In Search of the Waterless Fracture

What was once an emerging technology in the US has become the growth engine for oil and gas production globally, and the napalm-based mix that was used then looks like an anachronism.

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To meet the demand for larger stimulation volumes, GasFrac has used two of its units on a single well, allowing it to double the size of the fracturing job to 200 million metric tons a day at this site in Western Canada.

The first hydraulic fracture experiment was waterless. A gasoline gel was injected into the Hugoton field in 1947. What was once an emerging technology in the US has become the growth engine for oil and gas production globally, and the napalm-based mix that was used then looks like an anachronism.

But fracturing using hydrocarbons is on the short list of options for the industry, which is looking for an effective substitute for water in hydraulic fracturing.

Environmental questions have arisen about water use and water quality in unconventional resource development, which requires millions of gallons of water per well to open pathways for oil and gas trapped in nearly impermeable rock.

The Research Partnership to Secure Energy for America (RPSEA) has one waterless project in progress—to see if liquid nitrogen can fracture effectively—and the government/industry-funded research group is seeking more projects that experiment with waterless alternatives. “Water does work and has opened up the shale resources,” said Kent Perry, vice president of onshore programs at RPSEA. “(Fracturing) does take a lot of water. If you are in an area, particularly in parts of south Texas that are in a drought, even a little water is precious.”

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A worker wires lower-explosion level monitors before a fracturing job by GasFrac Energy Services. Proppant flows down from the vertical cylinder into mixers where it is combined with gelled propane before injection into a Canadian gas field.

 

Another driver for seeking waterless fractures is the search for a way to produce more of the oil and gas out of the ground. Oil recovery in unconventional formations is generally well below that of conventional formations, with 3% to 6% estimated ultimate recovery rates in many unconventional oil formations.

“If you recover 10% (of the oil and gas), you are doing well but you are leaving 90% behind,” Perry said. “It is not just the fracture treatment. The whole approach will have to be looked at within those resources.”

Waterless fracturing could also remove an impediment to tapping unconventional formations in many spots around the world: limited water supplies. During a panel discussion at the recent International Petroleum Technology Conference, Peter Voser, chief executive officer of Shell Oil, said he “told the R&D group to come back with the waterless fracture.” His comment was delivered in Beijing, where Shell has been aggressively pursuing unconventional exploration opportunities in a country that has both enormous unconventional natural gas reserves and water shortages over large areas.

The list of waterless possibilities under consideration includes breaking up formations using rocket fuel and using a cable saw to open up a formation. RPSEA did a preliminary evaluation of the latter method, called slot drilling (described in paper SPE 164547), and reported that it was not likely to open up as large an area as hydraulic fracturing, but the study using computer simulations is continuing.

For now, the only practical waterless options are hydraulic fracturing using oil and natural gas liquids (NGL) most of it in a select group of formations in Canada, where adding water has long been thought to reduce gas production. Gerald Schotman, Shell’s chief technology officer, said in a recent interview that fracturing using propane is one of eight or nine waterless options that Shell is evaluating. He declined to discuss the details.

A company has been testing NGLs to produce oil in a formation associated with the Eagle Ford trend in south Texas. BlackBrush Oil & Gas has used gas liquids to fracture 16 wells in three formations: 13 in the San Miguel, two in the Buda and one the Eagleford, said Phil Mezey, co-chief executive officer and chief operations officer of the company. They were pumped by GasFrac Energy Services, which developed the first closed system able to pump these volatile liquids into a formation.

Early results have been positive. Average initial oil and gas production is 77% higher per stage fractured using this method (Fig. 1) and, in the months since the project began, “we are definitely seeing higher cumulative production,” Mezey said.

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Fig. 1—Production totals from BlackBrush Oil & Gas show wells fractured using natural gas liquids (NGL) produce significantly more initially in liquids-rich unconventional formations in south Texas.

 

Just as important, BlackBrush has found ways to reduce the net cost of the butane and pentane it uses by formulating the fracturing fluid to ensure that it flows back with the oil and then can be sold. Mezey said the value of those sales has pared the cost difference down to 10% to 15% higher than water and, by year’s end, he hopes the net cost of using gas liquids after the value of the sales is included, will equal that of water.

Still the question remains: Can gas liquids produce better long-term results than water? Mezey’s answer is: “It is really hard to tell. It is early times.”

Water Sensitive

Waterless fracturing represents only a small slice of the fracturing business. Fluids mixing light oils and carbon dioxide are a mainstay in certain reservoirs where production is known to be particularly sensitive to water that is added during fracturing, such as the Cardium formation in western Canada.

Advocates for waterless say a broader range of formations could produce more if water is not used. “The advantage is that any liquid can soak into a low-permeability reservoir,” said Yu-Shu Wu, a petroleum engineering professor at the Colorado School of Mines. He is the director of the Energy Modeling Group, which does research on subsurface modeling. He is leading a project to see if liquid nitrogen can be used for fracturing. One argument offered for liquid nitrogen is that when it warms, it turns into a gas and flows out so “there is no formation damage, there is no productivity reduction,” Wu said.

Wu is trying to prove that he can economically deliver enough of the supercooled liquid into a well to cool the rock enough to extensively fracture a formation, and also deliver the sand or ceramic proppant needed to keep those passages open to allow long-term production.

The vast majority of fracturing uses water for hydraulic fracturing, but those working on waterless are working to convince the industry that the payoff for switching justifies the effort and expense of doing something different.

A presentation by BlackBrush shows its waterless fractures produce more initially and maintain a lead cumulatively during the first year. However, daily production rates in the NGL and water fractured wells are nearly equal after nearly one year.

BlackBrush is using the latest generation of equipment from GasFrac to increase the size of the fracturing jobs. Its production study was based on completions where the NGL fractures used about one-third the volume of liquid used in its waterfracs. Larger volume fracturing jobs using more gas liquids and proppant could mean greater long-term output.

Halliburton experimented with fracturing using liquid nitrogen in the 1990s and markets a fluid made of light oil and carbon dioxide that is designed to be viscous enough to deliver proppant into the well and then flow out with the gas production. But the dominant, growing part of its hydraulic fracturing business is based on water. Halliburton and other service companies are promoting recycling flowback water with systems to process the water.

“In terms of the total fracturing market, (oil-based fracturing) is a really small part and not a developing technology,” said Walt Glover, marketing manager of fracturing fluids at Halliburton. “There are very few situations in which we cannot develop a water-based fracturing fluid that will be very effective.”

The Water Left Behind

Considering the Possibilities

Doug McMillan, vice president of sales and engineering at GasFrac, realizes the 4-year-old company is swimming against the current as it tries to prove that propane-based fracturing fluid can in some cases be more effective than water. “There is a tremendous amount of capital (invested) in water technology,” he said. “Inertia is going in a different direction than we are.”

The company’s drive to do fracturing using natural gas liquids required that it develop a closed, pressurized system that could safely deliver volatile liquids, such as propane, and turn them into a gel. That concept is not so different from the gel used on the first fracturing job in Kansas. “We are pumping jobs daily, that is the upside. It is a quite straightforward process and one of those things has been around for many years,” McMillan said.

As of early February, GasFrac had done 1,863 fractures at 657 locations. Multiple fractures at a location has become the industry norm. The average for GasFrac is creeping past 10 stages per well and it is on its third generation of equipment, each designed to do progressively larger jobs, McMillan said. The latest, called the hybrid LPG system, can do up to 20 to 30 fracture stages and deliver more than 300 metric tons a day, he said.

The production benefits promised with fracturing using hydrocarbons flow from the fact they leave nothing behind. Propane or butane vaporize and leave with oil and gas produced. Typically, more than half of the water used for fracturing stays in the ground. If water remains in the fractures, it could reduce the effective producing area by increasing the surface tension and hydrostatic pressure in the fracture network.

A private exploration and production operator with a large unconventional acreage position in Europe, eCorp, sees propane as way to open the door to exploration in a place where water supply and environmental issues have been a sticking point.

Robert Lestz, chief technology officer of eCorp, said propane fracturing could be an attractive alternative. But to go waterless, it is seeking a way to effectively transport proppant without using chemicals to thicken the propane.

Lestz described the goal as using proprietary material science to deliver the proppant into the formation using pure propane. If it can find a practical way to do that, Europe may prove to be the best starting point for a new approach.

Sticker Shock

One of the biggest barriers to fracturing without water is the cost. The high cost of the oil needed for fracturing with oil-based fluids makes recycling a must in order to manage the expense, said Robert Taylor, manager of the Canadian reservoir studies team at Halliburton. With more fractures being done per well, the cost looms larger. “The big thing is the cost of the oil,” which is magnified by wells with as many as 20 stages to fracture, Taylor said.

Using oil or NGLs requires creating a way to pare that expense by reusing or selling the fracturing fluid along with the output of the field. When oil has been used for fracturing fields in Canada, operators managed the cost by installing the processing facilities on site to produce their own gas liquids out of the production.

Waterless fracturing has presented major logistical challenges for BlackBrush. It is leaning on the expertise of a sister company in energy marketing to acquire the truckloads of NGLs it needs and to reformulate the fracturing fluid so it can be sold along with the oil produced.

The mixture was changed to heavier gas liquids, such as butane and pentane, from propane which caused production issues—it bubbled out of the oil produced and when in the gas stream, compression caused it to condense. The new blend created a fracturing fluid that mixed well with the oil and could be sold to offset the price of the fracturing fluid.

Mezey said the price difference with water, which was initially around 0%, has been narrowed. (Fig. 2 and Fig. 3) The goal is to be equal to the cost of fracturing with water by year end.

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Fig. 2—Wells produced using different mixes of natural gas liquids (NGL) hold a lead in cumulative production over water in terms of barrels of oil and its energy equivalent of natural gas produced in BlackBrush’s south Texas wells, many of which are in tight sandstone formations. 
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Fig. 3—Over time the daily output converges for wells fractured using water and natural gas liquids. BlackBrush is increasing the volume of gas liquids used—the amount of NGLs used has averaged less than half the water used—to see if a comparable size fracture job will mean improved long-term performance. Source: BlackBrush Oil & Gas Presentation.

 

Over that time, BlackBrush plans to use GasFrac to complete about 16 more wells and it will be trying waterless fracturing in a deeper horizon, the Eagle Ford formation, where the pressure is higher. Mezey described it as normally pressured.

BlackBrush is building the track record needed to show if NGL can deliver better value than water. It is a slow process. Gasfrac recognized the long-term nature of the process late last year when it went through a major downsizing and a change in its top executives. The problem was it overestimated how fast the technology would be adopted. “I think a lot of people expected it to happen like flipping a light switch,” McMillan said. “It is much more complex than that.”

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This GasFrac worker is in charge of monitoring the data gathering. Staffers managing the job and controlling the pumping units also work in the trailer. A second trailer is the hub of the safety system that uses a variety of methods to detect leaks.

 

Taylor wonders if an industry, looking to maximize production from oil-producing shales, will try some older ideas, such as its oil/CO2 mix, marketed as MisCO2 Frac Service—short for miscible carbon dioxide—and Halliburton’s My-T-Oil V service, which provides oil-based gels.

“It was widely used in Canada 14 to 20 years ago, then they moved into coalbed methane and it was not used there or in shale gas,” Taylor said. “We have gone full circle. As the industry focuses on liquids rich shale, perhaps some lessons of the past” will be of use.

The Power of Cold

For Further Reading

SPE 124480 Case Study of a Novel Hydraulic Fracturing Method That Maximizes Effective Hydraulic Fracture Length by Eric H. Tudor, Gasfrac Energy Services, et al.

SPE 143113 Montney Fracturing-Fluid Considerations by R.S. Taylor, Halliburton, et al.

SPE 2006-168 Optimized CO2 Miscible Hydrocarbon Fracturing Fluids by R.S. Taylor, Halliburton, et al.

SPE 51067 Cryogenic Nitrogen as a Hydraulic Fracturing Fluid in the Devonian Shale by Steve R. Grundmann, Halliburton, et al.

SPE 164547 Evaluation of Well Performance for the Slot-Drill Completion in Low and Ultra-Low Permeability Oil and Gas Reservoirs by T.O. Odunowo, DeGolyer and MacNaughton/Texas A&M University, et al.

SPE 127863 Impact of Water Dynamics in Fractures on the Performance of Hydraulically Fractured Wells in Gas-Shale Reservoirs by Y. Cheng, SPE, West Virginia University