Frack Fluid Focus

From water heaters to long-life span pumps, frack-based service providers have options to reduce well completion costs with new approaches and technologies aimed at tried-and-true completion methods.
By Emily Aasand | May 14, 2015

Next-gen Water Heaters
Hydraulic fracturing a well requires 2 million to 9 million gallons of water. Some fracking experts believe water temperature is also important and that heated water ensures a better crude extraction possibility.  “Cold water mixing with hot crude in the ground makes a coagulation, whereas if you have hot water mixing with hot crude in the ground, it’ll increase the rate in which operators are able to pull out the crude,” says Dax Cornelius, CEO and managing partner of Torrid Technologies Group.

Torrid Technologies Group, a frack water heater manufacturer, got its start after recognizing a need for water heater services amongst energy service providers.  Cornelius and his team have developed a series of frack water heaters that are direct contact systems that typically prove a 99 percent efficient transfer of heat into water.

There are two kinds of water heaters being used in the industry. The current approach relies on heating metal coiled tubing, which then heats the water flowing through it. Torrid’s system takes out the middleman [coiled tubing] and directly heats the water causing an immediate transfer so there’s nearly a 100 percent efficiency, according to Cornelius. Since the company manufactures direct contact water heaters, there is nothing over 5 psi inside the systems.

“We were looking at these massive diesel trailers with these huge coil systems that could be very dangerous,” Cornelius added. “The current systems are almost like a pressure boiler with regards to heating water at such a high level, and those systems aren’t as safe as what we have designed.”

Torrid offers four sizes of propane-run frack water heaters: The 10 mm Btu Achillies, the 15 mm Btu Spartacus, the 30 mm Btu Hannibal and the 45 mm Btu Vulcan. All of which have a 500 GPM and vary from a 40 degrees Fahrenheit water temperature up to a 180 degree F water temperature.

The Montana-based company opened its doors in July 2014 and has four frack water heaters deployed in western North Dakota.

“While researching, we saw there was a huge gap in safety, there was a huge gap in the amount of emissions these units were emitting, and there was a huge gap in the amount of operation costs that it took to heat the water,” says Cornelius.

After looking into the water heating needs of the Bakken, the Torrid team found that in the summer, even if it is hot outside, operators are continuing to heat the water because the engineers want the water temperature going down the well at the same temperature no matter the season.

“We saw the demand, we saw the need, and that’s when we decided to start Torrid Technologies and provide a next generation frack water heater for the market,” Cornelius says. 

Thriving Market
With oil producers looking to cut costs at the well site, Torrid sees the price commodity as a perfect growth opportunity for the company. Cornelius says with the industry in the shape it’s in, Torrid has been able to be the answer to many of the markets’ questions. “Everyone is looking for faster, cheaper, smarter, more cost-effective, lower carbon foot printing ways to heat water for fracks.”

“We’ve probably seen a 35 percent increase because everyone is looking for that cheaper solution,” says Cornelius. “Everyone has to work harder and smarter to earn the business and make things better, not only from a profitability standpoint, but for the greater good of the exploration and production industry as a whole.”

Cornelius adds that as the market corrects itself, Torrid could nearly double its business by next winter.

“Our goal is to be identified as the next generation of frack water heaters for the industry. We’re tenacious on our growth game plan, we’re well funded and we’re in this market to stay because we believe we bring [a technology] to the table that every oil company would want under their operation.”

Cornelius says there are roughly seven to eight major frack water heating companies that provide services to the major oil groups in the Bakken and says his team is getting ready to launch its own frack water service to supplement its manufacturing this upcoming winter.

Under Pressure
For hydraulic fracturing engineers, a big problem on the job site is pump failure. Fracking currently requires multiple high-pressure pumps forcing a mixture of water, proppants and chemicals downhole to fracture the rock. Until now, the industry has been using reciprocating, positive displacement plunger pumps because it has been the only technology that has been rugged enough to process the high velocity, abrasive frack fluid.

Energy Recovery Inc., a pump provider, got its start in the water desalination industry and developed the company’s Cadillac piece of technology, the Pressure Exchanger. In 2008, Energy Recovery began to research markets in which its industrial fluid-flow applications could be prevalent and decided to target the oil and gas industry. Joel Gay, president CEO of Energy Recovery, says the company saw an opportunity for its technology to act as a pump where there was existing hydraulic energy that was being wasted at well sites.

“What we did was invent a solution exchanger that would replace the traditional hydraulic manifold, or missile,” says Gay. “Harnessing pressure energy the way we have in our other technologies, our solution ratchets frack fluid up to the required treating pressure, as high as 15,000 psi, without requiring the high-pressure water pumps to handle sand. This prevents the regular occurrence of pump failure, and has several immediate and profound impacts for operations, not the least of which is a dramatic reduction in maintenance.”

Roughly 18 months ago, Energy Recovery’s engineers conceptualized the VorTeq hydraulic pumping system that could use the company’s Pressure Exchanger to re-route abrasive proppants away from high-pressure pumps to ensure only pure water touches the pumps, expanding pump life spans.

Energy Recovery takes the hydraulic energy from the pumps—so they are only pumping clean water—and sends it at the desired treating pressure into the VorTeq missile, which will transfer that pressure energy to low-pressure frack fluid that goes directly to the missile from the blender and sends it down hole.

“The positive displacement pumps will no longer process proppant, they will only pump clean water,” says Gay. “Hydraulic fracturing engineers are going to be rebuilding the fluid end of their pumps far less frequently than they are today due to the fact that they are no longer pumping sand.”

The company believes that there are three distinct orders of value creation for this product. The first is the reduced repair and maintenance costs—clients use existing pumps and don’t have to rebuild them as frequently. The second is the opportunity for the service providers to reduce levels of excess capacity, which Gay says providers can use to outfit new fleets. The final value is that from a pumping model standpoint, Energy Recovery believes the VorTeq can redesign and redefine how fracking is done today.

This new technology allows operators to reduce current 15 to 20 positive displacement pumps down to three centrifugal pumps, Gay says. Centrifugal pumps are powered by a natural gas turbine generator set, which Gay says operators are already migrating to, to power existing pumps.

“You have a natural gas turbine generation set powering three centrifugal pumps and then you have the VorTeq, which is the gateway technology that allows you to cut pump numbers,” says Gay.

Gay adds that the life expectancy of the centrifugal pumps should be between 50,000 and 60,000 hours, compared to existing pumps, which could range from 6,000 to 8,000 hours.

Energy Recovery currently has its VorTeq deployed in a six-month exclusive field trial. Gay says after the field trials have been successfully completed, the company will be able to better determine when the technology could go commercial.

“We’re very bullish on the value creation that is represented by this technology,” says Gay. “We’re going to approach the field trials diligently and we’re going to make sure that it integrates seamlessly with your typical frack ecosystem.”

The California-based company’s first-generation tech will handle slickwater only, and its second-generation, which is currently in the process of being developed, will be frack chemistry agnostic: slickwater, gels and hybrids.

“To develop a solution that’s capable of withstanding the abrasion, viscosity and pressure cycles that you see at the wellhead is a challenge,” Gay says. “We’re developing a solution that would have a material impact on the cost per barrel to frack a well. We’re quite enthusiastic about the months and years ahead.”

Author: Emily Aasand
Staff Writer, The Bakken magazine


Statoil, Ferus Utilize CO2 Fracks
Through a recently awarded contract, Murray Reynolds and his team at Denver-based Ferus LP, an energized fluid provider for the oil and gas industry, will have the chance to prove why the number of U.S. unconventional wells that are completed with nitrogen or carbon dioxide (CO2) could, or should, be much higher than the current two to three percent.

Ferus has been contracted by Statoil, an international exploration and production company run by Norway, to use liquid CO2 to complete an unconventional well in the Bakken shale play. The well completion will take place in June and will help evaluate the potential production uplift and replacement option of water in multi-stage frack jobs.

Although there are many forms of CO2 or nitrogen-style completions happening in western Canada, the approach is usually the same for all wells, Reynolds says. In place of water, CO2 is mixed with proppant and the necessary chemicals and pumped downhole. Typically, the energized foam contains 70 to 80 percent gas with the remaining percentage consisting of proppant, chemicals and water.

On a water-based pressure pumping operation, the well site will have proppant tanks, water tanks, proppant blenders and high-horsepower pumps, but for Ferus’ operations, CO2 tanks are added to the lineup.

In Canada, the CO2 used by Ferus has been supplied from industrial producers near the wells. For the project in North Dakota, Ferus will source CO2 otherwise vented from a fertilizer plant in Saskatchewan and truck the gas in liquid form to the well site. For most wells, Reynolds says, roughly 2,500 to 4,500 liquid tons of CO2 would be needed. The Ferus team has completed a well using 6,500 liquid tons of CO2 preciously, a world record, according to Reynolds. By comparison, 1 liquid barrel of CO2 is equivalent to one liquid barrel of water.

Benefits of CO2 Fracks
“With this slowdown, people are going to question what they are doing and why they have been doing it,” says Reynolds. For Bakken operators, the adoption of slickwater-based fracture methodologies has greatly increased in the past two years. In some cases, slickwater volumes per well have increased from 1 million gallons to a range of 6 to 8 million gallons per well. Reynolds believes it is time to question those numbers given the studies and proven work completed on CO2-based fracks. “Are we getting the best bang for our buck or are we just spending more money on larger fracks?” he added.

Part of the intrigue of CO2-based fracks is related to the frack size reduction possibility. Based on studies from the Montney field in Alberta where Ferus performed CO2 fracks, energized foams provided a 100 percent initial production increase over slickwater jobs, Reynolds says. The cumulative recovery, roughly the first 12 months, also increases by 30 percent and the estimated ultimate recovery rates also increase by 30 percent. The production increases were also accomplished with a 25 percent well completion cost reduction.

According to Reynolds, the process allows completion engineers to reduce the size of the fracture job needed to reach previously expected levels of production. The overall frack job can be reduced by roughly 30 to 40 percent and require roughly 50 percent less proppant.

“Slickwater can’t carry proppant through the well bore as efficiently to the upper portions of the frack,” he says. “The foam jobs are more efficient at carrying proppant and keeping it in the upper part of the frack.”

The proppant carrying ability helps to increase production because a greater percentage of the fracture highways are kept open to allow hydrocarbon flow.

“With a big slickwater job, you are flooding the formation. You are displacing hydrocarbons from the near frack area and you are filling that porosity with water and altering the hydrocarbon saturation mix,” he says. “So the hydrocarbons are allowed to flow better and any liquids in the areas are being lifted to the surface much better.”

Another advantage of CO2-based approach is the reduction of water—slickwater or other—needed to complete the well and the amount of water that will be drawn back to the surface and require disposal during production. Roughly 25 percent of all water injected into a well will return during production and require disposal.

Although Reynolds is confident of the pending result of the project, Statoil has agreed to a single well first. Should the outcome be positive, Reynolds says future use of CO2 for well completion could utilize Ferus and General Electric’s ability to capture and recycle rich gas sourced from the Bakken. Gas could be piped or trucked to current or future well locations where it could be used to complete wells, Reynolds says.