Hydraulic fracturing: new perspective leads to successes

Oklahoma and Texas are both home to thriving unconventional resource plays where hydraulic fracturing is unlocking the potential of hydrocarbon-bearing formations. However, the shift from vertical to horizontal fracturing of wells has brought with it the need for greater quantities of water and a greater awareness of drought conditions.

Yet year after year, summer weather forecasts for the High Plains and southwestern US promise plenty of high temperatures and zero chances for rain. In summer 2012, more than 90% of Oklahoma was categorized as being under extreme or exceptional drought by the National Drought Monitoring Network. A quick look at a drought map would show that Texas also was severely impacted.

This month’s E&P cover looks at new perspectives in alternative water usage, a novel application of treatment and stimulation designs in the Ordos basin, and proppant economics of the Eagle Ford shale.

Putting it all in perspective

The comparison between the amount of water needed to drill and fracture a single well one time and the amount consumed by the public provides perspective on freshwater usage

As the industry knows all too well, water management is critical. “It is during times of drought that the oil and gas industry is criticized for using freshwater that could be used for other purposes,” said Stephen Holditch, professor of petroleum engineering at Texas A&M University.

While the challenges facing the industry on water-related issues are numerous, in regards to the sourcing of water for operations, Holditch said that one challenge is “to put the use of freshwater by the oil and gas industry in perspective to other uses.”

According to the most recent report on estimated water use conducted by the US Geological Survey, water use was about 410 Bgal/d in 2005. Power generation, irrigation, and public consumption are all significant draws on freshwater supplies located on and below the surface. Fortunately, the hydrologic cycle works to replenish the supplies except during times of drought. It is when the supply gets tight that the public wants to know how much water it takes to frac a well.

“Hydraulic fracturing may use as little as 50,000 gallons of water in a conventional vertical well treatment. Multiple interval fracturing in horizontal wells may require 2 [million] to 6 million gallons per well,” said Steve King, US region sales and technical director of fracturing services for Weather-ford. “This is the total amount of water required to fracture a well. “Once a well is fractured and placed on production, it may be capable of producing for 20 to 30 years. Fracturing is not an ongoing process in a given well.” According to a Chesapeake Energy water use fact sheet, total water use in the Eagle Ford shale area in 2008 was approximately 64.8 Bgal. Primary water users in the area were irrigation (~70%) and municipal/ public water supply (~26%). To drill and fracture a single Chesapeake deep shale gas well in the Eagle Ford, it takes approximately 4.9 MMgal of water.

In the Marcellus shale, the fact sheet noted that the region used approximately 3.6 Tgal of water in 2000. The natural gas industry in the region is expected to increase that amount by less than 0.1%, which is well within available resources in the region.

And what happens in those areas, like the Eagle Ford shale, where the available resources may be a little tight? “The energy companies understand that water is a primary issue when it comes to having a license to operate,” said Michael Young, associate director for Environmental Systems and senior research scientist at the Bureau of Economic Geology at the University of Texas at Austin. “The companies are working to avoid using potable groundwater wherever they can. And this means using alternative sources.”

In this map showing drought conditions as of Aug. 21, 2012, it is easy to identify the many areas across the continental US, covering several unconventional plays, that have experienced drought conditions ranging from abnormally dry to exceptional. (Image courtesy of the National Drought Mitigation Center at the University of Nebraska-Lincoln)

Finding alternative successes

Several alternatives have been used, or are currently in use, in drilling and fracturing operations. While some have experienced success, the jury is still out on others as each brings a unique set of challenges that the industry is working to address.

One alternative is the use of recycled produced water. When Devon Energy Corp. drilled its first well in Oklahoma’s Cana Woodford shale play in 2008, company officials found that the flowback water was sufficiently low in salt content and could be reused without needing extensive treatment.

The company built a water recycling facility in the area that in the first three months of its operation in 2012 saved more than 1 MMbbl of water. Considering that the state was experiencing exceptional drought conditions, the facility could not have gone operational at a better time.

According to Devon spokesman Tim Hartley, field operators are very pleased with how the program is working. “The new facility was put into service around mid-year 2012 – from an idea for which no regulatory permitting process existed in 2008,” Hartley said. “At the time the facility was first proposed, there was no regulatory permitting process in place for it. This was due primarily to the size of the storage reservoir, which can hold 500,000 bbl or 21 MMgal of water.”

By the end of January 2013, the company expected to have 63 wells hooked up to the system, with the goal of connecting an additional 112 wells throughout 2013. The system has recycled 3.5 MMbbl of water to date. In 2013 it is expected that an additional 5 MMbbl of water will be recycled. “Devon has installed approximately 15 miles [24 km] of water pipe connecting our wells to the Cana water facility so far,” he said. “We expect to lay an additional 25 miles [40 km] of pipe to wells in the Cana during 2013.”

Another successful alternative is the use of saline or brackish water. For example, Apache Corp. uses saline water in its wells in the Horn River basin located in northeast British Columbia. The nonpotable water is from the Debolt subsurface brine aquifer located just above the Horn River shale.

Before it is used, the saline water is treated at the Debolt Water Treatment Plant. The plant produced approximately 95% of the water required for fracturing operations in Apache’s Horn River basin area in 2011.

“A total of one or two additives are mixed in with the water, usually a friction reducer and a small dose of biocide, and we frac the well with it,” said George King, distinguished engineering advisor for Apache Corp. “Produced water is then filtered and put right back into the formation. It is a closed-loop fracturing system.”

According to King, Apache and other companies have found that saltwater is equally as good as freshwater for fracturing. Consistency of the water quality, however, is the key.

“As long as you can keep the water quality relatively consistent – the consistency of the chlorides, the hardness, the calcium – then a service vendor can take that and, by manipulating the chemistry of the small amount of additives, actually get the friction reducers, biocides, and all of those things to work,” he said.

An add-on perk to using saline water out of an aquifer is that “we’re using water that’s been outside of the hydrologic cycle for a long time,” said Young. “We’re not losing any water that was originally part of the hydrologic cycle.”

Young added that if the flowback water is treated on site and made available for release into rivers or streams, then water is being added back to the hydrologic cycle, which is “very advantageous, particularly in areas that are water-short,” he said. “And that could be a new source of water for communities.”