New Bakken Oilfield Tech

Offerings in the play today, or slated for arrival soon, show low oil prices aren't the only reason new technology continues to enter the Bakken.
By Luke Geiver | January 18, 2016

Any perceived, or real, activity slowdown in the Bakken hasn’t affected the influx of new oilfield technology. New offerings are entering the Bakken for a myriad of reasons, including: in-field operational gains, regulatory requirements, cost savings or at the most basic level, just for the sake of doing things better. To underscore the continued arrival of technology into the Bakken or the greater unconventional oil and gas industry, our team has detailed a handful of new tech offerings that are impacting the Bakken today or could soon be operating in the play.

Technology Coming Soon
GroundMetrics, a full-service survey and monitoring company spun out of the U.S. Department of Defense, may not be in the Bakken yet, but the company’s proven approach to tracking hydraulic fracture fluids or finding bypassed pay in mature fields should have exploration and production teams interested. The California-based firm has already been contracted to perform a refracture survey of a mature oilfield in the Barnett Shale.

The GroundMetric’s team has developed a system to create a multi-mile resistivity map that shows more data on fluid properties, distribution and movement up to 11,000 feet below surface.

The key to the system, according to Mark Wilkinson, vice president of unconventionals and a geophysicist for the company, is the capacitive sensor used to obtain the data. As long as the team can put the sensor in contact with the ground, it can be deployed on sand, frozen ground, wet ground or rocky ground. Typical electrical sensors on the surface can only penetrate to 1,000 meters, Wilkinson says. Through the GroundMetrics approach, a well bore casing is used as an antenna to send a signal from the sensor further down into the earth and capture data at the depth of a typical fracture event. The sensors, originally designed to find tunnels in the ground for the DOD, can actually detect changes in the earth while materials are being injected, Wilkinson says. No other method, including seismic, can track where fluid is going directly.

Due to the system’s ability to track fluid, GroundMetrics has also used the system for waterflood and CO2 injection projects. Before the team partakes in a project, a field team performs a simple modeling of the survey area at no cost to the client. Then, the team creates a 3D model of how the survey project is expected to go.

A Wyoming frack job helps to illustrate the predictive power of the sensors, Wilkinson says. Using the GroundMetrics system, the team was monitoring seven stages of a frack job. The fluid used on the job included fracture tracers capable of showing where the fluid was ending up. On one of the stages, the team gained data that suggested the frack fluids broke into a preexisting fracture. “We predicted to the client that the fluid had traversed across two laterals to the west,” he said. Although the team showed the data to the client, they weren’t interested. But, the client became very interested in the data and predictive power of the system after they detected the tracer chemicals two wells over from the original survey well.

“Though commodity prices are down, clients are seeing the value in what we bring to the table. We are busy,” Wilkinson says. “We are backlogged into the beginning of the year.”

New Regulations Bring New Approaches
An April 2015 North Dakota Industrial Commission rule requiring the total vapor pressure of Bakken crude to be verified before transport set a Bismarck technology developer in motion. The rule, intended to ensure the volatility of Bakken crude, mimicked that of other high-volume liquid shipments like refined gasoline, requires all North Dakota producers to utilize a verification technology. The majority have relied on heater treaters installed on the well site to test the Reid vapor pressure numbers of the crude. But, heater treater units can suffer from the climate in the Bakken, experiencing operational difficulties in extreme cold temperatures or high winds.

In mid-December, the NDIC approved a request by Hellervick to test a prototype capable of exceeding the operational capabilities of the commonly used heater treater. The company has also set-up a pilot test with an undisclosed operator at an undisclosed location.

“The main difference between current heater treaters and the Hellervik oil conditioning unit is that the Hellervik unit is able to continuously measure the vapor pressure of the crude oil in the vessel,” says Lowell Hellervik, CEO and founder. “It is then able to control the temperature and pressure within the vessel dynamically to achieve the pre-selected vapor pressure that the well operator desires.”

The technology relies on temperature distribution through oil agitation and nozzle configuration. An onboard computer can adjust those control parameters and adjust accordingly for external factors such as weather.

Expected Segments For Upgrades
As the unconventional oil and gas industry evolves, frack sand and proppant suppliers are not content to sell basic products used in the past, no matter the price of oil. Many continue to tweak the size, strength, source and overall effectiveness of their offering. Changing frack fluids also creates new opportunities to bring new offerings to the market. Fairmount-Santrol, a Texas-based proppant manufacturer, exemplifies the constant quest of proppant suppliers and developers to offer a new and exciting product.

In the Bakken and Three Forks formation last year, Santrol completed a six-well field trial of its suspended proppant product for Enerplus Corp. When compared to offset wells, the six wells hydraulically fractured with the suspended proppant recorded a production increase of 39 percent. The proppant is made with a hydrogel polymer wrapped around a proppant piece. The design, once added to water at temperatures starting at 35 degrees Fahrenheit or above, swells and suspends itself in the water. The Propel system allows for faster fracks and less water, according to Santrol. Each well used the same volume of proppant per lateral foot. Each well was a horizontal well that reached roughly 10,000 feet. The pump rate for the suspend product, Propel SSP, wells was 60 barrels per minute compared to the 35 bpm for the crosslinked, white sand wells. To frack the Propel infused wells, it took roughly 75 hours. The offset wells required nearly 87 hours to complete. Enerplus saved nearly $1.00 per barrel of water and the system paid for itself in roughly four months at $45 West Texas Intermediate oil prices.

Transformative Bakken Technology
Joel Gay, president and CEO of Energy Recovery Inc., is happy that the story of the VorTeq pump follows many narratives. The pump’s unique design can save pressure pumping firms maintenance and per-barrel pumping costs. A VorTeq-infused pump set-up is also more efficient than most traditional pressure pumping layouts. And, the system not only helps during a time of low oil prices, it also holds promise as the basis for the fracture infrastructure blueprint of the future.

Last year, Schlumberger agreed to a license agreement for the VorTeq pump. Liberty Resources has already used and tested the system for more than a year. Through a clause in the Schlumberger agreement, the global energy services firm and Liberty will be able to continue using or add the VorTeq pump to Bakken frack sites.

The system, built of tungsten carbide, can reduce the number of plunger pumps needed on the frack job site from 20 to 3 centrifugal pumps. The pumps can also last roughly 60,000 hours before maintenance is required. Pumps used today typically last 6,000 to 8,000 hours. “We isolate the pumps from the proppant,” Gay says. “Pumps break down due to the erosive nature of the frack proppant in the pumps.”

From a company standpoint, Gay believes the success of the VorTeq shows how his team has completed a case study on how small and nimble firms can entreanch itself in an established industry. The success of ERI can be duplicated, he says, and it will be seen in the future. Low oil prices have essentially forced the industry to adopt and streamline practices of maintaining existing infrastructure, he says. “I see a renaissance of efficiency. We didn’t develop the VorTeq because we saw an opportunity in a downturn,” Gay says. “We developed it because we saw values across all elements of the cycle.” On the topic of other entities following ERI’s lead into the greater oil industry during the near-term, Gay is also positive. “I think you will see a lot of interesting technologies and innovations that will lower the operating expenses for the entire value chain."

Author: Luke Geiver
Editor, The Bakken magazine