more than 30,000 injections wells, injecting water, air or carbon dioxide into a productive formation to increase production. There were also more than 5,000 “Type 1” disposal wells, placing produced water into a non-productive formation for disposal.

Commercial disposal wells are spread across the state, and dozens of permitted oil and gas waste haulers are operating in Texas. These are all clearly identified in RRC records. For instance, in the giant East Newark Field, a Barnett Shale producing field covering some 19 counties, there were 10,539 producing gas wells in March 2009. To service these wells, there were 117 injection wells, three surface waste disposal facilities and 24 commercial saltwater disposal wells on record, with new disposal permits pending.

That really isn’t so many disposal wells for the amount of producing wells covered. But generally speaking, natural gas wells do not make as much produced water as oil wells. However, one cannot speak in general terms in the oil business! There are always exceptions to the rule. Just look at coalbed methane wells. Many of them make tons of water, and they are just gas wells.

In addition, some shallow producing wells — including coalbed methane wells — generate fresh water as the produced water, and not saltwater. Depending on the characteristics of the site and the chemistry of the produced water, it may be reinjected into the subsurface, dispersed on the surface, pumped into evaporation ponds, released directly into local streams, or spread on dirt roads for dust control and other purposes.

Remember, each state follows somewhat different permitting procedures and has different discharge standards. Some states also allow annular injection, where produced water is gravity-fed into the annular space between the surface casing and the production casing of a producing oil or gas well. Usually this method disposes of brine produced on the lease or nearby and has a daily limit, say allowing only 10 barrels per day.

Managing costs
Obviously there is a huge environmental and regulatory responsibility for disposing of produced water. However, there is also a financial element to the equation. Disposing of produced water affects the economics of the producing lease. The more water, the more it can cost. At some point it may not be worth the effort.

For instance, a shallow oil well giving up small amounts of fresh water might discharge it into a nearby stream, depending on local rules. Or an offshore platform might send 1,000 barrels of produced water a day into the ocean, after it is certain there is no oil, grease or other contaminants in it. Salinity is normally not a problem for offshore work, so the majority of produced water there is often released into the sea.

At the other end of the spectrum is produced water that must be treated and transported dozens of miles away to a commercial disposal well. In this case, it might cost up to or more than $5/barrel to complete and inject a truck load of water.

Water volumes
Volumes of produced water also differ considerably. The DOE reported produced water volumes may be as high as 10 times more than crude oil production in this country. The DOE calculated more than 14 billion barrels of produced water were handled in the U.S. in 2002, compared to about 1.5 billion barrels of domestic oil production for the year.
Others put the annual figure in the 15-20 billion barrel range. But no one knows for sure. Early in the life of an oil well, the oil production is high and water production is low. Over time production characteristics reverse themselves with some older wells producing a water-to-oil ratio of 50:1 or higher!

Some states provide produced water estimates and some don’t. And then there is the entire offshore disposal situation, sometimes from platforms more than 100 miles from the coast in waters deeper than a mile.

The Wyoming Oil and Gas Conservation Commission reported the top 10 water producing fields last year, by themselves, yielded more than 1.6 billion barrels of water. Much of that came from coalbed methane fields such as the Powder River Basin Coalbed Field.

In Alaska, more than 1 billion barrels of produced water was processed in 2004 — the last year detailed information was collected. The actual total was 1,111,439,663 barrels, as reported by the Alaska Oil & Gas Conservation Commission. Most of that was handled on the North Slope, from the Prudhoe Bay fields (489 million barrels of water) and Kuparuk River pools (263 million barrels of water).

California is another big water state. The California Department of Conservation, Division of Oil, Gas and Geothermal Resources, reported more than 5.5 billion barrels of produced water were handled in 2007 — all in an effort to produce more than 243 million barrels of oil and 312 Bcfg for the year.

So water disposal does affect the bottom line of oil and gas operations. And be assured that there will be no government bailout for this necessary expenditure.