Growing The Shale Brand

Global energy services giant is bringing a new focus to shale. We talk with Halliburton's team on its focus in shale, new technologies and reasons for excitement in the digital, flowback and sand distribution segments.
By Luke Geiver | September 05, 2017

Stephen Ingram does not manage the design or manufacturing of high-end luxury vehicles or popular basketball sneakers, but he does play an integral part in furthering the success of a global brand. As Vice President of Technology Solutions in Halliburton's North America Operations, Ingram has been a key figure in Halliburton’s work to expand and better understand the unconventional oil and gas industry. Like so many of the world’s leading brands, Ingram and his team have an incredible opportunity—and challenge—to shape the way the industry they serve evolves. North American Shale magazine went behind the scenes with Halliburton, Ingram and others to explain the trends and priorities that one of the biggest names in unconventional oil and gas development has invested in.

Trends In Shale
For the past 15 years, Ingram has been with Halliburton’s U.S. operations. During that time, he’s seen how individual basins have developed. While commodity prices and moods or pace of development have been in flux, Ingram says the one constant that has driven the shale energy industry forward is its desire to repeat a process over and again: design or find new technology, implement that tech into the field and repeat. The ever-present and engrained thought process of shale players to innovate has helped Ingram and his team claim several major industry firsts or accomplishments through new product deployments or unique field operation strategies. The industry’s thirst for the new has also placed a real-time understanding of every basin at a premium for Ingram and his team, who value basin-specific knowledge.

As each major basin has changed, Ingram says it is clear that one trend has remained constant from Pennsylvania to Texas: longer laterals are the goal. “Technology continues to develop,” he says. “Extending laterals helps drive higher and higher returns on capital employed for the oil or gas operator.”

Pushing the toe of the horizontal further away from the heel is feasible depending on the maturity of a basin in many cases. In the newer plays like the Delaware or SCOOP/STACK, Ingram believes there is more running room for extended laterals. Operators in mature basins are now more set on their development plans and have already established leaseholds, however. Extending laterals in established plays can also require an alteration of surface infrastructure.

In addition to the desire for longer laterals, operators are now designing and planning surface strategies through a lens of efficiency. If they see an option to increase efficiency or decrease field-costs, they will plan for it before purchasing and designing a system, Ingram says. Although some areas still feature individual wells on single well pads necessitated by HBP drilling, the majority of operators are looking at multi-well pads. “What we absolutely see in the future is higher and higher well counts per pad to take on the efficiencies and economies of scale,” Ingram says. On the high-end, well pads in the future will house 20 to 25 wells per pad.

Well pad operations, including pressure pumping, looks strong to service providers, he adds. “During the downturn, most service providers found themselves to be in an area of excess supply for available demand. We see demand outstripping supply now,” he says. Halliburton is now expanding the typical norms of its field operations to benefit its operator clients and better utilize its equipment. The company looks to work on multi-well pads and in some instances, run operations 24 hours per day. “That is driving returns that we expect in this marketplace.”

For pressure pumping applications, no basin is declining in its use of proppant per well, Ingram says, and the amount of fluid injected per well is also generally increasing across all basins. With the increase of sand and fluid volumes per well, Halliburton has had to deal with increased wear and tear on equipment, a challenge Ingram believes his team will overcome because they’ve already proven how to overcome industry challenges in the past.

During the last industry upcycle—roughly 2012 to 2014—there were large inflation costs incurred by service providers. Halliburton was not immune to those, Ingram says. One of the main negative economic issues faced by Halliburton was linked to sand. To move sand from a transload facility into a storage container that could then be trucked to a well site, a pneumatic blower had to push the sand into the container in roughly 20 minutes. In many cases, pneumatic trucks and delivery trucks were left waiting at the transload facility due to an efficient and time-consuming process that was hindered by the timing on incoming sand loads and the distance of well sites from the transload site. According to Ingram, trucking providers contracted to move sand would charge Halliburton demurrage costs for non-productive time. “It was a massive cost that the industry bore the burden of,” he says.

To limit the company’s exposure to demurrage charges, Halliburton teamed up with U.S. Silica—the nation’s largest provider of frack sand—and Sandbox on a containerized sand solution that can bypass the waiting and streamline the sand movement, storage and utilization. The new approach to sand logistics has saved Halliburton and the industry significantly, he says.

The story of Halliburton’s sand supply problem-solving abilities is a bridge Ingram uses to explain how the company is continually trying to innovate. Because the company is so infused into the day-to-day and fiscally sensitive operations of the industry, the company has the opportunity to gauge what the industry will benefit from—or need—next.

The increase in sand volumes ushered in a new regulatory requirement that Halliburton and others had to consider. “One of the new costs that has come to the industry in the past year has been around dust capture,” he says. The U.S. EPA has imposed a regulation requiring a fully engineered solution for capturing dust related to frack sand. Because the company was dealing with such high levels of sand around the country, it knew of the issue and has already designed a solution into its containerized sand solution. The EPA’s requirement for the solution to dust won’t actually be imposed for another four years when the grace period of the regulation expires.

Halliburton isn’t the only shale entity that sees the value in placing an extreme importance on knowing the trends and needed changes in the field. Despite a period in the industry when few dollars were being spent by operators to understand why wells were or are producing better than previous versions, Ingram says today there has been an emergence in investment towards diagnostics. “They [operators] want to know what has changed and why.”

Answers On Advancements
Neha Sahdev is a Halliburton expert working with the Production Enhancement group. Sahdev is excited for the fruit of his team’s labors on Integrated Sensor Diagnostics (ISD). The team has developed a suite of services that help operators understand well fracture placement, bypassed reserves and the optimal method for completing and optimizing field development. “What we are trying to do is to accelerate the learning curve that an operator might have in their basin,” Sahdev says. Acceleration involves the implementation of sensors—including fiber-optic material—that can be placed downhole. According to Ingram, Halliburton has invested heavily in developing, deploying and driving down the cost of field ISDs.

Although operators were installing random and one-off ISD systems that mainly consisted of fiber optics temporarily deployed by wireline units in a field, the trend now is that many are looking to install fiber optics permanently across wider areas. In the next three to five years, Ingram believes every well pad will have at least one well with permanent fiber optics. “There is an entire level of fracture design optimization that can occur because of that,” he says. In 2012, the price for permanent fiber optic material installed was roughly $1 million. Today, the price is closer to—and needs to be—$100,000, Ingram says.

Fiber optics can explain production in a lateral for every three feet. The fiber cable is installed on the outside of a casing string and stays for the life of the well giving 24/7 monitoring capabilities to the surface. “I think the industry, even with the volatile times, has come to understand that the drill bit way of optimizing is not the most efficient way,” Sahdev. In fact, Sahdev’s team is now working with multiple operators that are asking Halliburton to deploy every ISD tool they have in an effort to better understand early production parameters and how they will impact long-term well productivity depletion rates. Sahdev doesn’t like to deploy the entire toolbox at first, however, opting first to understand the parameters or fiscally critical optimization challenges the operator is looking to understand. Through a one-off, custom consulting process, his team will create a solution that helps clients find what they are looking for. In most cases, the Halliburton team asks the operator to rank which elements of optimization are most important. “Let’s say an operator is going with an infill development plan. It is important to understand what happens when a new well bore is placed on an existing pad,” he says.

In the past a number of operators have been able to utilize the ISD approach. The high reliability on deployment due to design improvements, high fidelity data and new analyses techniques paired with reductions in cost of deploying these systems, has also played a large part in the fiber optics uptick.

Daryl Tompkins, a reservoir evaluations technical advisor for Halliburton, is also heavily involved in helping operators better understand the long-term nature or possibilities of their unconventional wells. Tompkins has helped lead the integration of diagnostics into the well flow-back process. In 2014, the team began the integration process and is now helping clients in the Permian understand the plausible outcomes that will occur when various flowback strategies are deployed. “Everyone flows back their well, but not everybody utilizes the data collected on it,” he says. After following the well flowback strategies of operators and collecting what data he could, Tompkins learned that there was very little science applied to that part of the well’s life. “At the critical moment of the well’s life, operators were just turning it over to a third-party flowback company with little or no consideration for the well's performance,” he says. Many problems stem from such a practice, he adds. The metric for the success of a well was measured by how high the initial production period volume was. “When we started looking at a couple of years’ worth of data on wells achieving high IPs, we could see operators trying to achieve high IP's had steep decline rates,” Tompkins says.

The issue with opening wells on aggressive choke schedules early on to achieve a high IP was that the high initial flow rates caused an excessive amount of sand to be washed out of the fractures. The loss of sand reduces near wellbore conductivity and limits the well's long-term production capabilities. “You may get a high IP but you will lose production out of that well,” Tompkins says. 

By utilizing a collaborative workflow between our reservoir engineering team and the well testing field personnel, Tompkins was able to assess data during flowback to determine how certain flowback and choke strategies were impacting a well’s long-term production. The data can also be used to inform future completion decisions on multi-well pads.

“When I go to meet with customers, they will say that they've heard other operators are ripping wells wide open and getting great results. Rumors spread throughout the industry and people only hear half the story. What operators need to do,” Tompkins says, “is gather the right data to evaluate their own wells.”

Ingram knows that operators and service companies have always altered which entity leads and which one follows. The ability and responsibility to both listen or lead the industry puts pressure on Halliburton, he also says, but despite the challenges of a commodity-linked industry, the company has always responded. “We want to drive an environment where at any price of oil or gas, we have a robust industry,” he says. “In the unconventional industry, there is no shortage of amazing people or companies that are constantly coming up with new technologies, innovations or improvements.”

In addition to pushing the shale space towards better diagnostics, Halliburton has also continued its investment in shale by remaining active with TAP—its technology acquisition process. “Even though we are unique in having such a large footprint, we are not arrogant to think that all great technology comes from Halliburton labs,” Ingram says. For the unconventional space—which for Halliburton has become a major point of focus whether it is in North Dakota or New Mexico—the future from the global shale brand’s perspective is clear, according to Ingram. “We are excited about what we are doing.”

Author: Luke Geiver
Editor, North American Shale magazine