The Next Level of Fracture Optimization

A new breed of data-centric, geomechanically-focused companies is helping completion engineers improve fracture treatments and overall production.
By Luke Geiver | May 07, 2018

Ahmed Quenes and Peter O’Conor believe their shale management solution is the future of the unconventional oil and gas industry. Their Texas-based company, FracGeo, is part of a small cluster of companies created in the past five years to provide geological modeling and geomechanical simulations to decision makers, asset managers, completion engineers and geoscientists. Using surface drilling data, algorithms and simulation software, FracGeo and others have ushered in a new era for shale development that includes a vastly improved understanding of subsurface properties affecting reservoir quality, hydraulic fracturing and well spacing. Using new, enhanced or cleaned-up data sources, this new breed of geologically obsessed company has impacted the fracturing and completion process in a way that they all believe—and most have proven—can and will improve asset ROR and well performance. 

Welcome To The Sweetspot
FracGeo was founded three years ago. The team has always been focused on bringing a new generation of collaborative software to reservoir analysis. “The collaboration is between the geoscience people and the engineers,” says O’Conor, the vice president of sales and marketing. With multiple beta sites currently active and already favored by clients, O’Conor says his team is preparing for exciting times ahead. Previously, clients could provide data to the FracGeo team and they would run and compute the data for fracture placement, reservoir depletion or complex downhole interactions (among a multitude of others) but now they are rolling out a full software line for purchase that will let clients use their system how and when they want. The package covers geophysics, geological modeling and includes several geomechanical simulator options. The package is the first, they believe, that provides a 3G option: the integration of geophysics, geology and geomechanics. “We can model the stresses and strains of completion designs,” O’Conor says.

FracGeo is trying to address the problem with assumptions in well modeling. “We see a lot of variability with wells that are right next to each other,” O’Conor says. “Investors are asking what is going on.” Because of the variability, operators are now taking a more surgical approach to developing wells, he says. To do that, the key is truly understanding the natural fractures along the well bore and how they will interact with pressure, fluids and proppants.

Utilizing data sources compiled during the drilling process, FracGeo has created a suite of software options that can model and predict 11 different segments, ranging from stimulation placements to production predictors. With its fracpredictor option, the company can predict how spacing and timing of frac placements will create frack hits. “We stimulate how the pressure we are going to pump will interact with the elasticity of the rock,” O’Conor says. The end result allows clients to predict where the sweetspot should be before placing costly fracture treatments in real-time. To date, the company has worked for clients in nearly every major North American shale play and it is also expanding to non-U.S. fields.

Rock Experts Obsessed With Data
Prior to becoming the Chief Technology Officer for Drill2Frac, Kevin Wutherich worked for Schlumberger and a private operator on completions. Today, he says, the majority of his time is spent converting drilling data into usable data that can uncover the mechanical properties of rocks. “We look at mechanical specific energy from drilling data already available on virtually every well,” he says. Using that data, they have also come up with a way to redesign and rethink completions. The team can find better ways to place perf clusters or divide a well into different stages based on the rock property data.

“Our approach is based on the idea that the rock that drills the easiest is likely going to be a softer rock,” Wutherich says. To find out the properties of the rocks, the team needs to clean and filter out drilling related variables that skew the true properties of the rock downhole. “That is really where our core expertise is, how to clean that data up and help our clients understand if what they are seeing is a response caused by drilling or reservoir effect.”

To date, the company has taken a hard look at perf cluster placement. While other companies that perform engineered completions opt to make only slight changes, Wutherich and his team push for a different approach. “We place every one of the clusters into complimentary rock,” he says. Many approaches are based on a geometric design. An engineer planning a 300-foot stage length will place the clusters equal along the segment. Wutherich makes sure the clusters and the stages are placed in the appropriate lithologies. “We like to keep all of our clusters in similar rock,” he says. To ensure that happens, the team will advocate for resetting stage boundaries and resetting cluster placements. “The completions will still take place in roughly the same amount of time, but now they aren’t using a random approach. Now,” he says, “they are placing stages and perfs based on what reservoirs are telling us.”

To create the appropriate simulation of a well completion, Drill2Frac uses surface drilling data provided by the client. In roughly two days after drilling ends, the team can turnaround an entire completion plan. Operators in the Permian, Eagle Ford and Mid-Continent have used the service. On a six-month, normalized stage length average, clients that have used the Drill2Frac system have increased production by roughly 22 percent. A product designed to help predict the proper placement and timing of diverters has been the most sought after and popular among Drill2Frac’s offerings. The system can help reduce the number of stages needed in a well without impacting production, Wutherich says. In addition to the reduced costs associated with the fracture treatment that a Drill2Frac simulation can provide, he also says operators are always looking to speed up the process so they can move on to the next well and the profits that come with each new well.

Amongst all its offerings, Wutherich is most proud of his team’s obsession with ensuring the quality of it’s data. The team has even developed a program to ensure that the wireline depth—the depth reached from a system that is used to collect the initial depth data—correlates to the actual drilling depth achieved. When clients perforate, he says, they do it on wireline depth and not on drilling depth. Using the best data from the real-life scenario from which it was acquired is crucial he says, and in the data business, nothing is too small. 

Following The Fluid
The new breed of fracture stimulation data and analysis companies that has cropped up in the past five years isn’t limited to simulations and predictive analysis. John Ughetta and his team at Texas-based Deep Imaging are in the monitoring and imaging business. Using surface-based electromagnetic monitoring sensors, the team can show operators where frack fluids actually went after the treatment is finished, and, when or where issues or hazards downhole might occur.

After laying out a tight grid of volt meters above the area of interest, Ughetta’s team transmits a controlled source into the earth with two injection points. Then they record the volts per meter that come back to the surface grid. “We are a direct measurement of a change at the reservoir that is caused from the stimulation,” he says. Using the voltage readings that bounce off of the altered rock below, the team has created a software that depicts where fluid went and how fractures turned out. Because the data can be collected and reassembled quickly, the Deep Imaging team can work in near-real-time conditions with engineers onsite while a fracture treatment is taking place. Because the data compilations can’t be interpreted in different ways, engineers are able to trust what they see and make changes to treatments to avoid situations like screen-outs.

Already working in the Permian, Eagle Ford and the SCOOP/STACK, the company just tripled its capacity and doubled its personnel to meet the demands of clients. According to Ughetta, operators and investors want to know how their fracture treatments performed. To perform the readings, the team subcontracts out the layout of the sensors, which takes roughly five days. As the frack stages move down the lateral, they move the sensors on the surface. On a microseismic job, nearly 1,000 receivers would be placed on the surface, but the unique sensors used by Deep Imaging reduce the number to roughly 100. Per fracture stage, the system costs roughly $12,000, and includes a clear depiction of where fluids and proppant went after a treatment. 

In addition to fluid placement and fracture reach, the team is also gaining interest from clients working on enhanced oil recovery projects, recompletions or those with environmental concerns. This year the team is working to improve operational efficiencies, fine-tune the batteries used during the process and expand its field-required infrastructure. Like FracGeo and Drill2Frac, Deep Imaging is gearing up for a greater demand, Ughetta says, because the data is there, it keeps coming and the answers it provides for shale oil and gas development are near limitless.

Author: Luke Geiver
Editor, North American Shale magazine