ENERGIZED FRACTURES

48 JPT • JUNE 2014

I

n the years since George Mitchell’s 

engineers first used the cocktail of 

water, sand, and a small batch of chemicals called slickwater to crack open the 

Barnett Shale in north Texas, trillions of 

gallons of the low-viscosity mixture have 

been pumped into shale formations all 

over the United States and Canada. While 

the resulting shale revolution owes much 

of its success to the use of slickwater, it 

has come at a high cost in terms of dollars 

and increased public scrutiny. 

In response, a growing chorus of 

suppliers, researchers, and service companies are on a mission to get operators 

working in North American shale plays to 

re-examine their almost exclusive use of 

slickwater and consider displacing large 

volumes of it with carbon dioxide (CO2) 

and nitrogen (N2). 

Those in the industry pushing the 

change say the “energized” fracturing 

of horizontal wells is a proven technology that stands to improve the economics of completions and the productivity of horizontal oil and gas wells. They 

point to a growing body of evidence 

from both Canada and the US that shows 

energized fractures greatly reduce the 

amount of water and proppant required 

to stimulate shale formations, and have 

the potential to increase recovery rates 

substantially. Internationally, the technology could help speed up lagging 

unconventional shale development by 

alleviating water scarcity issues. PropoShale Revolution Revisits the 

Energized Fracture

Trent Jacobs, JPT Technology Writer

As an alternative to slickwater, an energized fluid containing carbon dioxide is pumped into a horizontal well during 

fracturing operations in the Mancos shale play amid the rugged terrain of Grand County, Utah. Photo courtesy of Ferus. 

JPT_June 2014_Energized Fractures.indd 48 5/15/14 2
JPT • JUNE 2014 4

nents of the technology offer a variety 

of reasons why it has not been adopted on a wider scale including perceived 

cost issues, logistical limitations, supply 

constraints and, some say, the factorymode mind-set of many operators that 

leaves little time to test and evaluate new 

completion methods. 

Fracturing solutions containing 

these inert gases are called energized fluids or foams and have been used to fracture vertical wells, tight gas, and coalbed methane formations for more than 

40 years. In Canada, energized fracturing technology is estimated to be used in 

more than 40% of horizontal shale well 

completions. Comparison studies carried 

out there show that energized completions cost less and resulted in better performing wells than their slickwater counterparts. Despite the positive results seen 

in Canada, energized fracture treatments 

represented only 2% of completions in 

the US last year. “There is no question 

that there is not as much application of 

this technology as there could be,” said 

Mukul Sharma, a professor and chair in 

the petroleum engineering department 

at the University of Texas at Austin (UT), 

who has been researching the subject of 

energized fractures for nearly a decade. 

“We have seen a clear benefit in many 

of the Canadian shales using these energized fluids,” he said. However, “In the 

US, it appears to be a chicken and egg 

issue with suppliers willing to supply 

the gas, but needing a constant market 

demand to justify building gas plants.”

Baker Hughes is one of the few companies with a full line of energized technologies that can stimulate wells using 

just a fraction of the proppant required 

in slickwater systems. One of the oilfield 

service company’s clients recently carried out an energized fracture treatment 

specifically for its ability to place proppant in some of the hardest sections of 

the well to effectively stimulate. Baker 

Hughes is also introducing the technology to other operators in search of alternatives to water- and oil-based solutions. 

To help facilitate the creation of a 

sustainable market, three of the largest industrial gas suppliers in the world 

are researching and working with shale 

operators to identify the best applications for energized fractures in the US. 

One of those companies, Linde, has been 

working with its oilfield clients for the 

past 18 months on improving the logistics and selection of energized fluids 

and foams to their wellsites. So far, the 

company says its clients are netting the 

expected benefits. “Here in the US, the 

operators who have focused on energized 

components for their programs are saying they are seeing a cost savings,” said 

Robin Watts, oil and gas technology manager at Linde. “And they have seen better 

productivity results in the 10% range,” 

according to one of its operator clients. 

A Forgotten Technology

Since the 1970s, energized fracture 

treatments have been primarily used as 

a way to fracture underpressured dry gas 

formations. The turning point came in 

1994 when Mitchell Energy abandoned 

energized foam fractures after experiencing poor results in the Barnett Shale, 

a brittle and overpressurized formation 

that demands high volumes of fracturing fluids, and began using slickwater. 

Even as slickwater use propagated and 

shale gas development took off, the use 

of energized fluids was still considered 

common. But the success in the Barnett 

and other plays eventually led to a gas 

glut, and most drilling rigs moved to oilrich shale plays, where energized solutions had a much shorter track record of 

success. This transition away from energized solutions coincided with a younger generation of engineers joining the 

ranks, and since the breakthrough technology that started it all was slickwater, 

many in the business concluded that the 

shortest path to success, and the least 

risky, was to replicate the processes first 

used by Mitchell Energy. “As the revolution hit and everybody was looking at 

water, you had a 30-and-under crowd 

that never knew anything but water 

existed,” said Watts. “Now, those same 

companies are taking a look back and 

applying some of the lessons learned 

using CO2 and N2 from decades ago.” 

The main difference between energized fluids and energized foams is gas 

content. Energized fluids contain less 

than 52% of either CO2 or N2, while energized foams have gas volumes greater 

than 52%. In general, most energized 

foams consist of 65% to 75% gas and 

high-quality foams contain 95% to 99% 

gas. Linde delivers both gases to a drillsite by tanker truck in pressurized liquid form. Using conventional fracturing 

In both Canada and the US, all industrial carbon dioxide is collected from 

man-made sources, such as this fertilizer plant in Saskatchewan, Alberta where 

transport trucks load up with the gas before heading out to a wellsite. Photo 

courtesy of Ferus. 

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ENERGIZED FRACTURES

50 JPT • JUNE 2014

equipment, liquid CO2 is pumped downhole by a service company where it has 

roughly the same density as water and 

then as it heats up, it transforms into a 

gas. For N2, some specialized equipment 

is required. Trucks using a triplex pumping unit pump the liquid N2 from storage, 

warm it up by using a vaporizer, and then 

pump it downhole in the gaseous state. 

In most cases, the N2 must be warmed up 

from its liquid state, because it is so cold 

it could damage conventional casing and 

other equipment. 

While the potential applications for 

energized fracture treatments appear 

to be widespread, reservoir attributes 

must be considered before selecting 

CO2 and N2. Foam fracturing fluids have 

most commonly been used for underpressurized wells where the reservoir 

pressure is too low to drive a column of 

water out of the well. For those reservoirs, choosing a foam or energized fluid 

is an easy decision, because otherwise 

the well is more difficult to clean up prior 

to the startup of production. 

In wells that have asphaltenes and 

paraffin issues, energized fluids and 

foams with CO2 may not be the best solution because of reactions that can occur 

and damage the formation. In dry gas 

wells, these problems do not apply and 

the use of energized fluids and foams

have been more accepted. Because of the 

relatively small number of high-pressure 

pumps designed for N2, the gas has seen 

more use in shallower wells. In deeper 

formations, such as the Eagle Ford Shale, 

N2 requires pumping pressures as high as 

15,000 psi.

Water Issues a Driver 

Many of the boomtowns and surrounding areas that support US shale plays are 

under threat of drought, so water scarcity has become an issue for the unconventional business. A report published this 

year by a nonprofit investor group found 

that more than half of the counties in 

the US where horizontal wells are being 

drilled and completed with hydraulic 

fracturing are facing drought conditions. 

To reduce water consumption in these 

areas, some companies have invested 

millions of dollars in water treatment 

facilities to recycle the water after flowback and are even tapping into briny 

and brackish wells instead of freshwater sources. Since only 10% to 20% of 

fracturing fluids flow back to the surface 

in most cases, recycling can only displace a small portion of the water used in 

subsequent completions. 

If it is not recycled, the water is 

pumped into injection or disposal wells. 

This practice has become a topic of public concern after reports of earthquakes 

began about 4 years ago in the central US, where disposal wells are heavily used. Research done by the US Geological Survey and universities suggests 

that the increased injection of wastewater from oil and gas operations near 

fault zones may be inducing “swarms” of 

earthquakes, some large enough to cause 

damage to buildings and homes. In 2011, 

Arkansas regulators banned the use of 

disposal wells in part of the state. In California, where earthquakes are common, 

the thought of inducing even a small one 

This chart shows the desired fracturing fluid properties and their comparative 

performances. Graphic courtesy of University of Texas.

This chart shows the variation in the microcosmic signature of a slickwater 

and energized foam treatment in two western Canadian wells in which the 

same tonnage was pumped downhole to the same number of stages. The 

data shows the relative uniformity of seismic events with the foamed fracture, 

compared with the more scattered events in the slickwater fracture. Source: 

Paper SPE 166268.

Parameter Slick Water Linear Gel Pure CO2 Pure N2 Foams LPG

Fracture Creation ü ü ü ü ü ü

Wellbore Hydraulics ü ü ü û ~ ü

Proppant Transport û ü ~ û ü ü

Proppant Conductivity û û ü ü ü ü

Fluid Recovery û û ü ü ü ü

Reservoir Compatibility ~ ~ ü ü ü ü

Safety Hazards ü ü ~ ~ ~ û

Fluid Availability ü ~ ~ ~ ~ ~

Cost ü ü ~ ~ ~ ~

ü good performance û poor performance ~ unknown/field-dependent

JPT_June 2014_Energized Fractures.indd 50 5/15/14 2
ENERGIZED FRACTURES

52 JPT • JUNE 2014

has become the latest argument against 

expanding unconventional oil and gas 

development there. 

In regard to production problems, 

the introduction of millions of gallons of 

water can lead to formation damage in 

plays prone to clay swelling or water loading. This occurs when water is trapped in 

a reservoir’s nanoscale pores and inhibits the flow of hydrocarbons. Formations 

that are naturally low in water saturation 

are especially vulnerable to this effect. 

According to Sharma, there are only four 

places the fracturing fluids can go to: the 

wellbore, the rock matrix, unpropped 

fractures, or propped fractures. “There 

is really a question about what is happening to the frac water and how much 

of an effect it is having on our IPs (initial production) and recoveries,” Sharma 

said at a recent joint industry and university meeting in Austin, Texas. “The fact 

that we recover only about 20% of the 

water tells us it is sitting in one of these 

places.” Sharma and his team of research 

students concluded that one way to minimize water loading is to opt for an energized solution, because the gases do not 

cause swelling and can even help prevent 

water from saturating the rock.

As part of the UT-joint industry consortium, which is funded by 34-member 

operators and service companies, Sharma and his team have developed what 

they say is the industry’s first software 

capable of modeling energized fluids and 

foams, as well as conventional fluids such 

as gels and slickwater. Without this tool, 

operators would otherwise have little 

predictive ability when it comes to applying energized fractures. “All of the other 

hydraulic fracturing (modeling software) in the world are really designed 

for polymer or water-type fluids, which 

are assumed to be incompressible and 

isothermal, so the density and temperature do not change. There is no change 

in the fluid characteristics as it goes 

down,” Sharma said. The modeling software developed at UT takes into account 

the changes that energized fluids would 

undergo as it flows through the wellbore, 

The software, ERAC-3D, developed by the University of 

Texas, combines fracture, wellbore, and well productivity 

models for energized foams and fluids, as well as all other 

conventional fluids such as slickwater and gels. Image 

courtesy of the University of Texas.

The Montney play straddling British Columbia and Alberta 

in Canada is a long producing tight gas formation and was 

selected for a fracturing fluid comparison study because 

of the variety of solutions used. Graphic courtesy of Ferus. 

Temperature, °F

68.3507

68.2810

67.2113

66.1417

65.0720

64.0023

62.9326

61.8630

60.7933

59.7236

Shale

Siltstone

Sandstone

Erosional Edge

British Columbia Alberta

Laramide Thrust Belt

Facies 1

Facies 2

Facies 3

Montney Study Wells—Average Completion Costs

Fracture Fluid Type Avg. Completion Cost 

(USD Millions)

Data 

Points

% of Difference 

from Slickwater

Binary (CO2 + N2) Foam 3.18 12 –20

CO2 Foam 2.95 12 –26

N2 Foam 2.94 7 –26

Slickwater 3.97 4 —

Total 35

Source: Ferus.

JPT_June 2014_Energized Fractures.indd 52 5/15/14 2
JPT • JUNE 2014 5

such as the phase behavior, density, and 

temperature variations. The software, 

available only to consortium members, 

has been in development for more than 8 

years and was recently updated to feature 

a 3D user interface so engineers can visualize their well designs before choosing a 

fracturing fluid. 

The Canadian Experience 

Straddling the border between the Canadian provinces of British Columbia and 

Alberta is a long producing tight gas formation called the Montney shale. Production from the maturing Montney was 

revived in 2005 when companies began 

horizontal drilling programs in the area. 

Early on, operators were using hydrocarbon-based gels for fracturing, but 

in search of cheaper alternatives, more 

wells were fractured using energized fluids and foams. Then over the past 3 to 

4 years, larger operators in the area, 

including Encana and Shell, switched 

from energized solutions to slickwater 

as a cost-cutting measure. The variety of 

fracturing fluids used in wells located in 

relative proximity is why industrial gas 

supplier, Ferus, selected the Montney to 

carry out a comparison study using publicly available completion and production data. “It was a good opportunity to 

go in there and do a rate transient analyses study to see which systems were most 

effective,” said Murray Reynolds, director of technical services at Ferus and 

author of the SPE technical paper that 

outlined the study. “We looked at cost, we 

looked at NPV (net present value), and we 

looked at water savings.”

After analyzing the cost and completion methods used in 50 multistage 

horizontal dry gas wells that had been 

producing for more than 18 months, the 

study concluded that energized foam 

completions were about 25% cheaper 

than slickwater completions and used 

about 80% less water. The average completion cost for a slickwater completion 

in the area was USD 3.97 million, compared with about USD 2.9 million for a 

N2 or CO2 foam completion. Some of the 

added cost for the water-based treatments included water sourcing costs, and 

having to haul flowback fluids to disposal 

wells located more than 90 miles away. 

“As activity picks up, sourcing the water 

becomes more challenging for operators,” Reynolds said. “But it also means 

that finding a place to dump the water is 

becoming increasingly difficult.” 

The study says that wells completed with an energized fracture were able 

to produce earlier because CO2 and N2

flow up the well freely on their own in the 

cleanup phase. The energized wells also 

achieved higher recovery rates of gas over 

the slickwater wells, on average equal to 

USD 3 million per well. By volume, the 

energized fractures were 25% smaller and 

required 30% less proppant than slickwater-induced fractures, but produced 

more gas. “The proppant that is pumped 

is obviously placed in a position that is 

more effective,” Reynolds explained.

UT also compared data from horizontal wells in Canada and found similar results to the Ferus study. The university examined the completion methods 

and production results from three separate fields in the Cardium area in western Canada, and concluded that in most 

cases, the wells with energized fractures 

had the highest production rates and 

projected cumulative production curves. 

Operators in Canada are able to 

use CO2 and N2 in such a large proportion of their horizontal well completions because the technology is familiar to many service company crews in 

the region, the required equipment is 

readily available, and there is a strong 

supply network. Ferus reports that the 

demand for energized fracture treatments is increasing in Canada, but the US 

market is just now opening up. Because 

of supply limitations, Reynolds expects 

a slow uptake over the next 10 years for 

energized fracture treatments in the US 

compared with what has happened north 

of its borders. “If everyone in the Eagle 

Ford said tomorrow, ‘I want to switch to 

CO2 foam-based fracs,’ it is just not going 

to happen,” he said. “It will not be overnight, but I think it will happen.” 

Limited Use in the US 

The highest proportion of energized 

fracture treatments in the US is in the 

San Juan basin that spans northwestern 

New Mexico and the southwestern corner of Colorado. Driven by water availability and sensitivity to its use, around 

a quarter of completions in the San Juan 

basin used an energized component 

in the first half of last year, compared 

with approximately 3% in the Marcellus 

Shale, according to Houston-based market intelligence firm PacWest. In many 

other plays, including the prolific Eagle 

Ford Shale, energized fractures account 

for less than 1% of completions. 

A production curve chart shows the difference in cumulative oil production 

in the Buck Lake field located in the Cardium formation in western Canada. 

The slickwater used had a nitrogen content of 12% compared with 58% for the 

foam treatment. Graphic courtesy of the University of Texas. 

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54 JPT • JUNE 2014

Baker Hughes has carried out energized fracturing treatments in both the 

Marcellus and Eagle Ford and says its 

experience with energized fluids and 

foams in the US has so far been positive, 

in terms of cost savings and production 

results, but that operators are still in the 

early stages of determining how to use 

them. In the Marcellus, Baker Hughes 

has conducted completions using both 

slickwater and energized treatments in 

the same well. After an operator experienced difficulty stimulating the end of 

its long horizontal wells, known as the 

toe, it elected to try an energized solution. Satya Gupta, a business development director at Baker Hughes and an 

SPE Distinguished Lecturer on energized 

fractures, said the operator applied an 

energized treatment in the toe section 

and slickwater in the remaining stages. The operation was done with Baker 

Hughes’ VaporFrac technology, which 

uses a solution containing up to 95% 

gas. “The high-quality foams have better 

proppant transport than slickwater so 

you can stimulate (toe) sections very successfully,” Gupta said.

For the VaporFrac system, which 

uses very little water, an ultra-lightweight proppant is required because 

there are not enough liquids to carry 

heavy concentrations into the formation. 

In an energized fracture treatment, the 

amount of proppant required is proportional to the amount of liquid in the mix. 

Because the VaporFrac system uses highquality CO2 foam, it reduces the amount 

of proppant required for a horizontal 

well by as much as 90%. At an off-site 

facility, the proppant is mixed into a viscoelastic gel and is then delivered by 

truck. “So if you have a location, which 

has a very small footprint, you don’t need 

a blender or a lot of equipment,” Gupta 

said. “You just add gas to this preslurried 

gel, which already contains the proppant, 

and do a VaporFrac.”

In the Eagle Ford Shale, Baker 

Hughes is working on a pilot project with 

an operator that is seeking to increase 

production and reduce its dependency 

on hydrocarbon-based fracturing oils 

that it is using to replace water, but has 

found it to be an expensive alternative. 

The company has also applied the technology in wells with low natural pressure 

and formations that are prone to water 

trapping due to low water saturation. 

Despite its success in the field, Baker 

Hughes has found that the economics 

and logistics do not always favor the use 

of energized fractures. Gupta said that 

when supply and demand for energized 

fluids sync up, it is a cost-effective solution, but one that is only now being considered by many operators. “The technologies have been proven,” he said. “The 

reason they have not taken off yet, is that 

water is still available—and it is cheap.” 

Lack of Logistics 

Gas suppliers acknowledge that the supply network in the US for energized fluids and foams is not sufficent enough to 

support large horizontal programs in all 

areas. Linde realized this firsthand when 

it and another supplier were involved in 

a program in the US Rocky Mountains. 

Partly driven by the high cost of transporting water back and forth over mountainous terrain, the operator selected 

an energized solution but ran into some 

logistical challenges. “It took six CO2

plants to supply what I would call their 

modest well program,” Watts said. “And 

they were 8 to 10 stage wells, not the 

massive horizontals like you have in the 

Eagle Ford or Bakken.”

As it stands, Linde’s current supply 

infrastructure is only suited to support 

pilot projects and not large-scale commercial developments. Part of the reason 

is that the vast majority of the CO2 used 

in fracturing is sourced from industrial 

plants that can shut down for repairs at 

a moment’s notice, and in some cases, 

for weeks at a time. On the other hand, 

N2 can be produced directly from the air 

using separation units. Air Liquide says 

that large jobs have been supplied over 

the course of a few days with up to 3,500 

tons of N2 for multistage horizontal fracs. 

Still others maintain that more N2 generators are needed to increase the supply to 

the volumes required for horizontal campaigns. Linde says it is looking for operators to commit to energized completions 

by way of successful pilot programs. Only 

then, the company says, will more investments be made to expand the supply side 

of the business. 

A tanker truck carrying carbon dioxide makes its way down an icy mountain 

road in Carbon County, Utah, underscoring some of the logistical challenges 

involved in high-volume fracturing of horizontal wells in the more remote areas 

of the US. Photo courtesy of Ferus.

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56 JPT • JUNE 2014

Sticker Shock

Like its competitors in the industrial gas 

market, Air Liquide is also carrying out 

research and studying the problem of how 

to create a larger market for energized 

fluids and foams. One issue the company 

and its peers are facing is the impression 

that water is cheap and energized fluids 

and foams are expensive. Depending on 

the variables involved, it can go either 

way, according to Dave Wedel, commercial manager of Air Liquide’s oil and gas 

business in the US. “Compared to water, 

a container of CO2 looks expensive, so 

there can be a perceived cost issue,” he 

said, adding that because increased production by way of an energized solution 

is an assumed benefit, it is not always the 

most convincing argument. Wedel argues 

that the long-term productivity of the 

well must be taken into account in order 

for the benefits of energized fluids to 

be apparent.

Another barrier to the adoption of 

energized solutions in the US is the fast 

pace at which drilling and completing is 

occurring in shale basins. Over the past 

few years, operators have been working 

hard to offset the high cost of unconventional drilling and completion by implementing what many companies now 

call factory-mode drilling. Rather than 

approach each shale well with nuanced 

decision making, many operators have 

tasked their engineers with planning 

entire well programs in advance to save 

on time, materials, and the manpower 

required to complete dozens of wells as 

soon as possible. This means that some 

considerations are not as important as 

staying on schedule. “If a company is trying to drill 10 wells and if they go with 

an energized fluid and can only drill 7 

or 8, their goal is to drill those 10 and 

they might accept lower productivity per 

well in order to meet their schedule,” 

Wedel said. 

Production Benefits Debated 

One of the main arguments in support 

of using energized fractures is that while 

in some cases fluids and foams may cost 

more than slickwater, they can produce 

significantly more oil or gas. However, 

Fernando Covas, oil and gas consultant 

at PacWest, said some of his clients are 

still not fully convinced of this. “If there 

really is a production benefit, that would 

certainly outweigh any additional cost of 

the N2 or CO2,” he said. “But there are so 

many reasons why you may have higher production; it is a very big undertaking. No one has really been able to isolate those variables to come to a very 

clear perspective.”

In some cases, Covas said operators are reporting no difference in production when using energized fluids 

and foams compared with slickwater or 

crosslinked gels. Others say it has made a 

positive difference in production. Covas 

attributes the divergence in opinion in 

part to the short time for which engineers can observe production data from 

wells completed with energized solutions in the US. Operators interested in 

energized fractures are trying to carry 

out studies that eliminate other variables, such as the amount of proppant 

used, to verify that energized fluids and 

foams offer better results. “There are 

people out there trying to do this analysis,” Covas said, “but if you talk to different completion engineers, you will get 

different answers.” JPT

Long-Term Goal: CO2 Recycling

To enhance the economic viability of using CO2 for fracturing, General Electric 

and Statoil have teamed up to evaluate whether a recapturing system can 

be used to recycle the gas after it has been used in a well. The industry 

currently lacks the technology to capture the CO2 in the flowback phase and 

reuse it in another horizontal well. Without such a system, the CO2 is vented 

into the atmosphere, increasing both the carbon footprint of an energized 

fracture operation and its costs. At the recent SPE Symposium on Improved 

Oil Recovery in Tulsa, Oklahoma, Michael Ming, general manager of GE’s global 

research oil and gas technology center, said that the project is in its infancy 

and could not give a timeline for the development of such a system. “It is not 

a system that comes together tomorrow,” Ming said. “Some of the pieces may 

come together faster, but as a system it takes some time.”

The project is being funded under GE’s “ecoimagination” initiative that 

calls for the investment of USD 10 billion in clean technology research by 

2020. Working with Statoil, GE plans to use its suite of other technologies to 

design a system that could reuse high-quality CO2 in multiple horizontal wells. 

The research project is also taking a look at developing a small-scale CO2

generator for remote locations. 

For Further Reading

SPE 159812 A New 3D Compositional Model for Hydraulic Fracturing with Energized 

Fluids by Lionel Ribeiro and Mukul Sharma, University of Texas at Austin.

SPE 163867 Fluid Selection for Energized Fracture Treatments by Lionel Ribeiro and 

Mukul Sharma, University of Texas at Austin.

SPE 166113 A Day in the Life of a Barrel of Water: Evaluating Total Life Cycle Costs of 

Hydraulic Fracturing Fluids by Robin Watts, Linde.

SPE 168632 A Comparison of the Effectiveness of Various Fracture Fluid Systems Used 

in Multistage Fractured Horizontal Wells: Montney Formation, Unconventional Gas 

by Murray Reynolds, Ferus, et al. 

SPE 168645 Analysis of US Hydraulic Fracturing Fluid System and Proppant Trends 

by Purav Patel, PacWest Consulting Partners, et al.

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