"Tackling One Of The Fracking Industry’s Biggest Problems" by Robert Rapier

[Tom Nolan + 2,443]

Plasma Pulse Technology is a new fracking tech that requires no chemicals or water.  Its developers describe it as a technique that is complementary to fracking, at a fraction of the cost.

https://oilprice.com/Energy/Energy-General/Tackling-One-Of-The-Fracking-Industrys-Biggest-Problems.html

Tackling One Of The Fracking Industry’s Biggest Problems

By Robert Rapier - Dec 21, 2021, 12:00 PM CST

• The fracking industry has often been criticized for its tremendous water usage.
• Plasma Pulse Technology is a new fracking tech that requires no chemicals or water. 
• Its developers describe it as a technique that is complementary to fracking, at a fraction of the cost.

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In the previous article, I discussed some of the issues involving water and hydraulic fracturing (fracking). In a nutshell, although fracking has proven to be a highly effective means of boosting oil and natural gas production, the process requires millions of gallons of water. Further, there is the potential to contaminate water supplies. Although fracking isn’t going away anytime soon, it would be beneficial if there were some complementary tools for drillers in the event that conventional fracking could prove to be problematic. For example, an extremely arid area with certain types of hydrocarbon resources could be ripe for such a technique.

Several years ago, I first heard about Plasma Pulse Technology. As with many new technologies, I approached it with a healthy degree of skepticism. I like to see data, and at that time there wasn’t a lot of data yet available on the technique.

Plasma Pulse Technology was invented at St. Petersburg State Mining University in Russia. Conventional fracking uses water at high pressure to break open channels that then enable the flow of oil or natural gas into the well. In contrast, Plasma Pulse Technology through a powerful electrical discharge produces a high-pressure plasma pulse (5,000 psi), and the subsequent compression shock wave propagates along the path of least resistance (i.e., in the perforations). These compression shock waves propagate over long distances.

The first two or three pulses clean the perforation. Subsequent pulses penetrate into the reservoir, clean the existing channels, and create a network of micro-cracks. This enables oil to more easily flow into the well. Following the application of the technique, oil production can be boosted for several years.

To be clear, this isn’t voodoo. The technique is described in some detail in multiple technical reports and research papers. For example, in Petroleum Research Karan Patal et al. report on the technical details of how the technology works and specific case studies in Plasma Pulse Technology: An uprising EOR technique.

Its developers describe it as a technique that is complementary to fracking, at a fraction of the cost. It doesn’t always work in the same niche as fracking, but it has been shown to boost production in previously fracked wells.

Related: Gas Markets Could See Sudden Bout Of Volatility

Novas Energy rolled out Plasma Pulse Technology in China, Kazakhstan, Russia, and the Middle East a decade ago, and in 2014 it was introduced to North America. Novas Energy North America President and CEO Ken Stankievech described the advantages of the technology to me in a recent phone call:

“The cost differential between Plasma Pulse Technology and hydraulic fracking jobs is substantial. On a vertical well, Plasma Pulse Technology is 75% cheaper than an equivalent hydraulic fracturing job. On a horizontal well, depending on the lateral leg length of the project, it can be 90% cheaper than a traditional job, while operating without the extreme consumption of water and caustic chemicals.”

He added that they have performed the technique on wells as deep as 13,000 feet, but says the original tools have now been modified for extreme depths of 30,000 feet.

So far Plasma Pulse Technology has been used primarily on small wells, but the results have been promising. Novas Energy provided several case studies, some of which are available in the published literature.

Here are some of the cases in which the technique has been used:

• The Kuwait Oil Company well RA-000A was producing oil of about 196 barrels of oil per day (bopd) before the plasma stimulation and after the job the well is producing a stable rate of about 363 bopd. Plasma pulse produced an incremental oil gain of 167 bopd — an increase of 85% from the initial oil production rate. (Source: Chellappan, Suresh Kumar, et al. “First application of plasma technology in KOC to improve well’s productivity.” SPE Kuwait Oil and Gas Show and Conference. OnePetro, 2015.)
• Alberta Case Study 1 – Vertical well Lower Mannville, Retlaw Alberta. Pretreatment oil production of 12.6 barrels of oil equivalent per day (Boe/d) increased after treatment to 26.5 Boe/d — a 109% increase. The average 24- month increase is 73%.
• Alberta Case Study 2 – Vertical well Lower Mannville, Alderson Alberta. Pretreatment oil production of 27.8 Boe/d increased after treatment to 48 Boe/d — a 73% increase. The average increase was 44% over a 40-month period.
• Russia Case Study 3 – Vertical well in the Taylakovskoe oil field, a tight sandstone deposit.  Pretreatment oil production of 40 Boe/d increased after treatment to 145 Boe/d — a 275% increase. The average increase was 80% over a 48-month period.

Case Study 1 and 2 are available from the public data fields GeoScout provided directly from the client to GeoScout, a third-party data management company authorized by the Alberta Energy Regulator (AER). The Russian study was done by Slvneft-Megionneftegas.

Early results are promising, but oil and gas companies are notoriously conservative when it comes to embracing new technology. But Novas Energy believes 2022 is going to be a breakout year for them, as they have a committed book of business of more than 100 oil and gas wells for plasma treatment.

According to Stankievech “More and more of our clients are realizing that Plasma Pulse is an environmentally-friendly and cost-effective technology that can boost hydrocarbon productivity without breaking the bank.”

By Robert Rapier 

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[Refman + 207]

Stupid question, but why do they use water for fracking? Why don't they just use oil and avoid having to deal with the waste water?

[Eric Gagen + 713]

On 1/23/2022 at 9:30 AM, Refman said:

Stupid question, but why do they use water for fracking? Why don't they just use oil and avoid having to deal with the waste water?

In a very few cases they do,  but the amount of water used is very large - it's difficult to collect that much oil together in one place, and the tanks, trucks, etc. required to transport it are all more expensive than the ones required for water (after all, a water spill dries up - an oil spill is a hazard and reportable environmentally) It's also a safety hazard during the fracturing job.  Water can't catch on fire by accident, and the diesel driven pumps and equipment used to perform the fracturing treatment can get pretty warm.  In the event of some sort of screw up,  it can (and has) happened that the whole frac fleet burns down, even with water as the working fluid, but the risks are MUCH higher if you use oil as the working fluid instead.  

The real biggest #1 issue though is cost.  Oil costs (checks) $87 a bbl ~ $2 a gallon.  Depending on how you have to get it to the wellsite, water costs ~ $0.002 a gallon.  A typical frac job uses ~ 4 million gallons of water, and costs ~ $6 million - when you use water.  If you use oil instead,  you can tack on an extra $8 million to that cost and bring it up to $14 million.  Worse yet,  what you pump into the well usually doesn't come back out.  Out of the ~ 4 million gallons of fluid used in a frac job,  only between 1/3rd and  1/2 of it comes back out of the ground over the course of the next year or so, you have permanently flushed $4  $-6 million dollars worth of oil down the drain.  

The TOTAL cost of the well before this project was only going to be $8 million or so to begin with,  so by making the decision to use oil as your fracturing fluid, you have almost doubled the total cost of the well.  

[dukeNukem + 80]

19 hours ago, Eric Gagen said:

In a very few cases they do,  but the amount of water used is very large - it's difficult to collect that much oil together in one place, and the tanks, trucks, etc. required to transport it are all more expensive than the ones required for water (after all, a water spill dries up - an oil spill is a hazard and reportable environmentally) It's also a safety hazard during the fracturing job.  Water can't catch on fire by accident, and the diesel driven pumps and equipment used to perform the fracturing treatment can get pretty warm.  In the event of some sort of screw up,  it can (and has) happened that the whole frac fleet burns down, even with water as the working fluid, but the risks are MUCH higher if you use oil as the working fluid instead.  

The real biggest #1 issue though is cost.  Oil costs (checks) $87 a bbl ~ $2 a gallon.  Depending on how you have to get it to the wellsite, water costs ~ $0.002 a gallon.  A typical frac job uses ~ 4 million gallons of water, and costs ~ $6 million - when you use water.  If you use oil instead,  you can tack on an extra $8 million to that cost and bring it up to $14 million.  Worse yet,  what you pump into the well usually doesn't come back out.  Out of the ~ 4 million gallons of fluid used in a frac job,  only between 1/3rd and  1/2 of it comes back out of the ground over the course of the next year or so, you have permanently flushed $4  $-6 million dollars worth of oil down the drain.  

The TOTAL cost of the well before this project was only going to be $8 million or so to begin with,  so by making the decision to use oil as your fracturing fluid, you have almost doubled the total cost of the well.  

Eric, just to double check - is $6m bucks correct number for frac job these days? I was thinking something about $2-3m, in average...

For TOTAL cost of average shale well $8 mil - does it still costs $2m to drill the well? Rig day rates, labour and casing price went up.... 

 

 

[Eric Gagen + 713]

2 hours ago, dukeNukem said:

Eric, just to double check - is $6m bucks correct number for frac job these days? I was thinking something about $2-3m, in average...

For TOTAL cost of average shale well $8 mil - does it still costs $2m to drill the well? Rig day rates, labour and casing price went up.... 

 

 

might be $4-6 million for the frac job.  $3 million is definately too low - maybe OK for short laterals, but not enough for the average well. It's probably still ~ $2 million to 'put the hole in the ground' although with inflation I do expect this is going up.  Going up to what, I am not sure.  A lot of companies have contracts and inventory at 'old prices' that is keeping their costs down for now. My gut feel is that by the end of the year the all in cost of a shale well will be up to $10-12 million from the current $8-10 million.  The exact cost depends on the area, and if you include things like flowlines, lease acquisition and gathering systems.  These are costs in some areas, and in other areas are 'legacy costs' which were mostly paid for by previous operations. 

[kshithij Sharma + 78]

On 1/23/2022 at 9:00 PM, Refman said:

Stupid question, but why do they use water for fracking? Why don't they just use oil and avoid having to deal with the waste water?

In addition to what @Eric Gagen aptly said, the amount of water needed to frack a well and then create pressure to pump the oil out can be more than the amount of oil the well can produce. Even though a good amount of the water is recycled, it is still only about 50% of the total water that is pumped in. The rest either diffuses into the soil becoming ground water or seeps into the ground displacing the pores and cavity created by the extraction of oil. This means that if oil is used instead of water, the net oil extraction from the wells will go down by 50% as the oil wasted by seepage will have to be deducted. This makes the fracking much less technically viable by making its EROEI (Energy Return on Energy Invested) significantly lower than what it is. Currently the EROEI of most Fracking wells are in the range of 3-4. By using oi, it will come down to 1.5-2 and a good number of wells with current EROEI under 2 will simply be unviable

[Eric Gagen + 713]

4 hours ago, kshithij Sharma said:

In addition to what @Eric Gagen aptly said, the amount of water needed to frack a well and then create pressure to pump the oil out can be more than the amount of oil the well can produce. Even though a good amount of the water is recycled, it is still only about 50% of the total water that is pumped in. The rest either diffuses into the soil becoming ground water or seeps into the ground displacing the pores and cavity created by the extraction of oil. This means that if oil is used instead of water, the net oil extraction from the wells will go down by 50% as the oil wasted by seepage will have to be deducted. This makes the fracking much less technically viable by making its EROEI (Energy Return on Energy Invested) significantly lower than what it is. Currently the EROEI of most Fracking wells are in the range of 3-4. By using oi, it will come down to 1.5-2 and a good number of wells with current EROEI under 2 will simply be unviable

Any data on the EROI figures?  Most of the published stuff I have seen for shale oil wells is on the order of a 10:1 ratio or better.  

[kshithij Sharma + 78]

11 hours ago, Eric Gagen said:

Any data on the EROI figures?  Most of the published stuff I have seen for shale oil wells is on the order of a 10:1 ratio or better.  

The initial EROEI is 8-10 when the oil simply gushes out due to pressure from the gas formation but with EOR (enhanced oil recovery) the EROEI halves. Most of the EROEI calculation include the gas production too which makes the EROEI appear inflated. Assuming all the gas is flared off, the EROEI of producing "only oil" from the tight oil wells will be lower. Simply subtract the energy of all the gas (6Tcf gas = 1 billion barrel oil equivalent) from shale oil wells from EROEI and you will see that the EROEI will be lowered

 

An articles that speaks of the amount of water and frac sand injection: https://damnthematrix.wordpress.com/2018/06/01/why-the-eroei-of-oil-fracking-is-so-awful-revisited/

 

[Eric Gagen + 713]

6 hours ago, kshithij Sharma said:

The initial EROEI is 8-10 when the oil simply gushes out due to pressure from the gas formation but with EOR (enhanced oil recovery) the EROEI halves. Most of the EROEI calculation include the gas production too which makes the EROEI appear inflated. Assuming all the gas is flared off, the EROEI of producing "only oil" from the tight oil wells will be lower. Simply subtract the energy of all the gas (6Tcf gas = 1 billion barrel oil equivalent) from shale oil wells from EROEI and you will see that the EROEI will be lowered

 

An articles that speaks of the amount of water and frac sand injection: https://damnthematrix.wordpress.com/2018/06/01/why-the-eroei-of-oil-fracking-is-so-awful-revisited/

 

The amount of gas from tight oil wells which is flared is much much smaller than you are assuming.  About 1/2 of tight shale wells are for gas, and they don't flare any of it (they don't even make any oil usually).  As for the oil wells,  the most that got flared off was 10-15% in the Bakken in the mid-late teens, and in the Permian in the late teens .  Since Covid reduced demand for oil and allowed pipeline networks to catch up,  gas flared volumes are in the range of 1% produced now.  The other thing is that you are assuming EOR is being used in shale oil wells, and in general it is not.  There are pilots/tests taking place for EOR on shale oil wells, but there is no EOR on 99% of the shale oil wells out there.  

The article discusses the amount of sand and water used (sadly the graphics wouldn't load for me) but doesn't discuss EROI. 

[kshithij Sharma + 78]

On 1/31/2022 at 6:15 PM, Eric Gagen said:

The amount of gas from tight oil wells which is flared is much much smaller than you are assuming.  About 1/2 of tight shale wells are for gas, and they don't flare any of it (they don't even make any oil usually).  As for the oil wells,  the most that got flared off was 10-15% in the Bakken in the mid-late teens, and in the Permian in the late teens .  Since Covid reduced demand for oil and allowed pipeline networks to catch up,  gas flared volumes are in the range of 1% produced now.  The other thing is that you are assuming EOR is being used in shale oil wells, and in general it is not.  There are pilots/tests taking place for EOR on shale oil wells, but there is no EOR on 99% of the shale oil wells out there.  

The article discusses the amount of sand and water used (sadly the graphics wouldn't load for me) but doesn't discuss EROI. 

The well life of shale is 5 years before its EROI makes it unprofitable. EROI of 1.1 is practical feasibility limit as 10% energy is used in transport, refining and overheads as oil is never used directly. So, we have many wells which were drilled in 2010-14 and may be employing EOR by now.

I quoted the article to show that the amount of water needed for a shale well is 4.6 mil gallons for extracting 4 mil gallon oil. So, if oil is used in place of water and 50% is lost, it would mean loss of 2.3 mil gallons, effectively making the oil production 1.7 mil gallons, about 42.5% of initial level. Now, further subtracting the natural gas energy of 15%, we would come to figures of 27-28% of original EROI. This means an EROI of 8 would become EROI of 2. EROI of 5 would become 1.4, almost at the verge of infeasibility. Any wells with lower than 5 EROI would be unfeasible.

[kshithij Sharma + 78]

On 1/31/2022 at 6:15 PM, Eric Gagen said:

The amount of gas from tight oil wells which is flared is much much smaller than you are assuming.  About 1/2 of tight shale wells are for gas, and they don't flare any of it (they don't even make any oil usually).  As for the oil wells,  the most that got flared off was 10-15% in the Bakken in the mid-late teens, and in the Permian in the late teens .  Since Covid reduced demand for oil and allowed pipeline networks to catch up,  gas flared volumes are in the range of 1% produced now.  The other thing is that you are assuming EOR is being used in shale oil wells, and in general it is not.  There are pilots/tests taking place for EOR on shale oil wells, but there is no EOR on 99% of the shale oil wells out there.  

The article discusses the amount of sand and water used (sadly the graphics wouldn't load for me) but doesn't discuss EROI. 

Referring to this article: 

The gas production in Eagle Ford tight oil field is 5.8Bcf/day which is 2.1Tcf/year. The oil production is 1.05MBl/day which is 385MBl/year. Converting gas to oil equivalent, we find that 6Tcf gas = 1GBl oil (1 billion barrels). So, 2.1Tcf amounts to 350Mbl oil. the ratio of Gas to total energy produced is 350/(385+350) = 47.6%.

At least in this case, the energy from Gas is close to 50% or almost same as energy from oil produced, not merely 15%. I am not sure of Permian fields gas ratio and it may be just 15% there. However, considering that USA natural gas production almost doubled between 2010 and 2020 shows that it may be strongly linked to the shale oil extraction that also spiked during the same period.

Edited February 2, 2022 by kshithij Sharma

[Eric Gagen + 713]

6 hours ago, kshithij Sharma said:

The well life of shale is 5 years before its EROI makes it unprofitable. EROI of 1.1 is practical feasibility limit as 10% energy is used in transport, refining and overheads as oil is never used directly. So, we have many wells which were drilled in 2010-14 and may be employing EOR by now.

I quoted the article to show that the amount of water needed for a shale well is 4.6 mil gallons for extracting 4 mil gallon oil. So, if oil is used in place of water and 50% is lost, it would mean loss of 2.3 mil gallons, effectively making the oil production 1.7 mil gallons, about 42.5% of initial level. Now, further subtracting the natural gas energy of 15%, we would come to figures of 27-28% of original EROI. This means an EROI of 8 would become EROI of 2. EROI of 5 would become 1.4, almost at the verge of infeasibility. Any wells with lower than 5 EROI would be unfeasible.

I am in the oil and gas industry, and have spent quite a few years working with shale oil and gas wells.  almost none of them are subject to EOR programs, regardless of how old they are. The exception is several dozen wells owned by EOG in the south western portion of the eagleford, which are a part of a pilot project.  The rest either continue to produce at very low rates, or get plugged and abandoned, because nobody has come up with an effective EOR program suitable for shale formations. Even the ones drilled in the first round of horizontal shale production in 2008 are mostly still on production without EOR (a few have already been plugged and abandoned, but not many)

You can't subtract the natural gas energy, because between 95 and 99% of it is being produced and sold.  

I agree that if oil were being used as the frac fluid, that the whole enterprise would be doomed.  these are reasonable figures.  

[Eric Gagen + 713]

58 minutes ago, kshithij Sharma said:

Referring to this article: 

The gas production in Eagle Ford tight oil field is 5.8Bcf/day which is 2.1Tcf/year. The oil production is 1.05MBl/day which is 385MBl/year. Converting gas to oil equivalent, we find that 6Tcf gas = 1GBl oil (1 billion barrels). So, 2.1Tcf amounts to 350Mbl oil. the ratio of Gas to total energy produced is 350/(385+350) = 47.6%.

At least in this case, the energy from Gas is close to 50% or almost same as energy from oil produced, not merely 15%. I am not sure of Permian fields gas ratio and it may be just 15% there. However, considering that USA natural gas production almost doubled between 2010 and 2020 shows that it may be strongly linked to the shale oil extraction that also spiked during the same period.

Good analysis, but I wasn't trying to make an assessment of the Gas Oil Ratio (GOR) for different fields or areas.  The estimate of 15% (maximum) was the portion of the total gas stream from these regions which was getting flared, without regard for what the GOR in any particular place was.  

On an energy basis, the ratio for the Permian as a whole is ~ 30% gas.  However the Permian has different sub areas, some of which are mostly oil, and other which are mostly, or even completely gas. The Bakken (the 3rd major US shale oil province) is almost entirely oil, and is only about 10-15% gas on an energy basis.   

The doubling of US natural gas production between 2010 and 2020 is partly because of associated gas in oil wells, but is mostly due to natural gas ONLY shale wells.  These are clustered mostly in the Marcellus shale of the northeastern US, and the Haynesville shale in northwestern Louisiana.  there have also been less important production in Oklahoma, in the Fayette shale, and in the Utica shale.  

[specinho + 470]

errr..... pardon the crudeness of this drawing... from an outsider...

The points to be illustrated are:

1. there is no air between the water level in the cone shape funnel and the inner bottle below. Water flows sluggishly. Shall water is pumped into earth 13000 feet below (~ 2km?), imagine the efficiency using the illustration... much energy used but with minimal  output?

2. shall impulse is applied from the top, cracks might happen where they shouldn't below. Seepage, wastage and probably earthquake could be triggered on zones with thin crust?

3. the funnel conditional flow could be improved tremendously when the cone shape funnel is lifted slightly to provide air, or relief the pressure lock, at the bottle neck. Could there be a way to provide relief for the air lock ~ 2km beneath the earth? Just wondering.... from an outsider point of view....

From  the shape of a drill or a borer, could we assume the well is a straight and may be tight cylinder? Any possibility to have other shapes? Pardon my ignorant, i am just curious... :-p

[Refman + 207]

Thank you all for the replies and discussion