Advances In Fracking – Low-Tech, High-Tech, and Climate-Tech

Originally published on on February 22, 2022

A spread of oil and gas innovations continues to make fracking more efficient and even spills over to a green energy application.   

The Hydraulic Fracturing Technology Conference (HFTC) was held in The Woodlands, Texas, on February 1-3, 2022. The pandemic hiatus appears to be over at last, so long as no radical new variants pop up.

The hiatus hasn’t stopped innovation, which has always been a key ingredient of the oil and gas industry. Here are a few recent highlights, some of which came out of HFTC.

Low-tech advances.

An increase in the number of wells to be completed in 2022 plus longer horizontal well sections portends a jump in frac sand. But current sand mines, more often in-basin these days, have suffered from reduced prices and maintenance in the past few years, and may not be able to fill the need.

Pumps are in short supply. Operators are hanging onto pumps that need repair or upgrading because rental places are limited in their supply.

Some operators in the Permian are drilling longer horizontal wells. The data show a cost reduction of 15-20% for drilling and well completions compared to recent years, partly because wells can be drilled faster. One company drilled a 2-mile horizontal in just 10 days.

Faster drilling is shown by this comparison: at the height of Permian drilling in 2014, 300 rigs drilled less than 20 million lateral feet in a year. Last year, 2021, less than 300 rigs drilled 46 million feet – a remarkable result.

Part of the reason is an increasing use of the simul-frac design, where two adjacent wells are perforated and fracked in concert – 70% faster completion than the traditional zipper-frac design.

Oil production per foot increases with horizontal length from 1-mile to 2-miles. While most wells in the Permian are now at least 2-miles long, some operators are pushing the limits. For one operator, almost 20% of wells are 3-miles long, and they are happy with results.

But some report mixed results for productivity per foot. While some longer wells stayed the same, some wells fell by 10-20% between lengths of 2-mile and 3-miles. A definitive result is not available yet.

A sidebar to this is the enormous amount of water and sand used to frac a 3-mile horizontal well. If numbers obtained from a typical 2-mile well in 2018 are extrapolated to a 3-mile well, we find total water volumes rise from 40 feet to 60 feet over the grassed area of a football stadium – and this raises questions about the source of the frac water.  A similar revelation appears for total sand volumes which rise from 92 railcar containers to 138 containers. And this is just for one well

High-tech advances.  

At the wellhead, there is a stronger focus on collecting more data and diagnosing the data to improve fracking of horizontal wells. 

Near-field connectivity.

Seismos has developed an innovative diagnostic that can characterize how good is the connection between wellbore and reservoir, which is key to flow of oil into a horizontal well.

An acoustic pulse is used to measure flow resistance in the near-wellbore region of a well that has been fracked. The metric is called NFCI, for near-field connectivity index, and it can be measured all along a horizontal well. It has been shown that NFCI correlates with oil production in each frac stage.

A uniform NFCI (top panel) is an ideal scenario for higher production rates compared to a less consistent NFCI spread (bottom panel). Source: Seismos.

Studies have shown that NFCI depends on:

  • The geology of the reservoir — brittle rocks give larger NFCI numbers than ductile rocks.
  • Proximity of other wells that can induce stresses that cause NFCI numbers to vary along a horizontal well.
  • Adding a diverter or using a limited entry frac design which can boost NFCI values by 30%.

Sealed wellbore pressure monitoring.  

Another high-tech example is SWPM, standing for Sealed Wellbore Pressure Monitoring. A horizontal monitor well, filled with liquid under pressure, stands off from another horizontal well that is to be fracked all along its length. Pressure gauges in the monitor well record tiny pressure changes during frac operations.

The process was developed by Devon Energy and Well Data Labs. Since 2020, over 10,000 fracking stages – typically 40 along a 2-mile lateral – have been analyzed.

When fractures spread out from a given frac stage and reach the monitor well, a pressure blip is recorded. The first blip is checked against the volume of frac fluid pumped, called VFR.  The VFR can be used as a proxy for cluster frac efficiency and even used to figure out fracture geometry. 

Another goal can be to understand if reservoir depletion, due to a pre-existing parent well, can affect the growth of fractures. A new fracture tends to head toward a depleted portion of a reservoir.

Near-well strain from fiber optic cable.   

A fiber optic cable can be strung out along a horizontal well and attached to the outside of the well casing. The optical cable is protected by a metal sheath. A laser beam is sent down the cable and picks up reflections caused by minute crimping or expansion (i. e. strain) of the cable when a fracture at the well has its geometry altered by a change in well pressure during oil production.

Precise times are recorded when a laser reflection occurs and this can be used to calculate which location along the cable was crimped — well segments as small as 8 inches can be identified.

The laser signals are related to the geometry and productivity of the fracture at a particular perforation cluster. A large strain change would suggest a large change in the width of the fracture connected to that perforation. But no strain change would indicate no fracture at that perforation, or a fracture with very low conductivity.

These are early days, and the real value of this new technology has yet to be determined.

Climate-tech advances.  

These are innovations related to climate change and emissions of greenhouse gases (GHG) that are contributing to global warming.


In the oilfield, one way to reduce GHG emissions is by oil and gas companies greening their own operations. For example, by using, instead of diesel, natural gas or wind or solar electricity to pump fracking operations.  

In an opening plenary session at HFTC, Michael Segura, senior vice president, said Halliburton was one of the major players in electric-powered frac fleets or e-frac technology. In fact, e-fracs were initiated by Halliburton in 2016 and commercialized in 2019.

Segura said that benefits lay in fuel savings as well as reductions in GHG of up to 50%. He claimed this was a “pretty remarkable impact on emissions profile of our industry.”

He also said the company has made “a large commitment to the development of equipment and enabling technology, such as grid-powered fracturing.” This apparently refers to using electricity from the grid, rather than from gas turbines powered by wellhead gas or CNG or LNG sources.

The most common e-fleets use wellhead gas to run gas turbines to generate electricity that power the fleet, said one observer. This reduces the GHG footprint by two-thirds and means more wells can be completed under a given GHG emission license.

E-fracs are only about 10% of the market now, but worldwide demand to lower GHG is expected to grow the use of e-fracs, where typically 50% GHG reductions can be achieved.


Geothermal energy is green compared with fossil fuels, because it extracts from underground formations energy in the form of heat that can be converted to electricity.

Hot Dry Rock was the name of the method to tap geothermal energy by fracking granite in the mountains close to Los Alamos National Laboratory (LANL) in New Mexico. This was in the 1970s.

The concept, invented at LANL, was quite simple: drill a slant well into the granite and frac the well. Drill a second well some distance away that would connect to the fracture(s). Then pump water down the first well, through the fracture(s) where it would pick up heat, then up the second well where the hot water could drive a steam turbine to produce electricity.

The concept was a simple one, but the fracture results were anything but simple – a network of tiny fractures that complicated and reduced the flow of water to the second well. Efficiencies were not great, and the process was expensive.

The concept has been tried in many other places around the world, but remains on the cusp of commercial affordability.

John McLennon, of University of Utah, spoke at the plenary session of HFTC about a new plan. He is part of a team that wants to expand the concept by drilling horizontal wells instead of near-vertical, and deploying the latest fracking technology from the oilfield. The project is called Enhanced Geothermal Systems (EGS) and is funded by the US Department of Energy (DOE).

The project drilled the first of two 11,000-ft wells in March 2021. The approach is to frac the first well and map the fractures to design a stimulation plan for the second well 300 feet from the first well that will provide the connectivity needed between the two wells. If it works they plan to adapt operations to two wells that lie 600 feet apart.

It is a little ironic that well technology developed for the shale oil and gas revolution may be grafted into a clean energy source to help replace fossil fuel energies.

Another version of this, with funds from DOE to the University of Oklahoma, is to produce geothermal energy from four old oil wells, and to use it to heat schools close by.

Despite the enthusiasm in projects like these, Bill Gates argues that geothermal will contribute only modestly to the world’s power consumption:

Some 40 percent of all wells dug for geothermal turn out to be duds. And geothermal is available only in certain places around the world; the best spots tend to be areas with above-average volcanic activity. 


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