A solid understanding of near-wellbore conditions is a key component for successful completions.

Operators could use trial and error to test completions effectiveness, but without understanding near-wellbore conditions, the approach is costly and time-consuming. 

Obtaining wellbore conditions using pre-existing data and simulating different completion designs is a better, non-invasive option, according to Drill2Frac.

The company developed its FlowFX near-wellbore fluid distribution solution over a period of years.

Kevin Wutherich, Drill2Frac’s CTO, started his career as a completions engineer and understands the importance of getting flows right.

“I realized early on that the near wellbore is where everything happens,” he said. “If you can get what happens in the near wellbore right, then you can have a good effect on the rest of the job. You can’t control what happens after the fluid leaves the wellbore, but you can change what’s happening in the near wellbore.”

Rock properties in the near wellbore can change foot-by-foot, he noted, meaning clusters can be placed in different types of rocks.

To adapt to the near wellbore, it is important to understand what the initial conditions are, he said.

“If you can get what happens in the near wellbore right, then you can have a good effect on the rest of the job.” — Kevin Wutherich, Drill2Frac

Kevin Wutherich, Drill2Frac's CTO
Kevin Wutherich, Drill2Frac's CTO. (Source: Drill2Frac)

“There have been models built to understand fracture efficiency, but they haven’t been able to effectively take into account near-wellbore rock properties,” Wutherich said.

Between 2016 and 2019, Drill2Frac president Dharmesh Mehta said the company focused on improving its process for characterizing rock properties in the near wellbore leveraging drilling data and other information operators had been obtained, such as via downhole cameras or fiber optics. 

The entire focus is to use data the customer already has instead of requiring the collection of new data, he said.

But data alone is not enough. “That left the last frontier, understanding things like erosion and stress-shadow models,”  Mehta said.

Integrating those models with customer data was the next step.

With digital solutions for fluid distribution in place and the ability to detect depletion using data and processes, Drill2Frac’s data and analytics help operators fine-tune completion designs by modeling parameters such as the number of perf clusters and length of stages, he said.

Drill2Frac Fluid Distribution Analysis Demonstration
The FlowFX simulation on the left shows how insufficient perforation friction allows intra-stage stress shadowing to dominate. (Source: Drill2Frac)

The result is a cloud-based solution designed to be non-invasive with the goal of helping operators achieve more consistent and productive wells.

Playing what-if

FlowFX allows completion engineers to visualize frac plans and quickly simulate the effects of different designs, Mehta said. 

In a perfect frac, pumping 1,000 lb of proppant into eight clusters in a stage would distribute equally. “The reality is that is not the case. You never get equal distribution.” 

As Mehta puts it, FlowFX provides a visualization of how the proppant is going into each cluster for each stage.

From there, it is possible to play what-if and tweak elements of the completion, he said. All the physics and modeling happens behind the scenes.

FlowFX Near-Wellbore Fluid Distribution Model Comparison
FlowFX Near-Wellbore Fluid Distribution Model Comparison
FlowFX models how fluid will be distributed among perforation clusters for differing completion designs. (Source: Drill2Frac)

Customers can “turn the knobs” on the completion design. They can adjust variables such as number of stages, stage length, clusters per stage, shots per cluster, perf diameter, orientation of perfs, pump rates and the volume of proppants to experiment on what might affect a completion’s effectiveness.

Mehta said modeling allows customers to understand the effects of the near-wellbore conditions.

“[It makes] that process simpler, easier and leverag[es] the data you already have,” he said.

Dharmesh Mehta, Drill2Frac president
Dharmesh Mehta, Drill2Frac president. (Source: Drill2Frac)

“Our entire focus is to use data the customer already has.” —Dharmesh Mehta, Drill2Frac

Wutherich said modeling different scenarios can show crews what they can expect during fracturing with any modification — easily more cost-effective than trial and error. 

“It’s a model. It’s not going to be perfect, but it’s based on solid physics and data.” So, it makes it possible to predict how changes in completion designs will affect fluid distribution along the wellbore, he said. 

Instead of running operational trials on 50 completion designs, FlowFX can shortlist those designs to the five most likely to succeed, he said. 

The model cannot take every variable into account, according to Wutherich. Poor cement, for example, presents difficulties because the cement is not fully controlling where the fluid will go.

Wutherich said Gordy Oil, one of its customers, made completion design decisions based on FlowFX for wells in the Delaware Basin. The ability to model different designs led to an optimized design that resulted in a significantly improved completion and production increase, he said.

Drill2Frac announced the availability of FlowFX during the 2021 Unconventional Resources Technology Conference (URTeC 2021) and has been using it internally for customers. The FlowFX 2023 update, which will be launched in first-quarter 2023, incorporates feedback from customers.

The biggest change: the modeling solution will be cloud-based, allowing Drill2Frac customers to work directly with the digital solution and run their own simulations.