Frac’ing Goes Green… The Electric Frac Job Is Here!

Guest commentary by David Middleton

This morning, Charles passed a couple of articles on to me about electric fracking. One was from a WUWT Tip submission by RonPE and the other was in an email he received. My first thought was that it might be referring to the use of microwaves to free kerogen from oil shale… Alas, it was just referring to regular old frac’ing using gas turbines, rather than diesel engines to run the pumps.

From The Houston Carbuncle

BUSINESS // ENERGY
Baker Hughes chooses Permian Basin to debut ‘electric frack’ technology

Sergio Chapa April 30, 2019

Houston oilfield service company Baker Hughes is using the Permian Basin in West Texas to debut a fleet of new turbines that use excess natural gas from a drilling site to power hydraulic fracturing equipment — reducing flaring, carbon dioxide emissions, people and equipment in remote locations.

Baker Hughes CEO Lorenzo Simonelli spoke about the company’s “electric frack” technology during a Tuesday morning investors call. The company said its first quarter profit fell more than half to $32 million from $70 million during the same period a year earlier. Revenues rose to $5.6 billion from $5.4 billion revenue inthe first quarter of 2018.

As production continues to outpace pipeline construction in the Permian Basin, operators are burning off, or flaring, an estimated 104 billion cubic feet of natural gas per year instead of shipping it to market. Simonelli said he views wasted natural gas, a byproduct of oil drilling, as a business opportunity.

[…]

The Houston Comical

I’m not knocking this innovation. It’s a great idea in a mature producing area with so much excess associated natural gas that they have to flare ($200) to $300 million worth of natural gas every year to produce $243 million worth of oil every day…

El Paso Permian West Texas/SE New Mexico Natural Gas Prices (NGI)

Over the past two years, Permian Basin natural gas prices have dropped from $3/mcf to less than $1/mcf, briefly falling to -$2/mcf this spring. 104 Bcf is 104,000,000 mcf, worth about $50 million at the current Permian Basin price.

4 million barrels of crude oil per day times $60.74/bbl equals $242,960,000/day.

This is why none of the Permian Basin oil producers are losing any sleep over flaring natural gas. That said, Baker Hughes’ Electric Frac’ing crews will save Permian Basin operators money on frac jobs. Free natural gas is a lot cheaper than diesel fuel. So… Why do they call this “‘electric frack’ technology”? Because Baker Hughes is a subsidiary of General Electric.

Also from the Carbuncle


Climate Change: Baker Hughes pledges net-zero carbon dioxide emissions by 2050

And this…


BUSINESS // ENERGY
Marine renewables get focus at OTC
By Ilene Bassler, Contributor May 8, 2019

The Offshore Technology Conference is focusing on integrating marine renewables into its overall program, offering nine technical sessions — the most ever — on the topic.

[…]

The Houston Comical

Nine out of forty seven technical sessions is “focusing”? Two of the nine are on methane hydrates. One is on tidal and other hydrokinetic processes. Two are on offshore wind. The other four are on geotechnics. So… In reality, only three of the technical sessions deal specifically with “renewables.”

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57 thoughts on “Frac’ing Goes Green… The Electric Frac Job Is Here!

  1. Reduces Carbon Dioxide emissions?? We’re SAVED! We’re Saved!!
    No, it’s really a good idea if it reduces fracking costs.

  2. In order to be more green/renewable, couldn’t these turbines be powered by whale oil or perhaps polar bear fat?

    • Heck, the lefties will probably mandate that they run on soylent green.

      Renewable energy, and rids Mother Gaia of some of those icky excess humans.

  3. I grew up a couple hundred yards from an oil well that was pumped by a hit-and-miss engine running on NG from the well.
    Fell asleep many nights to the semi-rhythmic BANG! thunk-thunk-thunk, BANG-thunk…

  4. Actually calling it ‘electric frack’ is just transparently deceptive.
    Deception is cheaper than truth.
    Yeah, and we have COOL ‘all electric trains’!
    Pay no attention to the diesel generator behind the curtain.

  5. That’s a lot of gas….putting my green hat on….reinject it….will just cause oil to go $10 /bbl higher…but someday you will be able to sell the gas that is now being wasted…. or be able to turn it to CO2 a millenia or two from now and prevent a pending ice age.

    • To re-inject it, you have to drill injection wells and you can only do this if the reservoirs are suitable for gas injection. Frac’ed shale reservoirs generally aren’t suitable.

      Much of the gas sold from late spring to early fall is already injected into gas storage facilities for sale during withdrawal season. In order to inject it, you have to be able to sell it and transport it.

      Natural gas at less than $1/mcf literally has no value. When the price dropped to -$2/mcf, they had to pay to get the gas into the pipeline system. Baker Hughes use of gas turbines to run frac’ing pumps will reduce the flaring to some extent. But the only solution is more gas pipeline capacity out of the Permian Basin and into the places that need gas. Unfortunately many of the States in dire need of natural gas are blocking pipeline construction in their States or their neighboring States are blocking pipeline construction.

      • EOG has a successful gas re-injection program going on in the Eagle Ford.
        They claim the EF geology may limit the spread of this elsewhere.

        Granite Oil, up in the Bakken Viewfield in Saskatchewan, has a long running, modestly successful re-injection program taking place for a couple of years now.

      • The way I’m seeing it, in about 30 years the Blue states will be the new Appalachia-most people in poverty-because of the current decisions to destroy energy. The middle of the country will be the economic powerhouse.

  6. Our tax dollars subsidized all of those windmills that line the Permian… how much electricity could the flaired gas generate, in windmill units?

  7. It’s a great idea in a mature producing area with so much excess associated natural gas that they have to flare ($200) to $300 million worth of natural gas every year to produce $243 million worth of oil every day…

    In any corporate environment I’ve ever known finding a way to not throw away >$200 million per year gets you noticed big time.

    In government, finding a new way to throw away >$200 million a year gets your name on a public building.

  8. Living in Michigan I think it is crazy to flare nat gas, why can it not be captured and sold? When I visited Malaysia in 1999 we drove past a big nat gas flare near the road, that was hot.

    • The nat gas has to be first cleaned, then you need to build a pipe from the well field to wherever the nat gas is needed.
      The cost of this is sometimes more than you can sell the gas for.
      As the article mentions, there are often problems with greens fighting the building of any pipelines anywhere. Even though these pipelines would result in a reduction the amount of CO2 being produced.
      The nat gas is being produced and it is being burned, regardless of what the green morons do. If we get useful work out of it in the process that means some other type of energy will be used a bit less.

  9. Well, I think that this could be A GOOD THING if it’s done right (not left). Think about this: make the power plant go to the fuel, not the other way around. No pipeline law suits, just adding grid interconnects with portable substations, that move with the gas field de jure. And we stop wasting all that flare gas which is a whole sh*t load of BTUs that could be making KWHs….

    • Doing this would result in thousands of small power plants, one for each field where nat gas is being produced.
      Small plants are generally not as efficient.
      Small plants are generally more expensive per unit output.
      You still have to build power lines.
      When the field runs dry, you have to abandon the power plant, whether or not it still has useful life left in it.

  10. This approach of using electric pumps, supplied by natgas fueld turbines, started in 2014 in West Virginia by Antero.
    Evolution Well Service and US Wells are the 2 main frac companies doing this.

    Biggest – of many – reasons the gas is not captured in early years of a play’s development is the rapid drop off in gas output (similar to oil drop) in early months of production.
    To buildout relatively expensive gas capture infrastructure is not economically viable until more comprehensive production takes place.

    There is a plethora of ideas on how to effectively capture this early production.
    LNGo from Siemens (originally from Dresser) is a micro LNG plant that – supposedly – may have 18 units deployed in the Permian in the coming years.

  11. As the culprit who sent in the ZeroHedge story I have to expound on some of the implications.
    As David Says:

    But the only solution is more gas pipeline capacity out of the Permian Basin and into the places that need gas. Unfortunately many of the States in dire need of natural gas are blocking pipeline construction in their States or their neighboring States are blocking pipeline construction.

    This could be a game changer: take the power plant to the fuel, not take the fuel to the power plant. Having spent a big chunk of my misspent youth at sea I can attest that power plants, of industrial (city) size can be both compact and portable ( they float). Today one can envision a wheel based powerplant on rubber wheels or steel wheels (on rails) that could be moved periodically to the sources of fuel, and demand. Similarly, the interconnect substation could be modularized and portable (mobile) so the power source could be connected to the grid at the point of generation. Think about it.

    • As I said… It’s a good idea where you have excess associated gas production in a mature producing area. The Permian and, to a lesser extent, the Williston are good examples. In both of these plays, there is a well-established, stable, excess production of natural gas.

  12. I wrote a report on the North American frac sand industry in 2015 for Roskill Information Services in the UK – a multi-client study. At that time, frac sand production was~ 55million MT and average per well was 1500 tonnes.to give some idea of the size of this sector of the O&G industry. EOG (what’s left of Enron) was experimenting with closer spaced frac points and had upo3d qverage sand use to 2500t per well. At that time also, Schlumberger was experimenting with using liquid nitrogen as a fluid in fracking. I havent heard anything new on this, but it was a response to greeny enviro concerns.

  13. I noted a Bloomberg headline on April 10.
    “Oil Producers Are Burning Enough ‘Waste’ Gas to Power Every Home in
    Texas”

    • Marketed natural gas production from Texas could power ever home in Texas forty times over.

      Marketed natural gas production from Texas is about 20,000 million cubic ft/d… That’s 40 times the 553 million cubic ft/d flared in the Permian Basin.

  14. Also, a headline from “Tthe Daily Caller” on January 23:
    “{Lacking Pipelines, New England Awaits Its First-Ever Shipment of Russian Gas”

    • This past February 1, 2019, 2 Floating Storage and Regasification Units (FSRUs) from Excelerate delivered at a peak rate of 800 million cubic feet/day into the Northeast Gateway Port outside of Boston. (NB … not Everett).

      Next year, Australia may get the first of possibly 6 FSRUs at Port Kembla.

      FSRUs have just set up in Bangladesh, Pakistan, Brazil and Turkey.
      The rapid, widely dispersed use of LNG is changing our world overnight.

  15. Worked the Permian Basin as a field engineer for Halliburton Services in the early ’80’s (at the then Monahans District camp – later consolidated to the Midland camp) .

    I’m frankly puzzled why a service company would use natural gas for pumping. For example, Halliburton’s diesel pump truck’s were capable of achieving the pressures required for most frac jobs, cement jobs, and acid jobs. So, why have pump truck dependent upon site-sourced natural gas, when you can use the same diesel to run your trucks and run you pumps at all sites… including the the vast majority of sites that don’t have site-sourced natural gas? (Like most oil wells, exploratory wells, etc.). Can’t see how this would be economical. The service industry is a low profit margin business and you need to keep the capital investment in you equipment working every day to be profitable.

    And there are ways to boost the pressure from the pump trucks for special and high volume situations where pump trucks alone won’t do the jobs. So, isn’t not like high pressure/high volume problems can’t be overcome relatively low cost specialized equipment

    I wonder if the real problem is Baker’s pumping equipment? In my day, Baker Hughes had lousy pumps. Typically they couldn’t achieve the high pressures of the Halliburton pumps could and they tended to break-down more often. Maybe, Baker Hughes still has lousy pumps? Don’t know, since I been out of that business too long. (However, did take a lot of Bakers business away from them by “selling” Company men on Halliburton’s superior equipment).

    Maybe I’m missing something? Any thoughts from those with more recent experience would be appreciated.

    • That’s why I noted that this is only well-suited to the plays where there is a stable source of excess associated gas. It certainly wouldn’t work if there were no nearby wells producing an excess volume of gas.

      I don’t want to bash BHI, I have friends there and even coauthored a paper with BHI guys a few years ago… But, this strikes me as mostly a greenwashing gimmick.

      • Dave

        Baker Hughes did have good wire line equipment and expect it does to this day. It was its pumping equipment that didn’t meet the grade.

        Like you, I have friends that worked both with Baker Hughes and Western… including my best friend in High School/College (He worked the wire line end of the business).

        So, don’t take my above comment as a swipe at Baker Hughes’s overall value… I just did’t see them as a major player in the cementing, acid, and fracking parts of the business. Again maybe things have changed… I’ve been out of the service industry a very long time.

        I agree this looks gimmicky. But, I also question the economic viability of the concept… and not being careful with one’s penny’s is a sure way to go broke in that business.

      • You guys might get a kick out of reading about the Vor Teq missile from an outfit called Energy Recovery.
        In a nutshell, they propose using specialized cartridges that allow fluid to fluid transfer of pressure up to 15,000 psi.

        Thing is, their hardware enables all the pumps to be centrifugal, rather than displacement.
        Cost savings, space requirements, and high reliability are just some of the benefits.

        Problem is … it doesn’t work … yet, anyway.
        Vibrations seem to be big issue.
        If/when problems get overcome, could be a real game changer.

      • David Middleton & Joe B

        After thinking about it over night, I couldn’t see a company like Baker Hughes introducing a “crack pot” idea into the Permian Basin area without being able to produce any real competitive advantages to the local service camps and their “company men” customers. That’s serious market, with very serious no-nonsense players, and none of the players takes kindly to gimmickry… especially if it doesn’t save them cold hard cash.

        So, I came up with several possibilities why this might make sense. Consider the following:

        1) The frac pump trucks could be fitted with electric motors that are likely more compact and cheaper than diesel engines. So, they would have a capital advantage over trucks equipped with diesel engines. And electric motors would be cheaper to maintain than diesel engines.

        2) Due to the extra space on eack frac pump truck it might be possible to install more pumps on each frac pump truck. Say… four pumps vs the typical two. This could produce an additional capital advantage, lower personnel cost, and lower overhead maintenance. (Fewer trucks required per job site and decreased set up/break-down time per job).

        3) With fewer diesel motors in the frac fleet your typical camp manager could reduce the size of his maintenance shop and concentrate camp maintenance activities on customer oriented activities like more frequent pump packing (lowering chances of pump leaks during operations and possibility decreasing the number of spare trucks needed to cover this eventuality ).

        4) As a power source us multi-fuel turbines like those used on modern tanks. This would eliminate the problem of needing a source of on-site natural gas, since any on board liquid fuel could be used as substitute. Overall fuel consumption would likely be higher… but the reduced capital cost, lower, overall maintenance cost, and lower manpower cost could quickly well make up the difference.

        5) Given the more complicated nature of turbine maintenance, install turbine packages on each truck that can be rapidly replaced and the camp level (again like those installed on tanks). In this concept, turbine maintenance is centralized at a large specialty district-level maintenance shops… relieving camp-level maintenance burdens.

        6) While should be possible to configure each frac truck with turbines, the possibility of reduced set-up/break-down times using more pumps per frac pump truck might make using separate trucks exclusively equipped with turbine power packs a more sensible option. This requires a dedicated fleet of frac pump trucks, but, most large camps have dedicated frac fleet anyway. And none of this precludes using cement pump trucks form supplementing the frac fleet during extra-ordinary sized jobs.

        7) With fewer pump trucks connected to the well head, on-site safety could be improved simply because, there would be fewer hand-installed high-pressure connections leading to the well head.

        Under this concept the “green-washing gimmick” is “selling” use of on-site natural gas as a green house reduction strategy. The real goal would be reduced overall cost and improved on-site safety… Goals I think are more likely to be respected by any oil field “Hand”. Or as we used to say in my date a “Mighty Fine” solution.

        Keep in mind that all of this is speculative, comments appreciated.

        Dave

        • Dave

          Good points all, and – with one exception – both Evolution Well Services and US Well Services are pretty much doing what you just described.

          The exception is the power plant which is simply a mobile TM2500 turbine gas generator that supplies all the electricity.
          They lug the thing in, hook up to onsite gas (if available), connect to the electrical pumps in the frac fleet, fire up, and voila.

          Don’t know why it has taken so long to be more widely adopted, but this approach finally seems to be taking off.

          • Joe B

            Thanks much. Very interesting. Figured I might have been missing something in my first comment. And was clearly out-of-date. Going to start looking at this from an investment perspective.

            One side note, a check of the TM2500 turbine specs indicates it can run on liquid distillate fuels… so that solves the problem of needing on-site natural gas at all locations.

            In addition, it’s a 30 MW truck-trailer mountable unit with a 10 minute spin up time to full power, so it looks like a good fit for the pump only frac pump truck concept.

            Going to keep my eye on this.

            Dave

  16. There cannot possibly be a newspaper anywhere that is as out of touch with its local readership as the Houston Chronicle. The children they have on their editorial board are stunningly out of touch with economic reality. And don’t get me started about Ken Thomlinson….

  17. Using otherwise flared gas to produce electrical power is nothing new. Alstom Sweden sells a gas turbine originally based on a military jet engine from the early 50’s which has been used for this for decades. They seem a little bit embarrassed by it, since it is very old-fashioned and inefficient. However it is quite simple and robust and extremely insensitive to gas quality and there is a steady demand for it. “You can almost run it on wood chips” an engineer told me. This is important since flare gas is unrefined and can contain quite a lot of other things than methane.

    • tty

      Using otherwise flared gas to produce electrical power is nothing new. Alstom Sweden sells a gas turbine originally based on a military jet engine from the early 50’s which has been used for this for decades.

      OK, fine.

      You mandate the rule that flare gas must be run through a (portable) gas turbine to ???? A gas well ten miles from nowhere, 15 miles from a transformer and switchyard and high voltage transmission line to ???? to the nearest high tension line comes at what price in enviro permits and land permits and land purchases/leases and construction costs.

      10-12-15-20 miles of 10,000.00 per mile of high and medium-high volt lines is paid off by how much electricity from a 500 Kwatt (or less) generator for how many hours? Need to buy the transformer and switchgear and connection too: concrete and poles and copper and towers.

      Electricity doesn’t come cheap, quick, nor easy. IF the gas could be burned to make a profit by doing ANYTHING (even running a pump or compressor) it would be burned to generate that profit.

      • The electricity is used to power the well site. As you mention the site is 15 miles from nowhere so there are no power lines running out to it.

        The idea that a turbine that runs on waste gas from the well is cheaper than a diesel generator that runs on trucked in diesel.

  18. Too cheap to meter. That was the promise of nuclear reactors making our electricity. It was true then and now. Well, If you remove the punitive taxes unnecessary regulations and other hidden costs artificially imposed it’s still true. I have long wondered why Trump hasn’t required that all flaring gas be used as fuel to make electricity. I live pretty much next door to the Eagleford play. The countryside from Corpus Christi to San Antonio and beyond is dotted with fracking wells and accompanying flare stacks. Imagine if this wasted resource was put to the task of making electrons move through wires. Too cheap to meter, or damn close.

    • Aaron Edwards

      Good idea in concept, but likely limited by the way emissions are regulated in the United States.

      Use of flare gas to produce commercial electricity would run smack into Clean Air Act limitations in the United States. The problem being that the emissions from commercial electrical generation units are regulated to much higher standards than the emissions from industrial and oil field sources. If you were to use flare gas you’d quickly run into the exceptional strict standards for annual NOx, ozone season NOx, SO2, Hg, visible emissions (SO3 emissions associated with high sulfur content fuels – H2S in this case), PM (particulate), carbon monoxide, hazardous air pollutants (HAP), and VOCs (volatile organic carbons).

      Keep in mind that the emission standards set for stationary natural gas based electrical generating units are set based on the assumption that the natural gas being used has already been processed to remove the nastiest actors contributing to these emissions. H2S being just one example.

      Dave

  19. I find all of this interesting, but as a former employee of Caterpillar I’m puzzled there is no discussion of running diesel engines on the natural gas, either directly running the transmissions driving the injection units, or the electric motors. Diesel engines will run on all these fuels. And are generally much less finicky than turbines, which Caterpillar also sells, especially to oil & gas companies.

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