Water Misers: How new waterless fracturing technology could cool environmental worries in dry environments


Water, its use, management and protection, is a central economic, ecologic and social concern when considering the practice of hydraulic fracturing.

“Putting it into the wells, what you get back is actually very unfriendly. Disposing of that is costly and has an environmental impact,” says Grant Nevison, executive vice-president of industrial gases at Millennium Stimulation Services. He adds that water fracs are typically greenhouse-gas (GHG) intensive as well.

MULTILATERAL STIMULATION  Fishbones' Dreamliner system drills laterals into the formation using rig pumps to circulate the drilling fluid already in the well. A number of small diameter laterals jet out from the wellbore to penetrate the reservoir. (IMAGE: FISHBONES AS)

“Following a frac, generally a well is vented into the atmosphere, because that is the lowest pressure source and you are trying to get out all or as much of this water as you can. Of course, natural gas accompanies that and just percolates into it—native natural gas. With that, [operators] vent and flare at the end of every treatment to get that flow started and to get the water out of the well.”

With water worries on the minds of producers, regulators and the general public, companies are looking to new methods that reduce or even eliminate water use in fracturing. At Millennium, the solution is to take what is essentially LNG and pump it downhole. For Norwegian-based Fishbones AS, solving the water issue involves a mechanical medley of pipes containing several titanium needles to bore through rock, making tiny laterals.

“There are a lot of positive benefits from the reduced amount of fluids being pumped,” says Kevin Rice, Fishbones’ North American regional manager. “What is required on location is a huge amount of reduced horsepower required to do any type of hydraulic treatment.”

He adds, “We are by no means trying to replace fracturing, but there are places and certain applications where fracturing just doesn’t make sense for one reason or another, and in those situations sometimes Fishbones is a good fit.”


Fishbones has two methods for deploying its technology, depending on whether the target formation is carbonate or not. For limestone and chalks, the tiny needles actually bore by squeezing out a hydrochloric acid solution that dissolves rock to create small tunnels for the needles to extend further and further from the mother bore.

“Hydrochloric acid is a natural substance,” Rice says. “It is actually pretty much the same thing that your stomach has, and so it is quite a natural phenomenon.”

Fishbones' Dreamliner. (IMAGE: FISHBONES AS)

Vast tracts of the Middle East, U.S. and much of Mexico produce hydrocarbons from carbonate reservoirs. However, there are also traditional sandstone reservoirs that do not react to hydrochloric acid. Therefore, Fishbones also deploys a version of its technology with hundreds of small drillbits.

“In certain cases, we have had a 30-time increase in the productivity index, which is a method of measuring production,” says Rice. While Fishbones uses some water in its process, such as to deliver diluted acid into the carbonate rock, the amount of water used is relatively small—in the order of thousands of gallons—compared to a typical hydraulic fracturing job, which can use millions of gallons of water, he adds.

“One of the things that is quite different about our system as well is that we actually place the Fishbones laterals at certain depths along the well. We can actually target points of the formation to hit, and we know how far into the formation our laterals actually go…. This allows operators to potentially avoid portions of the formation that produce a lot of water.”

The most notable limitation to Fishbones is its focus on conventional oil and gas plays, according to Rice. The company does not yet tackle unconventional reservoirs, simply because the nature of shale-type plays is that they call for fracturing treatment that opens up to the largest volume of payload possible, and at the moment Fishbones’ technology does not increase contact area to the same degree as does hydraulic fracturing.

“We have some things on the horizon of our development that might make us more favourable for use in those types of reservoirs, but at the moment it is just not our focus.”

In Canada, he notes, the company is thinking about how its methods could be applied to SAGD operations in the oilsands. “We think we have a very strong position to be used in the injector side of SAGD well pairs, actually helping distribute steam in the reservoir, getting past many barrier and baffle issues created by shales, mudstones and those sorts of things in certain parts of the oilsands.”


CO2 cannot remain in a liquid state above 31.1 degrees Celsius at 7.38 megapascals, and so when Ferus pumps an emulsion made up of 70 per cent liquid CO2 into the formation, it gasifies, expands (one cubic metre of liquid CO2 equates to about 542 cubic metres of gaseous CO2) and then pushes the 30 per cent polymer-gelled aqueous phase out of the fracture, leaving behind proppant. The method typically reduces water use by 70–80 per cent.

“All of our CO2 is recovered from high-emitting man-made sources in Canada. Gas plants, fertilizer plants—we currently have three facilities in Alberta that recover the CO2. It is then chilled into a liquid form and is transported to site,” says Murray Reynolds, director of technical services at Ferus.

According to Reynolds, using liquid CO2 is nothing new, and has been part of the upstream oil and gas industry for roughly half a century. What is new are the large, increasingly-commonplace multistage fracs, and so what his company is doing is offering a new application to an old technology. Ferus recently completed a large job using liquid CO2 in the Bakken for Statoil ASA, as well as in the Foothills for Husky Energy.

“[In] certain formations you are going to see more benefits from using CO2 versus slick water. We are not seeing this as a panacea for every formation, and you are not going to see a huge benefit for every formation. But certainly [it benefits] any of the water-sensitive formations in the deep basin or Montney, or even the Cardium.”

He adds, “If you want to save water or you can’t access water, or you have trouble finding water, this will certainly work, and it will work as well as slickwater-based fluids. The [Alberta Energy Regulator] is putting water restrictions in certain areas due to low stream flows and low river levels, and so this is certainly an option for people who are interested in saving water.”

Currently, once Ferus deploys the CO2, about 30 per cent is sequestered in the formation as it latches onto connate waters, formation waters and rock surfaces. The other 70 per cent is vented at the surface. “We do have long-term plans to capture it,” Reynolds says. “We are in the researching phase, and we want to eventually capture that CO2 and reuse it. But that is still a few years down the road.”


Environmental regulations and economic stability are key reasons for deployment of Energized Natural Gas (ENG) as a fracturing solution, which Millennium says enables a virtually complete replacement of water volumes while also eliminating the need to vent or flare gas emissions into the atmosphere. Millennium’s solution also improves well production and recovery.

GAS SUBSTITUTION  Replacing water with natural gas allows Millennium to dispense with the problems that come with sourcing and treating water, while improving production. (PHOTO: MILLENNIUM STIMULATION SERVICES)

“Natural gas is a resident component in the reservoir versus nitrogen or CO2, which are not,” says Michael Heier, president and chief executive officer. By using natural gas for the foam frac, a commodity already in the reservoir, what comes back up can simply go online with the produced hydrocarbons, says Heier, who was founder of service company Trinidad Drilling.

Unlike GASFRAC Energy Services, a company which used propane gel in place of pressurized water to frac shale formations before recently going out of business, Millennium uses LNG as an energizer rather than as the primary carrying fluid.

“From an economic perspective, on a plant basis we can generate LNG at current gas prices for probably around the same price—and maybe even slightly better—for what you would pay to produce nitrogen. I can give it to the clients for what they actually pay for nitrogen, and still make a reasonable return in the plant. The rest of it is the same process—whether a nitrogen or natural gas frac, it is the same equipment and same process.”

According to Nevison, ENG replaces liquid volumes with natural gas ones. If done on a water frac, the process can replace up to 90 per cent of the water. At that point, he says, companies could just move over to frac oil or produced oil to make up the remaining 10 per cent.

“That way, we can either (a) reduce water if the operator feels he needs water, or (b) we can eliminate [water] if hydrocarbons are an option. The beauty of this is that as soon as we start reducing water, we also allow the operator to flow the gas injected immediately back to the pipeline. It is beneficial not only in regards to getting rid of water, but also managing [GHGs].”

By putting less liquid in the reservoir, Nevison adds, there is less liquid to get trapped and block oil and gas production, and therefore operators will actually achieve better performance on their wells. “We take natural gas that has been produced anywhere in the field and we liquefy that by essentially cooling it down to LNG, which is just condensed natural gas that is at atmospheric pressure, but is very cold at about -160 degrees Celsius.

“It is cryogenic, and that is something the oilfield already deals with every day—cryogenic liquids with, for example, liquid nitrogen use.”

The only limitation Heier sees with ENG is it might require new infrastructure in some areas to chill the natural gas. However, the process could prove to be a key solution in regions where operators might want to do multistage fracturing, but where an adequate water source is hundreds or even thousands of kilometres away.

“You might have to make all your fracturing fluids out of what pre-exists in the reservoir. We bring that opportunity to the table where you can take your condensates or native crudes coming out of the reservoir, and we are treating them so you can safely pump the native hydrocarbon liquids along with the ENG cryogenic side. This creates an all-hydrocarbon fracture [that] eliminates flaring and water requirements, leading to reduced carbon footprint,” he says.

By Carter Haydu


KaBOOMing The Problem: Exploring explosions as an assist to fracturing

Quite literally, Zdeněk Bažant proposes an explosive solution to increase the amount of gas that can be extracted with the same amount of fracturing water, and thus reduce the amount of water required for the same amount of gas. Comminution, in which the solid material gets reduced to small particles, could break up rock via shockwaves from chemical explosions or electrohydraulic pulse.

“Explosive events with comminution materials can affect a region of a few metres around the borehole,” says the Northwestern University engineering professor. “That way, it can loosen any blockages that exist so the gas and oil can escape.” However, Bažant notes, this method cannot altogether replace conventional fluid fracturing, because the area impacted by explosion is too small compared to the pay area producers are trying to access.

“It has potential as a secondary measure to improve the gas flow…but it will not be the main procedure to comminute or create the many, many fracs in the fracking stage. The reason is that the power of shockwaves from the explosion decays too fast with distance and becomes too weak at far enough distances.” He adds, “There is some possibility of multiple, simultaneous explosions…but we have not explored that.”

So far, according to Bažant, research into comminution for unconventional hydrocarbon production has been largely empirical. The next phase of research requires a theory that provides theoretical understanding and predicts the spread of hydraulic fractures; a theory that predicts the fracturing energy, crack fields, the role of water viscosity modification and of the proppants.

To this end, theEvanston, Ill., university has research funding from the U.S. Department of Energy and Los Alamos National Laboratory. “Probably, if [industry] were to use explosions, then what is being explored and is most promising is the electrohydraulic shock—basically, a big spark is discharged,” says Bažant.

“That can create explosions much bigger than chemical explosions, because a typical diameter of the pipe [or steel casing] is only about four to six inches, and you just cannot pack enough explosive materials in that tight space. However, electrically we can create much bigger explosions.”

According to Bažant, oil and gas companies are interested in his research, which he expects to produce results in two or three years, perhaps delivering a computer code that would assist the fracturing crews in order to optimize results. “We see the explosions as a sort of assistance, but still the main thing is to do fracturing by the pressurized fracking fluid. Here, the objective is to create more cracks with the same amount of fracking fluid.”

He adds, “If you increase efficiency and extract maybe twice as much gas with the same amount of water, then that is an enormous environmental benefit, because there is half as much fracking water required for the same amount of gas. This is the aim.”



Zdeněk Bažant, Northwestern University, Tel: 847.491.4025, Email: [email protected]


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