Why Is America (Texas) Burning Millions of Dollars Per Day Of Natural Gas?

[Douglas Buckland + 6,308]

Mike! Where is that darn 'button at the top' you mentioned earlier? I think it may come in handy in the future! 😂

[ronwagn + 6,290]

13 hours ago, Falcon said:

What ? My opening statement shows concern and states TRRC SHOULD ENFORCE CAPTURE OF ASSOCIATED GAS. 

Now it seems a group of mutual admiration friends want government to bail them out from lack of foresight and poor investment decisions. 

In another post Doug wants to know when small producers make comeback. Take an economics class.  Read the chapter on industry life cycle.

Doug I agree shale is fiasco, debt ridden etc FOR THE OPERATORS THAT FAILED TO SEE WHERE THE ECONOMICS WERE HEADING AND OVER LEVERSGED.

I've made poor investment decisions before.  I cut my losses and moved on.  Just have to make more good decisions than bad.  

Adjust to economic reality and change or stick your head in the sand like an ostrich and hope it all goes away.

GOOD LUCK

I guess I misunderstood your full intent. My bad. I just think that operators need to have the expectation, written into law, that they will not flare any more natural gas than is necessary to start a well and assure that the natural gas is used, transported, or stored. If small operations can't do that I think they need to work for a company that can. 

If proper procedures were followed, 95%, or so, of the gas could be used or stored IMHO. 

[Mike Shellman + 548]

11 hours ago, ronwagn said:

You are taking this discussion personally. It is not an attack on you. You have no say so as to how the operations are handled. Or do you?

The laughing thing is meant to insult me, personally; it didn't. I simply have a job and can't spend all day on the internet engaging with people who essentially only want to talk about how much money they make or have an abundant amount of time to cherry pick links from Google. Having said that there is, indeed, often a sorted effort to control the content of the forum. 

The vast majority of the shale oil industry is not going to do anything about flaring, because that costs money. It is not losing very much money by flaring if it can strip the liquids before it turns the gas lose. So it will keep flaring as long as it is not regulated, just like it will continue to use fresh water until someone makes them stop. Irresponsible operators and folks just interested in making a buck before the roof caves in are scared to death of regulations. That is short term thinking. Right now the shale industry thinks it's bulletproof. I fear by about mid 2020 it's going to find its not. It is going to have to weather a regulatory storm it is has never seen before. It will be totally unprepared.  

Edited May 30, 2019 by Mike Shellman

[wrs + 893]

12 hours ago, ronwagn said:

You are taking this discussion personally. It is not an attack on you. You have no say so as to how the operations are handled. Or do you?

I am not taking it personally at all, why would you say that? I have agreed that I don't think flaring is responsible or good but it has to happen if there isn't enough infrastructure to handle the associated gas.  It's a chicken and egg problem that I have been watching from the beginning back in 2012 when there was nothing in Orla.  

Of course as a landowner and mineral owner I have a huge say in how operations are handled, it's called a LEASE.  It's my land they are drilling on and putting roads, tank batteries, electric lines and pipelines over.  Of course I have a say in that if I entered an agreement with them.  The old lease that XTO is using gives them more rights than a modern lease but they still signed a land use agreement with us.  They also have not flared much gas, ever.  They got pipeline commitments before they drilled the wells so they don't have to flare.  That's responsible development.  

Our lease with the independent makes him pay us for flaring gas, it's a disincentive to flare for him.  We can't tell him not to flare but he agrees that he doesn't want to flare unless he has to.  From the start he had an agreement with the only gas processor out there back in 2014 to take our gas.  He only flared after the plant blew up in late 2015.  He was able to eventually reroute his gas to other processors and in the meantime we got paid for our lost minerals.  

As to my comment to Mike, I assume he would be as responsible as my current operators, i.e. he would do everything he could to avoid flaring by developing responsibly.  However, when the play is in wildcat status, there just isn't enough infrastructure and build out is not done until there is a certainty of sufficient flows.  It has taken several years but the infrastructure is now in place and more is being built.  The flaring is going to be substantially reduced by the end of the year but you won't hear about that in the news.

Edited May 30, 2019 by wrs

[ceo_energemsier + 1,818]

What will happen if this comes true and drops further? Maybe it will go down to 30$/bbl for a few months? thin out the herd across the board?

It will be a blood bath in the shale patch and it will be a clean up operation after that, the weak and sick will be gone and bigger , better operators with better quality rocks, better fiscal discipline and better economics will survive and thrive!

https://www.cnbc.com/2019/05/28/crude-could-drop-to-52-as-global-pressures-persist-top-technician.html

[ceo_energemsier + 1,818]

Solutions not denials!!!!!

https://oilprice.com/Energy/Energy-General/Electric-Fracking-Could-Take-Over-The-Permian.html

[ceo_energemsier + 1,818]

New Study: ‘Independent’ Oil, Gas Operators Drive American Energy Development By Wide Margin

Independent oil and natural gas producers are dominating the United States energy markets, according to a new study commissioned by the Independent Petroleum Association of America. Independent oil companies now accounting for 83%  of the nation’s oil production and 90% of its natural gas and natural gas liquids (NGL) production, according to “The Economic Contribution of Independent Operators in the United States,” which also finds that independent producers develop 91% of the nation’s natural gas and oil wells.

Independent natural gas and oil producers are defined as those companies that typically do not have midstream or refining operations, unlike the much-larger “major” or “international” oil companies. The report looked at more than 2,200 companies, and the direct, indirect and induced jobs created through their upstream activities. The report also provides state-level analysis, including production, well count and operating expenses by state.

The study, conducted by the business analytics group IHS Markit, also describes the economic contribution of independent oil and natural gas operators in the United States – up to $573 billion or 2.8% of U.S. GDP in 2018 and expected to rise to $823 billion or 3% of U.S. GDP by 2025.

Oil, natural gas and NGL production, as well as drilling and operations were analyzed for 2016, 2017 and 2018, and were forecast for 2020 and 2025.
Other key findings from the report:

    •    Through their business, supported 4.5 million American jobs in 2018;
    •    From 2016 to 2025, capital investment by independent companies is projected to increase by 87%, and;
    •    Independent producers will continue to drive solid contributions to the U.S. economy over the remainder of the study period (2025) and, quite likely, beyond.
      
“Independents continue to play a major role in America’s natural gas and oil industry. Their entrepreneurial spirit and willingness to take on risk spawns innovation – like opening up shale plays – while creating jobs and contributing to U.S. gross domestic product (GDP),” said IPAA President and CEO Barry Russell, in a statement. With these companies making up 90% of U.S. natural gas activity, their production is a critical component in supporting regional and local economies, maintaining strong national security and the effort to tackle global climate change with improved technology and efficiency.”

 

https://www.ipaa.org/wp-content/uploads/2019/05/IPAA-Economic-Contribution-Final-Report.pdf

 

Edited May 30, 2019 by ceo_energemsier
add

[ceo_energemsier + 1,818]

Texas crude oil production continues to break records in 2019. This comes in spite of declines in rig count, drilling permits, well completions and E&P employment, according to the Texas Alliance of Energy Producers’ Texas Petro Index.

The Texas Petro Index (TPI), a monthly measure of growth rates and cycles in the Texas upstream oil and gas economy based on rig count, drilling permits, well completions and employment, declined in 1Q 2019.

“Typically, these E&P indicators decline during an observable, sustained contraction in oil and gas activity, but that doesn’t appear to be what we’re seeing now,” said Karr Ingham, petroleum economist for the Texas Alliance of Energy Producers and creator of the TPI. “I do think these decreases can partly – even largely – be attributed to the sharp and unexpected fourth quarter 2018 crude oil price declines, but clearly there are other forces at work. These have become increasingly evident over the course of the current recovery and expansion from the 2014-2016 industry downturn.”

Part of this explanation comes from efficiencies by Texas oil and gas producers, with daily production exceeding five million barrels for the first time, according to Alliance estimates. Essentially, operators are making it happen with fewer resources.

After cyclically peaking in December 2018, direct upstream employment is waning – to the tune of about 3,500 job losses from December to March 2019. Further, the March estimate is down by more than 70,000 compared to the all-time peak employment total in December 2014.

Industry employment and crude oil production estimates in March suggest that for every one direct upstream oil and gas employee, about 700 barrels of oil are produced, compared to about 170 barrels per employee in 2009.

“Given current price levels, which continue to improve, the Texas upstream oil and gas economy remains in expansion mode,” said Ingham. “But the nature of oil and gas economic growth in Texas is different in 2019 largely because it has become perfectly apparent that Texas oil and gas companies can produce more crude oil with fewer resources deployed.”

[ceo_energemsier + 1,818]

Ohio's Shale Energy Industry Attracts $74B in Investment

 

https://www.constructionequipmentguide.com/ohios-shale-energy-industry-attracts-74b-in-investment/45086

[ceo_energemsier + 1,818]

 

Oil market glut will lead to declining prices through 2020 by Dr. Daniel Fine

 

With the OPEC-Russia meeting ahead, the price of oil is at a crossroad. 

President Trump wants lower prices for gasoline at the pump and the Democratic Party wants a shortage to lift prices higher. This is the 2020 presidential election, to re-elect Trump or a create a Democratic left-center White House.  

Is OPEC-Russia ready to sustain output cutbacks for $70 Brent Oil or continue revenue maximum against market share? Curiously, in the conversation at Vienna the Oxy purchase of Anadarko will resonate. Why? Oxy must now increase its export of oil to lower its debt (Warren Buffet and more) and prevent a serious management miscalculation of paying too much for Anadarko. 

Permian Delaware shale, with new high volume pipelines completed soon, must find expanding import markets of l.5 million barrels of oil per day or the equivalent of OPEC-Russia resuming late 2016 output for export.

As this writer concludes this column for the The Farmington Daily Times' Energy Magazine, which Is going on hiatus in San Juan County after this edition, there is no change in an outlook that dates back to the oil price crash of 2014-2016.  

There is too much oil (over-supply) against world demand for it.

Exxon-XTO in the Permian is prepared for $40 per barrel, and to still add  $82 billion value in the New Mexican Permian or the Delaware in the next 40 years.

However, along with Chevron, Oxy,  EOG and Pioneer, it must have a market for the economic recovery of reserves estimated at nearly 47 billion barrels in the Permian Delaware Basin. They must export against OPEC-Russia production.

The lifting cost of Saudi Aramco oil remains lower than Permian Shale. Saudi Aramco has sold debt (bonds) and 63% of its cash flow goes to its government? With oil demand slack and sluggish, and electric vehicles preparing for a 2024 market challenge both technically and politically (zero emissions). 

While associated natural gas has partially become a free commodity from Permian Delaware producers, natural gas is up next, after coal, as a target for Green Energy. It should resemble oil on a smaller scale as price dependent entirely on exports in the form of LNG.  

Will Persian Gulf, Australian, and Russian natural gas production roll backward in favor of American LNG? American exporters today cannot compete in a $5 per ton Asian LNG market.

Some San Juan Basin producers at the recent San Juan Basin Energy Conference openly discussed shifting capital spending

from natural gas to oil development.

This writer reaffirms his $50 average price for WTI oil in 2019 presented for the smaller independent producers at a briefing at Merrion Oil last December, but beginning early in 2020 forecasts a second half average of $38 per barrel .

In New Mexico, the Governor can adjust the Energy Transition Act basic law next February, but it should be a petroleum-revenue 30 day session without serious oil and gas organized opposition. 

New Mexico is now a hybrid Green State with more exportable oil and gas than every OPEC country except Iraq and Saudi Arabia, and yet it will impose the most effective rules for methane capture.  

No amount of ad hominem distraction against its policy and leadership will change this direction, and the nation could follow with the outcome of the national election next year.

Daniel Fine is the associate director of New Mexico Tech's Center for Energy Policy. The opinions expressed are his own.

https://www.daily-times.com/story/money/industries/oil-gas/2019/05/24/analysis-oil-market-glut-lead-declining-prices-through-2020/3760213002/

 

[ceo_energemsier + 1,818]

 

Good for big oil, thinning the herd plan, then go in and pick up the skeletons for pennies on the $

 

_____________________

 

(Bloomberg) -- Big Oil probably won’t be buying up the Permian Basin’s struggling independent drillers any time soon.

Years of costly exploration and frantic buying sprees have gutted shareholder returns in the world’s largest shale basin. And management teams and their financial backers can’t count on shale-hungry, cash-rich supermajors to buy them out.

Exxon Mobil Corp., Royal Dutch Shell Plc, Chevron Corp. and ConocoPhillips are all on record saying they are wary of scooping up smaller rivals at a time when would-be sellers are demanding premium payouts and global crude prices are under pressure from ample supplies.

There is “not always alignment among buyers and sellers,” Exxon Chief Executive Officer Darren Woods said Wednesday. He suggested Permian drillers may have to be squeezed by weak prices for a bit longer before they dial down their expectations.

“That’s often the case in a market, particularly in one that’s in transition,” Woods said.

Conoco CEO Ryan Lance has a similar view. There are “a lot of bid-ask issues sitting in the market today,” he said on May 23. “Expectations change” is what’s needed to stoke acquisition activity.

Shell has been on the hunt to bulk up in the Permian for some months but has yet to seal a deal. The Anglo-Dutch major was said to be in talks with privately-owned producer Endeavor Energy Resources LP in January.

Chevron walked away from buying Anadarko Petroleum Corp. earlier this month after being outbid by Occidental Petroleum Corp. “We’re serious about being disciplined,” Chevron CEO Mike Wirth said.

Occidental may have ended up with a winner’s curse. Carl Icahn, the billionaire investor, sued Occidental on Thursday for its “fundamentally misguided and hugely overpriced” bid for Anadarko.

[canadas canadas + 136]

If I ran some type of oil extraction operation and had some natural gas vented, I would try to see if I could get it to run a generator to produce electricity that would in turn power some oil extraction pumps, etc.  Getting natural gas to produce electricity from an onsite generator would be a bonus win.  A generator mounted on a truck would make it site mobile. 

Edited June 1, 2019 by canadas canadas

[ceo_energemsier + 1,818]

Flare gas solutions!!!

 

 

Siemens Enters Permian Gas Processing Market With Electric Compression Technology

Siemens was awarded a contract to provide three residue compression trains for two, 250 million (500 million total) standard cubic feet per day (MMscf/d) cryogenic gas plants in the Delaware Basin on May 30.

Each train consists of a 22,000 horsepower motor, gearbox, and multistage Dresser-Rand DATUM centrifugal compressor, all mounted onto a single skid. The compressors, motors, and drives will all be built by Siemens in the U.S. and is scheduled for commissioning the latter part of 2020.

Mid-size gas treatment plants traditionally use reciprocating compressors driven by electric motors or gas engines. However, with the increase in production from shale plays, larger gas plants—in the range of 200 to 300 MMscf/d—are being constructed, forcing gas processing companies to consider alternative compression solutions in order to reduce costs, footprint, and maintenance.

While the traditional approach would require 10 large reciprocating units for this project, Siemens’ centrifugal compressor solution met the entire plant duty for this 500 MMscf/d project using just three compression units while ensuring low turndown capability. The plot space and the ancillary infrastructure—such as foundations, piping, wiring, cabling and electrical systems—was also remarkably reduced resulting in significant capital cost savings for the customer.

The high efficiency of the DATUM compressors, coupled with their easy maintenance, was a major factor for selecting this configuration. With a DATUM fleet availability of more than 99.7%, the plant will have minimum downtime despite the un-spared compressor configuration and will ensure minimal loss of production, bringing significant value to the customer in meeting contractual production guarantees.

“This project is an excellent example of Siemens’ ability to offer its customers a complete integrated solution,” Patrice Laporte, vice president of Oil and Gas for Siemens America, said.

[ceo_energemsier + 1,818]

On 5/29/2019 at 10:36 AM, ceo_energemsier said:

I have said this before under different topics on this forum about flaring and also about the indiscriminate waste of precious water resources used in drilling and hydraulic fracturing operations, both of which are being addressed but not fast enough. This is one area where I do support Federal/State intervention in passing science based, technology driven , sensible and meaningful regulation to put an end to environmental quality degradation, waste of natural resources, reuse and recycling of natural resources, proper management of natural resources and timely approval of permits for sound and safe build out of needed infrastructure such as storage tanks, feeder and trunk lines, processing and gathering facilities etc.

On the subject of exports, I do not believe that there should be a ban on exports unless it is defined and classified as a nationals security matter. It would boil down to the aspect of putting a ban on exports of any goods or services produced or grown in the US based on an industry's or a specific group's interest. We could just go on and start demanding to ban the export of US beef, poultry, soybeans, cotton, corn, beets, sunflower oil, canola oil , ethanol, US steel, US pharmaceutical products and the list goes on.

 

 

I have mentioned some where else on this forum recently and last year about the various options for produced gas before pipelines and processing/gathering facilities are in place to prevent the flaring.

These options below can be deployed rapidly in comparison to large scale facilities and can be dismantled and relocated to a new location/new production  basin as needed in the future.

One has to understand that when E&P companies go into an area to explore and drill, the midstream companies (pipelines, oil and gas separation and processing plants, storage and other related infrastructure and services companies) do not go before the E&P companies to lay the pipe and develop the infrastructure, until such time the basin/region proves out to be containing substantial resources (oil gas etc) for years to come and can be sustainable for the long term. Once that is established , they rush in to provide the services and develop the infrastructure. Federal, State and Local permitting is also a major factor how fast these facilities are developed and put into operations.

This, however does not preclude the E&P companies nor the services companies to sit idle and just flare the gas. Can you imagine if E&P companies just let the oil flow out of the wells into the fields and ditches and waterways? Why spew the gas then into the air?!!!

The industry needs to cooperate and collaborate with each other and out of industry players with the right techs and concepts to develop meaningful, sustainable, cost effective, environmentally safe methodologies, technologies and applications and implementation of all these to maximize the use of the resources available and being developed.

1) Produced gas re-injection into the formation or into another zone for later use and or increasing liquid hydrocarbons production volume sa an EOR for liquids recovery.. We tried that in several different parts of the country and different countries and it worked well. Saved a valuable resource for future use and also prevented the air quality issues etc.

2) Compact (and or small scale) GTL plants that would convert the gas to liquids fuels . There are several companies that offered the solution in the oil and gas fields and provided it as a service. Some companies provide tech services that will convert the natgas to high quality methanol, ethanol, formalin/formaldehyde and other petrochem feedstocks and liquid fuels  and further use of inhouse tech to components of cleaner burning fuels. This adds value to the end product compared to just the lower value of the gas and these liquids can be transported off site by tanker trucks with ease or stored at a nearby storage facility for further transportation via rail or connect to a products pipeline if feasible.

3) Compact LNG plants , offering the same as 2) for easy onsite or near site within a play /field region for gas to LNG and further transport by LNG trucks to points of storage/transport or re-gasification

4) On or near sites of production and or production basin based compact NG- LPG plants

5) Portable/mobile natgas power plants that can provide electric power to the operators on site and also can connect that generated electric power into the grid

6) Develop regional gas storage hub as the E&P companies ramp up exploration and production in the basin or region. It could be in salt caverns or man made storage facilities as the production is ramping up. It will require shorter pipeline distances or temporary pipeline setup that are safe and reliable to move the produced gas to the nearby basin /regional storage hub. Collaboration would be required with the permitting and approval process for these as well. Once the trunk pipelines are in place, the companies can move the stored gas to areas where the demand is.. power plants, main gas storage hubs, LNG plants etc.

 

Just some thoughts, some of which have been executed and implemented with success! Rampant, illogical, willful , negligent flaring for ease and convenience should end!

However, perhaps, probably, some folks who do not like the shale industry, would go on to demand , and actually have demanded the shut down of the shale industry, without any scientific merit to ban hydraulic fracturing. CO is on such a path.

 

There is no need to flare the gas in the Bakken or in the Permian, solutions and technologies exist to stop the flaring. I have done that in our operations from the start of any project development. States should start imposing strict and high value fines that will definitely impact the companies doing it and will make them stop. They should get fined certain $/boe gas flared.

 

 

 

 

https://energyofnorthdakota.com/home-menu/impacts-solutions/flaring/

 

https://www.galileoar.com/us/historias/distributed-lng-production-galileo-flare-reduction-solution-for-bakken-shale-2/

 

https://www.pioneerenergy.com/

 

 

https://www.researchgate.net/publication/307967387_Natural_Gas_Flaring_-_Alternative_Solutions

 

https://www.scirp.org/journal/PaperInformation.aspx?PaperID=74459

[ceo_energemsier + 1,818]

Gas Flaring in the Permian

Last month the Environmental Defense Fund released an analysis of NOAA satellite data estimating volumes of gas flared in the Permian Basin in 2017. Its findings: operators report half of the amount of gas actually flared.

104 Bcf of gas is enough to serve all needs of Texas’ seven largest cities – $322 million worth of gas. The State also does not collect severance tax on that gas.

Operators must obtain permits to flare gas and report volumes flared. The RRC has not denied any permits. Between 2016 and May 2018, the RRC issued more than 6,300 flaring permits in the Permian. Between 2008 and 2010, the RRC issued fewer than 600 flaring permits for all of the state.

EDF’s analysis also compared the top 15 oil producers in the Permian (click on image to enlarge):

Last October S&P Global Market Intelligence issued an analysis of flaring in the Permian Basin and the Eagle Ford. It also relied on satellite data and a NOAA algorithm that estimates flared volumes. Its analysis concluded that in 2017 Texas operators flared 163 Bcf of gas, about 2.6% of the state’s natural gas production. NOAA data indicates that Operators may have flared nearly 1 Tcf of gas from 2012 to 2017. The analysis also remarked on the difference between reported volumes of flared gas in Texas – 1.6% of production in 2017 – and NOAA estimates of 2.6%. (S&P Global’s report online has a cool graphic showing rates of flaring over time on a map of Texas.)

In contrast, S&P Global found closer agreement between NOAA and state data in North Dakota, where the Bakken production occurs – but still under-reporting of flared volumes. North Dakota regulators have sought to reduce flaring and fine violators, planning to require producers who exceed allowed flaring levels of 15% of production to shut in their wells until pipeline infrastructure can be built to market the gas.

EDF’s report also analyzed flared gas on state-owned University Lands, more than 2 million acres in the Permian. University Lands collects royalties on flared gas. EDF concluded that UL has a lower rate of flaring on its wells – 2.75% – than the overall Permian average of 4.4%. A higher degree of lease management and the requirement to pay royalties on the gas flared likely correlated to better performance.

Both EDF and S&P Global concluded that state regulators should incorporate NOAA satellite data into their regulatory oversight to identify violators. EDF also recommended that operators be required to pay state severance tax on flared gas. EDF’s other recommendations included requiring best flaring technologies, eliminating the duration of flaring permits, and encouraging technologies that capture the gas onsite.

Yesterday the three commissioners of the Texas Railroad Commissioners, Ryan Sitton, Christi Craddick and Wayne Christian, appeared before the Texas Senate Natural Resources and Economic Development Committee and were questioned about these reports that methane emissions were “much higher than the EPA predicted in West Texas.” All said they did not believe those reports. Sitton said he thought the volumes reported to the RRC are “very close to accurate.” Craddick said she was “not sure if [the reports] are accurate or not.” Collin Leyden of EDF commented that the commissioners “seem to dismiss the reports on the grounds they believe that the data they have is correct. I did not hear any sort of technical analysis of the satellite data indicating they had found any sort of flaws or errors.”

 

 

 

 

 

[ceo_energemsier + 1,818]

A good series on this forum about gas flaring!!

and ongoing solutions being brought forth instead of just NO TO SHALE!!

Fueling fracturing with natural gas: Redefining wellsite power for oilfield services

On Aug. 24, 2017, Hurricane Harvey was barreling toward the middle of the Texas Gulf Coast shoreline, packing winds up to 145 mph and reports of anticipated rainfall in excess of 36 in. As the storm loomed closer to making landfall, the team at Evolution Well Services was busy evaluating the best plan of action—Harvey’s projected path was headed directly for one of their newly deployed fleets of electric power generation and fracturing equipment in the Eagle Ford shale.

The personnel decision was an easy one; people on location quickly battened down the hatches and promptly evacuated to safety for an undetermined amount of time, not knowing what the severity, length or aftermath of the storm would be. The newly minted equipment, however, still gleaming with its fresh coat of silver-fleck paint, was not going to be so lucky. The decision was made—the fleet was going to ride out the storm where it stood.

Two days after Harvey had passed, the crew was re-deployed to the wellsite. What they found was incredible; no notable damage to any of the equipment. The team spent the day completing safety checks, ensuring that all systems were “go” for resuming fracturing operations later that night. The natural gas line was opened, feeding the custom turbine generator, and momentarily after that, electricity was flowing out to the pump trailers, blender, and ancillary equipment on location. Pumping operations resumed, and business as usual commenced, Fig 1.

Fig. 1. On location in the Eagle Ford, Evolution’s electric fracturing fleet, powered by local natural gas, provides an alternative to traditional diesel engines.

 

AN ALTERNATIVE FUEL FOR FRACS

What was not realized at the time, was that the majority of the other frac fleets in the basin were still not operational, and they wouldn’t be for many days or weeks yet to come. The situation confirmed a key value of electric-powered fracturing—the insulation from disruption of a continuous diesel supply to location. Harvey had introduced major disruptions into crude refining and fuel logistics across the Gulf Coast region. On the Wednesday of Harvey’s approach, 110 mi east of Houston, the largest crude oil refinery in the U.S. made the decision to close for an undetermined amount of time. According to CNBC reports, 20% of U.S. refining capacity was taken off-line by the storm.

While other pressure pumpers anxiously awaited the arrival of diesel trucks on wellsites across the Eagle Ford and beyond, Evolution was completing stage after stage on the client’s wells. The service was accomplished with a patented, custom-power generation package, fueled solely by natural gas pulled directly from local in-field gathering lines. In this particular case, the fuel source resided just 10 yards away.

The story is reminiscent of how, and why, Evolution got its start in 2010, in British Columbia, Canada. At that time, the large Kitimat LNG export facility was being planned. The nearby Horn River basin held untapped reserves that would feed the facility, and well completions were required to recover them. Once it was determined that the wells could produce enough gas to fuel a fleet of fracturing equipment, it was clear that there was an opportunity at hand to implement a new technology. 

The geography, harsh climate, and remote location of the planned operation increased the risk of interruptions in consistent fuel supply, which in the case of a conventional hydraulic fracturing fleet would typically be a continuous string of diesel tankers (roughly six per day for today’s fracturing designs). And so, Evolution began exploring how the Horn River field gas could be used to fuel the fracturing operations, thereby eliminating the need to continuously deliver diesel fuel to the remote locations.

During this concept phase, the company filed their first patents for a scalable, electrically powered fracturing system that uses natural gas to generate onsite electrical power.

ENERGIZING THE WELLSITE

The initial technology used a turnkey gas turbine generator package from General Electric: the GE TM2500+. The package delivered 32 MW of mobile generation capacity, and successfully powered Evolution’s first commercial fleet from 2016 to 2018.

The current system was developed to cut the move time between wellsites, which was taking four to upwards of seven days. This meant that nearly a quarter of each month consisted of non-operating time. Any time spent mobilizing equipment between wellsites signifies dollars lost. The non-productive time is so crucial in fact, that it is recorded in intervals of minutes, not hours. 

Optimizing the power generation package. To maximize efficiencies and increase up-time, the power generation package was redesigned to provide a more rugged, rapidly deployable package for hydraulic fracturing and other oilfield applications.

The redesign resulted in a custom-power generation package and creation of an affiliated entity, Dynamis Power Solutions, Fig 2. Dynamis and Evolution designed, patented, and have manufactured six custom turbine generator packages, using the GE LM2500+ G4 turbine engine. In 2018, the engine had a reliability rating of 99.9%. The generator packages have a high power density, with their road-legal dimensions housing 36 MW (roughly 48,000 hp). The packages have reduced average pad move times by more than 50%, allowing clients to bring producing wells online two to four days faster than before. 

Fig. 2. Custom 36-MW turbine generator package improves mobility of power generation equipment.

 

In a February 2019 application, the process of turbine rig-down, mobilization to a location 8 mi away, rig-up and distribution of power to the fleet was accomplished in just 14 hr.

Rounding out the frac fleet. The electric power generation solution opened new opportunities in designing the remainder of the fracturing fleet. Because the pumping trailers no longer had a traditional drive-train (the diesel engine and accompanying transmission) required to power each pump, significant real estate was available on each trailer to do something truly unique.

The most recent generation of pump trailers contain a single 7,000-hp electric motor with a dual shaft. Each end of the dual shaft directly couples to a 3,500-hhp frac pump. The typical frac fleet houses 56,000 pumping horsepower across eight pump trailers.

Controls and automation. The advanced control logic governing the operation of the pump trailers incorporates a balancing process across the two 3,500-hhp frac pumps; this greatly diminishes hydraulic harmonic vibration across the unit. Variable frequency drives control essentially every electric motor on the fleet. Not only does this control provide infinite adjustability to motor speed (and subsequent pump speed—meaning no more having to choose between gears while pumping), but it also provides more efficient use of power and sets the stage for enhanced automation and diagnostic ability. Various data streams from the variable frequency drives are monitored during operations and oftentimes predict component failures prior to an event. When routine pump maintenance is necessary, it is completed safely from ground level—all process equipment is on lay-down trailers that place pumps at a height that does not require elevated maintenance platforms.

Feeding all of the pumping trailers is a custom blender that houses two independent blending systems, each capable of rates of 120 bpm. The need for an external hydration unit was also eliminated with a 250-bbl hydration tank incorporated onto the dual-blending unit. This provides flexibility in blending operations to perform nearly any job design within the footprint of one trailer frame.

Safety implications. Engineering controls are the first line of defense and, ultimately, the most effective way to avoid injury is to keep folks out of harm’s way. Evolution’s custom IMPACT data van allows operation of the entire fleet from safe positions inside the data van. The van, which extends to three separate operating levels once on location, comfortably accommodates the client’s representatives and the entire frac crew, which is half the size of a conventional fracturing crew.

These units, as well as the other custom components that make up the fleet, are all powered by electricity produced by the Dynamis turbine generator package. The generator produces 13,800 V, which feeds through a custom switchgear unit prior to distribution to all process equipment on location, Fig 3.

Fig. 3. Process flow of locally sourced natural gas through the turbine generator, and subsequent electricity distribution to process equipment and ancillary services.

 

EVOLUTION OF DESIGN 

The latest generation of equipment reduces the number of ground cables from 59 to just 16, bundling all power and communication lines into one cable per unit. The system uses a custom-designed, circuit-protected plug and receptacle to connect each piece of equipment. This reduces trip hazards, and saves on cost and maintenance, as well as reduces the amount of time required for rig-up.

Reducing environmental impact. The fracturing fleets have a footprint that is 50% of a conventional hydraulic fracturing fleet. In certain basins where pad sizes are particularly small, the reduced footprint has enabled pumping operations without enlarging the pad size. The capability suggests wellsites could theoretically be built smaller, lessening the environmental impact and the effect on surrounding communities.

A GREENER ALTERNATIVE

In addition to fuel savings achieved by fueling frac fleets with natural gas instead of diesel (which typically range from $1 million to $2 million per fleet, per month), the emissions profile and other health, safety and environmental factors achieve wide-reaching improvements. Since inception, Evolution has conserved nearly 450,000 lb of carbon monoxide from being emitted into the atmosphere, and has hydrocarbon emissions (including methane) that are 95% lower than the Tier IV Final Non-road Compression Ignition Standards set by the EPA in March 2016, Fig 4.

Fig. 4. Comparison between EWS’s custom turbine and Tier IV diesel emissions standards.

 

Methane from oilfield operations. The topic of methane emissions has recently been in the industry spotlight, and for good reason. While the EPA established carbon dioxide as the reference point for Greenhouse Warming Potential (GWP) with a value of 1, methane, by comparison, has a GWP ranging from 28 to 36. And this is certainly not a game where the high score wins.

Atmospheric impact. In short, the GWP is a metric combining two different factors: radiative efficiency, which is a measure of how much energy the compound can absorb; and lifetime in the atmosphere. While CO₂may linger in the atmosphere for a thousand years or more, methane typically only resides there for about 10 years. However, the radiative efficiency of methane is considerably higher, essentially making it a warmer blanket for the earth. Although the industry has reduced methane emissions substantially since 1990, natural gas systems still rate as the second-highest source category for such emissions in the U.S.

E&P drive to reduce emissions. There are other drivers, as well, for working to capture the methane that is escaping from oil and gas operations across the globe. According to Newsweek,53% of U.S. companies tied executive compensation to performance targets aimed at being more environmentally friendly. Just a decade ago, that number was less than 10%.

Less wasted fuel. Additionally, 2016 marked the first time in U.S. history that natural gas fueled more electricity production than coal; 34% was produced from natural gas feedstocks and 30% by coal. Most would agree with the consensus that emissions standards are not likely to be relaxed in any material way in the future, meaning that natural gas will likely have a growing role in electricity production in the near-to-mid term. Therefore, all methane escaping these operations to the atmosphere could be looked at as spilled fuel; not contributing to production of useable power for the demands of growing populations.

APPLYING LEAN PRINCIPLES TO COMPLETIONS

During a time in the industry, where efficiencies are paramount, the process of delivering diesel still contains four of the eight types of waste included in classic Six Sigma principles; movement, waiting, transportation, and extra processing.

Where does diesel come from? Let’s follow the journey of a hydrocarbon molecule destined for use as diesel fuel in fracturing operations. How many times does the hydrocarbon molecule change location and chain of custody? It starts at the wellhead with the E&P company; next it is delivered to the midstream company; it then transfers to a holding facility; then on to the refinery; then back to a holding facility; then to the distribution rack; then to a retailer hauling it back to a wellsite, and then ultimately selling it back to an E&P company. 

Ripple effects. What about the emissions from the diesel tankers, delivering fuel to remote wellsites (not to mention the energy intensity of the diesel refining process itself)? Since commercial operations began in 2016, Evolution has conserved nearly 14 million gal of diesel fuel. This equates to over 3,300 tanker truck journeys, Fig 5. In addition, Evolution frac fleets contain fewer than half the number of trailers as a conventional frac fleet, meaning 50% fewer tractors are pulling equipment over the road with every pad move.

Fig. 5. The group of sand silos on the left had been working with Evolution on their electric fleet, while the silos on the right had been working on a conventional diesel wellsite.

 

Not only is this beneficial from an environmental perspective, but safety and civil infrastructure are impacted, as well. According to the latest reports from the Bureau of Labor Statistics, truck drivers and delivery workers have the highest rate of workplace fatalities.

Eliminating hot fueling. Once fuel trucks arrive on wellsites to fuel conventional diesel-powered equipment, the danger hasn’t yet passed. The refueling of the fracturing process equipment with diesel, while the pumping operations are occurring, is referred to as “hot-fueling.” The design of the standard conventional frac pump trailer, along with the fact that a large amount of equipment is typically parked very tightly together on a wellsite, poses a health and safety risk to those individuals involved in the hot-fueling process.

Combine these factors with the extremely large volumes of combustible fluid at hand, and the frequency with which this operation is done (daily on hundreds of frac sites nationwide), and risk of a potential disaster is increased. There have been dozens of equipment fires on fracturing sites over the past 15 years, with the vast majority of them pointing to hot-fueling operations as the source. Each fire poses risks to health, safety and the environment, as well as immense capital destruction. In 2018, alone, there was over $100 million in insurance claims filed by North American pressure pumpers, due to fracturing equipment lost in wellsite fires.

QUIET TECHNOLOGY

Many well completion operations in places such as the Barnett shale of North Texas are required to operate on “daylight only” schedules, strictly due to the noise produced by conventional frac fleets and associated services. One operator, currently working in close proximity to Oklahoma City, reached out to Evolution recently, because local residents had issued numerous complaints to local congressmen regarding excessive noise coming from nearby wellsites. Conventional diesel fracturing fleets operate at a noise level of 110 decibels or more. OSHA Standard for Occupational Noise Exposure requires hearing protection be worn anytime that the 8-hr time-weighted noise level exceeds 85 dB. Evolution’s fleet comes in at 85 dB or below.

In efforts to reduce the disruption that fracturing fleets might induce, the company has engineered and manufactured custom exhaust equipment for each power package, substantially dampening the noise during operations to levels that will comply with all currently published North American noise standards.

WHAT EVOLVES NEXT FROM THIS TECHNOLOGY?

Recently, Dynamis and Evolution have worked to improve wellsite operations by feeding produced electricity to other service providers on each location. 

Powering ancillary wellsite services. Plans are to expand the ability to act as an on-site power provider for other ancillary services such as wireline, water transfer and chemical mixing, including the design and manufacture of custom electric pump-down units, which are planned for deployment in the second quarter.

Recently, Evolution worked with Solaris Oilfield Infrastructure to extend the natural gas-fueled power for use with the Solaris sand delivery systems, in lieu of utilizing their conventional diesel generators for power. This was accomplished in short order, because Solaris also uses electric motors, components and controls, all on variable-frequency drives, typically powered by their own 480-V three-phase generator.

Heat capture. Another patent application that was recently added to the list outlines designs to capture otherwise wasted exhaust heat from the turbine generator, and repurpose that energy to a heat exchanger that can be utilized to heat water for fracing operations in cold-weather scenarios. The thermodynamic calculations predict that water will be heated by 30°F at a rate of 100 bpm. 

Data analytics. All of these operations are remotely monitored and, where sensible, are automated, from a joint Evolution and Dynamis Operational Excellence Center that opened this year in The Woodlands, Texas. This space is mission control for all data analytics, predictive maintenance, and artificial intelligence projects currently in the works

[ceo_energemsier + 1,818]

A good series on this forum about gas flaring!!

and ongoing solutions being brought forth instead of just NO TO SHALE!!

 

______________________________________

 

 

 

 

[Outlaw Jackie + 78]

Silly what this simple post about flaring, or wasting gas has devolved into.  One of several reasons I avoid this platform. 

Edited June 3, 2019 by Outlaw Jackie
Accuracy

[John Foote + 1,135]

On 5/28/2019 at 10:40 PM, Falcon said:

Don't know that Governor Perry was to blame.  The 2008 crash lead to Fed policy of "free money" and shale gas and oil was the only game in town. 

Did Perry let producers slide re gas capture prioritizing oil production ? Maybe.

But not his fault some thought that interest rates would be low forever or thought oil prices would always go up and never drop below $100.

 

The interest fiasco is so much more than shale. Personally I wish the government had bit the bullet and allowed fundamental reform. Baring that, as things improved raised rates a bit. The latest solution is essentially still mostly free money and tax cuts. We probably agree believing this won't end well.

A lot of Texas is on state owned land, very much under State control. Why UT and A&M have such wonderful endowments. 

I doubt anyone believed in free money forever, but the nature of the free market system is to take advantage of opportunities. But we have a case of privatized gains, public takes the risk when the Fed maintains essentially free money. 

[ceo_energemsier + 1,818]

Apache's Altus opens Permian gas processing plant

 

Apache Corp.'s Altus Midstream Co. said it opened its new Permian Basin processing plant to treat its production of natural gas and natural gas liquids.

The announcement comes after Houston-based Apache said in April it was dramatically cutting back on its natural gas production in the Permian Basin for now because of steep pricing discounts caused by pipeline and processing plant shortages in the region.

 

The opening of the Diamond Cryo Complex in its Alpine High portion of the Permian could soon get Apache's gas output moving again. Altus said it started up the first of three cryogenic processing facilities, called trains, this week with the other two expected to come online later this year.

The plant is expected to help process large volumes of purer streams of natural gas and NGLs, including ethane, propane and butane.

 

 

Altus launched late last year as a publicly traded spinoff of Apache's pipeline and processing facilities.

 

 

Apache's emerging Alpine High development in the Permian is expected to produce large volumes of gas in addition to crude oil output. There's so much associated gas produced along with crude oil that many companies are having to pay to have the excess gas shipped away. Either that or they're simply flaring more of the gas and burning it into the atmosphere, contributing to pollution and climate change.

That's why Apache opted to temporarily scale back on its production, especially in the gassier areas of the Alpine High.

 

"This is the proper approach from both an environmental and economic perspective relative to other industry practices such as flaring or selling associated gas at a negative or unprofitable price," Apache Chief Executive John Christmann said in April.

But the new processing plant can help Apache ramp its activity back up in the relatively near future.

Altus also announced it closed on its acquisition of a large stake in Kinder Morgan's Permian Highway Pipeline to carry natural gas from the Permian to the Houston area. The pipeline is expected to be completed by October 2020.

Altus now owns a 26.7 percent stake in the pipeline project.

[ceo_energemsier + 1,818]

Real life Solutions to real life issues in the Shale sector, Permian, solving critical issues with long term, sustainable economically feasible and viable solutions.

________________________________________

 

Exterran lands major water contract with Permian producer

Exterran Corp., a global systems and process company offering solutions in the oil, gas, water and power markets, announces its Water Solutions business has secured a significant produced water treatment contract with a major operator in the Midland area of the Permian basin.

The 30,000 barrels of water-per-day (bwpd) treatment system includes the removal of oil-in-water, suspended solids and iron. Offered as a turnkey package, the provided solution also includes accessories, manpower, and remote monitoring and reporting of water treatment data.

The contract follows a successful three-

month pilot in late 2018, where Exterran met or exceeded oil-in-water, suspended solids and iron outlet performance levels.

Todd Kirk, director of water at Exterran, said: “Over the past two decades, we have had many successful produced water operations around the world in over a dozen countries. These include a wide range of unique solutions designed to help meet any customer need from small mobile units that are lightweight, easy to ship, install and start-up to handling over a million bwpd of produced water at large processing facilities.

“Customers appreciate our expertise, efficiency and operational excellence. By partnering with a turnkey produced water specialist like Exterran, operators not only get a reliable portfolio of technologies, but also a team of experts to solve their water challenges and support them at a moment’s notice. Facility simplification, data acquisition, AI and experienced technicians help to solve manpower limitations in the basin and improve operations efficiency.”  

Exterran offers operators a full range of primary, secondary and tertiary treatment solutions for removing oil, contaminants and suspended solids from produced water. The company designs, builds, and operates systems that quickly, efficiently, and cost-effectively treat produced water ranging in volumes from 100 to in excess of 1,000,000 bwpd. 

[ceo_energemsier + 1,818]

A big solution to gas flaring issue!!!!

__________________________

 

 

Cheniere, Apache sign historic Permian shale LNG deal

 

Cheniere Energy and Apache Corp. have signed a first-of-its-kind agreement on liquified natural gas. Through a newly announced, 15-year deal, Apache will produce and supply LNG to Cheniere Corpus Christi Liquefaction Stage III LLC, a subsidiary of Cheniere Energy Inc. The LNG price paid to Apache will be based on global LNG indices.

According to Cheniere, Apache has agreed to sell 140,000 MMBtu per day of natural gas to the Corpus Christi facility.

“This first-of-its-kind long-term agreement with Apache represents a commercial evolution in the U.S. LNG industry, as it will ensure the continued reliable delivery of natural gas to Cheniere from one of the premier producers in the Permian Basin,” said Jack Fusco, president and CEO of the gas company, adding that the deal will give Apache flow assurance on its gas.

 

The Corpus Christi Stage III project is being developed to include up to seven midscale liquefaction trains with a total expected nominal production capacity of approximately 9.5 mtpa. Corpus Christi Stage III received a positive Environmental Assessment from the Federal Energy Regulatory Commission in March 2019 and is expected to receive all remaining necessary regulatory approvals for the project by the end of 2019.

Last week, Apache signed a deal with Altus Midstream to handle other portions of its shale gas.

John Christmann, Apache’s CEO and President, said the agreement was made to leverage Apache’s Permian Basin asset scale and diversify its customer base.

Cheniere has one of the largest liquefaction platforms in the world, consisting of the Sabine Pass and Corpus Christi liquefaction facilities on the U.S. Gulf Coast, with expected aggregate adjusted nominal production capacity of up to approximately 45 million tons per annum of LNG operating or under construction.

[ceo_energemsier + 1,818]

Altus bolsters Permian gas midstream foothold with pipe, plants

Altus Midstream is positioning itself for a long-term presence in the Permian Basin shale gas scene. This week the company bought into a long-haul pipeline plan designed to move more than 2 billion Bcf/d of natural gas from the Waha area in West Texas to the Texas Gulf Coast.

Through its 27 percent interest in the Permian Highway Pipeline, Altus will invest roughly $161 million in the project that it expects to be complete in 2020.

“This is a high-quality project supported by take-or-pay contracts with creditworthy counterparties,” said Clay Bretches, CEO and president.

Altus also announced this week that it has brought the first of three cryogenic gas processing facilites online in the Waha area. The

news should be welcomed by Apache Corp., who earlier this year had to shut down some gas production in the region of Altus' new cryogenic processing facility due to the lack of takeaway options and the price for gas. 

"These cryogenic processing facilities feature state-of-the-art SRX processing technology, which optimizes processing economics with better NGL recoveries in both ethane recovery and rejection mode versus more commonly used processing methods in the Permian Basin. Better recoveries will drive enhanced netbacks for Apache and provide a competitive advantage to Altus for third-party business," Bretches said.

[ceo_energemsier + 1,818]

More shale water solutions:

_______________________________

 

Companies Focus On Replacing Freshwater Sources

Technology for reusing flowback and produced water offers solutions for regions facing limited water sources and drought.

 

 

With the market for water management technology, handling and solutions expected to grow from about $8 billion in 2019 to more than $10.5 billion in 2026 by various estimates, service companies and midstream water providers are vying to supply the infrastructure, processes and equipment to meet operators’ needs for water treatment and transportation.

Midstream water companies are installing both permanent and temporary pipelines throughout unconventional shale plays in efforts to reduce the number of trucks hauling water. The number of water treatment facilities and water hubs is growing in shale plays with limited surface water availability.

With increased seismicity in several areas, such as the Scoop/Stack and Mississippi Lime in Oklahoma and the Permian Basin, companies are placing more emphasis on managing saltwater disposal wells while maintaining the disposal capacity needed by the industry.

The Permian Basin is one of the basins facing a shortage of surface water. Service companies and water midstream companies emphasize the reuse of produced and flowback water as a major solution.

The following companies are representative of some of the key players in water management and their approach to meeting oil and gas industry demand.

Aquatech Energy Services
With a total water system for sustainable upstream oil and gas water treatment solutions that are based on end use for the water, Aquatech Energy Services (AES), a division of Aquatech International, has been providing services on a turnkey basis to operators of both unconventional shale and conventional wells to manage, treat for reuse, and dispose of drilling, flowback and produced water.

The company also uses biocides and disinfectants to treat source and produced water for sulfate-reducing bacteria, reduction of H₂S and prevention of biofilm formation within storage tank batteries. Source, flowback and produced water are treated for iron and manganese to reduce hardness-bearing compounds, such as barium, calcium and magnesium, and to reduce sulfates. 

The AES team has extensive field experience, mostly in the Marcellus Shale play. The aim of the company is to develop solutions that ensure consistent water composition with minimal contaminants for predictable production characteristics in hydraulic fracturing and also minimal downhole scaling. For example, its MoVap mobile distillation system is designed for removal of total dissolved solids to produce ultraclean water, which will help reduce wastewater volume.

The AES treatment processes are based on technology from Aquatech International. Business options range from short-term to long-term contracts operating at well pads using mobile treatment units or at central facilities using fixed modular treatment units, according to the company’s website.

Its systems include the MoSuite system for producing reusable and sustainable water sources for multiple well pads as well as for reducing the volume of freshwater. The MoTreat mobile pre-treatment system removes total suspended solids and also can treat for hardness, bacteria and select precipitation of metals. AES operates multiple merchant central water treatment facilities serving producers for treating and disposing of wastewater from E&P activities.

Aqua Terra Water Management
Aqua Terra Water Management partnered with De Nora Water Technologies to provide a one-stop shop for produced water management. The company combined its disposal and pipeline transportation infrastructure with De Nora’s water treatment technologies to create a fixed-facility recycling option.

“By leveraging Aqua Terra’s extensive existing infrastructure and vast experience in disposal facilities with De Nora’s technologies, the market now has an efficient and inexpensive solution for the transportation, disposal and recycling of their produced water,” a July 9, 2018, press release stated.

“De Nora has always prided itself on having the environment at the core of its business values,” said Bryan Brownlie, managing director at De Nora Water Technologies Texas LLC. “Working together with Aqua Terra provides a sound solution for mass recycling in some of the most water-challenged areas in the U.S., including the Permian Basin.”

De Nora is a designer of safe and sustainable water disinfection and oxidation, filtration and electrochlorination solutions.

Aqua Terra’s goal is to provide solutions by providing expertise and strategies that meet regulatory and environmental requirements, according to the press release.

Aqua Terra CEO Cory Hall said, “When the drought hit in 2011, the use of freshwater became a serious issue throughout the Permian Basin. As the fracking processes become more advanced, our team has looked at and evaluated many different recycling techniques. Through our research, we have concluded De Nora’s process is best in class, which allows us to offer our customers a reasonably priced, effective substitute for freshwater for their fracking operations.”

According to the press release, “Recent recycling conducted by Aqua Terra Water Management utilizing De Nora’s process at Aqua Terra’s Jaker facility resulted in 98% reduction of iron, 100% bacteria kill, 100% removal of H₂S and an 80%-plus reduction in total suspended solids, capable of producing excellent quality frac fluid with one unit able to treat 100,000 barrels per day.”

Baker Hughes, a GE company
Baker Hughes, a GE company, Well Chemical Services help protect the integrity of wells while maximizing production before, during and after fracturing operations. Customized solutions are designed to avoid fracturing water challenges with superior water analysis and treatment while improving productivity with a customized flow assurance program.

The H2prO SR water management service uses a mobile system with proven filtration technology to remove suspended solids from produced and flowback water. It returns up to 99.9% of the water for reuse in hydraulic fracturing and other oilfield operations. The operator can conserve freshwater, reduce transportation and disposal costs, and ensure regulatory compliance, the company stated on its website.

The mobile H2prO SR service is more flexible, providing an economic solution compared to permanently installed equipment. Each filtration unit can treat up to 10,000 bbl/d of water and is simple to set up. It has a low energy consumption rate, which lowers overall operating expenses. Each unit has a small footprint and requires no special permits to transport, so the units can be deployed quickly to meet any time schedule, the website said.

The H2prO HD well chemical service uses environmentally preferred chemistry to treat produced and flowback water in tanks, reserve pits, impoundments and ponds. Using proven chlorine dioxide technology, the service neutralizes microorganisms, H₂S, iron sulfide, phenols, mercaptans and polymers in the surface water. The water can be reused for downhole operations with no threat of corrosion and equipment plugging, according to the website.

The H2prO HD service has a fast chemical reaction time, concentrated solutions and high chlorine dioxide generation rates. A single, mobile unit treats up to 200,000 bbl/d of water. The H2prO HD well chemical service includes pre- and post-water testing to ensure conformance to water quality standards, the company’s website stated.

Basic Energy Services
Basic Energy Services’ network of fresh and brine water stations, particularly in the  Permian Basin where surface water is generally not available, is used to supply water necessary for drilling and completion of oil and natural gas wells.

The company’s water logistics segment provides oilfield fluid supply, transportation, storage and disposal services required in workover, completion and remedial projects as well as in daily producing well operations, according to Basic’s website.

With service locations positioned in major basins to support a wide range of drilling programs, Basic provides trucking and water hauling expertise through 1,000 trucks manned by experienced, trained drivers. In addition to water treatment services for recycling water, the company also offers rental of portable frac tanks and test tanks for storing fluid at the well site.

The company’s water logistics assets include specialized tank trucks, portable storage tanks, water wells, frac tanks, test tanks and saltwater disposal (SWD) wells.

Basic provides fluid services through fluid supply, transportation and storage services using a fleet of more than 800 fluid service trucks supported by portable storage tanks, water wells and disposal facilities, the company said.

For water recycling, Basic provides efficient and environmentally responsible water recycling services featuring the chlorine dioxide process, the website noted. Basic’s Water Recycling Services group provides environmentally friendly water treatment services that efficiently recycle water, reducing the number of trucks needed for offsite disposal while
increasing productivity. The Water Recycling Services group complements the Pumping Services and Fluid Services water hauling and SWD services, providing a complete range of options for water management needs, according to the website.

As part of its commitment to the environment, Basic uses a fleet of LNG-powered trucks primarily for water hauling, the company noted.

 

Blackbuck Resources
With operations across New Mexico, Texas and Oklahoma, Blackbuck Resources LLC (BBR) designs, builds and operates water infrastructure and provides water-related services to the oil and gas industry.

The company’s infrastructure division provides produced water gathering and disposal systems while the energy services division offers treatment of produced water for reuse as well as transfer services.

BBR also boasts the only full-service pond management offering, utilizing an advanced aeration system and remote water quality monitoring alongside physical sampling and corrective remediation, according to the company.

On July 12, 2018, Xedia Process Solutions announced it was acquired by Blackbuck Resources LLC. BBR will be led primarily by the prior Xedia management team and will be supported by an equity commitment from Cresta Energy Capital. With Xedia’s water treatment experience and technology, BBR has a “competitive advantage” in providing E&P companies with “a one-stop shop” for water treatment, transfer, storage and disposal, a press release stated.

Xedia functions as a wholly owned subsidiary of BBR, offering its water treatment products to E&P operators globally, while BBR provides Permian Basin E&P operators with treatment services and water infrastructure.

In the press release, former Xedia and current BBR CEO Justin Love said BBR will continue to improve and expand its ability to tackle the energy sector’s toughest water challenges by leveraging a growing team and pool of expertise and its existing footprint as a technology-enabled treatment service company.

 

Cudd Energy Services
To deliver custom-engineered systems to address water management challenges in oilfield operations, Cudd Energy Services’ Water Management Solutions (WMS) group provides water treatment, water recycling, biocide services and well remediation. These systems offer a cost-effective method for managing onsite fluid supply, treatment and pit circulation, according to the company’s website.

The WMS technology is designed to provide flexibility in setup configurations while improving personnel safety and operational efficiencies. These systems allow easy mobilization, rapid rigup capabilities and seamless integration with a variety of remote control and automated features, the website noted.

The company’s personnel plan and implement its systems to improve operational efficiencies and mitigate risks. WMS provides the optimal treatment plan and configuration to meet water needs safely and efficiently.

The water treatment system consists of a contained, mobile unit that restores produced water for reuse in oilfield applications by eliminating bacteria from fresh, produced and recycled water sources. The system reduces solids content, removes hydrocarbons, breaks down emulsions, accelerates iron removal and destroys H₂S in produced water, according to the website.

Compartmental units are housed on individual trailers that can be rapidly mobilized to centralized pits, tank batteries and water collection/treatment facilities. Produced water may be transported to the treatment area or extracted from tank batteries or existing pits, the website stated.

The biocide treatment system treats produced water, surface water, surface vessels and wells for bacterial control. The biocide treatment system also includes oxidizing treatments to control iron sulfide, eliminate H₂S, remove biomass and biofilm, break emulsions and control other oxidizable species.

This system uses Petro-Flo Microbiocide, a fasting-acting biocide that effectively controls all types of bacteria. WMS performs onsite water testing to determine the optimal dosage to treat the particular water source.

De Nora Water Technologies Texas LLC
De Nora offers energy-saving products and water treatment solutions, serving many industries with diverse applications. With technologies and processes for the filtration, oxidation and disinfection of water and wastewater, De Nora has been addressing the offshore and onshore water treatment needs of the oil and gas industry for decades, from proven solutions in biofouling control, sewage treatment and membrane filtration on offshore drilling platforms to onshore frac water disinfection, produced water recycling and oil refinery process water treatment. De Nora offers a comprehensive portfolio of proven water treatment solutions for the oil and gas market’s water challenges.

Bryan Brownlie, managing director at De Nora Water Technologies Texas, said, “By working with our oil and gas partners, we’ve demonstrated that we can produce results with market-beating economics, not just for produced water recycling, but also for frac water disinfection—without the safety risks inherent to the use of chlorine dioxide in an enclosed trailer.”

DistributionNOW
For fully customized modular design, DistributionNOW (DNOW) U.S. Process Solutions, which includes Power Service, Odessa Pumps and Total Valve Solutions, can provide customized skid package engineering, design, fabrication and installation services for water management needs. The packages have integration technology so that a unit can operate completely automated.

For offshore and onshore oil and gas operations, the company provides saltwater disposal (SWD), waterflood, water transfer and custom-engineered packages. Its filtration systems are available for fresh and produced water transfer skids, custom SWD packages, chemical injection skids and waterflood packages, according to the company’s website.

Pumps are offered from several manufacturers, including Schlumberger’s Reda HPS horizontal surface pumps, NOV/Moyno positive displacement and progressive cavity pumps as well as Griswold and Flowserve ANSI B73.1 pumps. Equipment is selected for the best fit for the application.

For 60 years Power Service has designed, engineered and fabricated SWD and waterflood packages.

With multiple packaging options, DNOW Process Solutions can customize the operator’s facility whether it is an open unit with a small reciprocating pump or a large facility with multiple horizontal multistage pumps. Control logic allows modulation of the facility’s flow. An operator can inject into multiple wells at varying pressures from a single injection pump and can adjust to surges in incoming rates, the website stated. The packages can be designed for injection rates up to 60,000 bbl/d and pressures up to 5,000 psig, stated the website.

Whether by pipeline or truck, the company’s extensive knowledge of hydraulics, fabrication and automation ensures that the operator’s facility will provide reliability.

Dow Water & Process Solutions
With a wide range of water treatment technologies, Dow Water & Process Solutions offers the technical expertise to treat water produced by shale gas and oil extraction via hydraulic fracturing techniques, according to the company’s website.

Dow specializes in removing the organic compounds and harmful metals from flowback and produced waters before reuse or discharge. The company’s ion exchange and DOWEX OPTIPORE polymeric adsorbent technologies are used to remove the metals and organic compounds such as benzene, toluene, ethylbenzene and xylene.

The company’s TEQUATIC PLUS fine particle filter is a new technology that can be used to help filter difficult-to-treat waters with high total suspended solids. The filter proved successful in applications such as produced water disposal wells by reducing the maintenance and consumables costs compared to traditional technologies such as cartridge and bag filters, the website stated.

Operators are finding opportunities by applying an integrated approach that uses advanced technologies for oil and gas. For example, BNN Energy helped an operator reduce water sourcing costs and environmental impact by integrating TEQUATIC PLUS Filters into its system. The operator has since increased the volume of recycled produced water to almost 100% and expects to save about $2/bbl of water, reducing operating costs by about 60% (results may vary depending on specific operating conditions), according to the website.

With its DOW FILMTEC reverse osmosis and nanofiltration elements, operators can manage shale gas-produced water. Another nanofiltration membrane is Dow’s FILMTEC SR90 Elements, which are designed to selectively remove sulfate from seawater used for waterflood injection operations in offshore oil production, helping prevent barium and strontium sulfate scale precipitation. This nanofiltration membrane operates efficiently at lower pressures and removes all particles greater than 0.001 μ, which results in injection water free of silica and bacteria, the website stated.

Evonik
Evonik develops advanced chemistries that enhance production, protect assets and increase value throughout the hydrocarbon life cycle.

PERACLEAN 15 from the Active Oxygens Division is an ecofriendly, Environmental Protection Agency-approved antimicrobial used to treat flowback and produced water. Unlike nonoxidizing biocides, it acts rapidly to destroy acid-producing and sulfate-reducing bacteria. It also can oxidize reduced sulfur species (e.g., sulfide). PERACLEAN 15 leaves no toxic residue, as the product decomposes to water, oxygen and CO2.

Evonik polyoxycarboxylates and DEGAPAS products are aqueous polymer solutions with excellent dispersing properties. These anionic polymers, free of nitrogen and phosphorous, interrupt inorganic crystal growth and are perfect antiscalants/dispersants. They are optimized to prevent scaling based on calcium, magnesium, iron or manganese salts.

VISIOMER methacrylate monomers provide excellent building blocks for high-molecular-weight cationic flocculants for water treatment. A new application area is extended-release scale inhibition.

The Technical Applications Product Line offers a comprehensive series of cationic and nonionic surfactants. The ADOGEN, TOMADOL and TOMAMINE lines include fatty amines, etheramines, amphoterics, alcohol ethoxylates and amine quaternaries. These products are ideal for emulsifying and stabilizing the components of oilfield formulations, such as drilling fluids, stimulation fluids and corrosion inhibitors.

Evonik signed an agreement in November 2018 to acquire PeroxyChem, which manufactures peracetic acid and hydrogen peroxide. The transaction is scheduled to be completed by mid-2019. For the oil and gas market, PeroxyChem offers hydraulic fracturing biocides and viscosity breakers, oil sands processing and EOR.

Evonik’s advanced chemistries enhance production, protect assets and increase value throughout the hydrocarbon life cycle. (Source: Evonik)

Evoqua Water Technologies
Evoqua Water Technologies offers water treatment solutions for both onshore and offshore oil and gas industry operations.

With more than 40 years of experience in delivering projects to the offshore market, Evoqua understands the strict regulations and requirements with which the industry needs to comply.

To protect the lifetime of equipment, “Chloropac systems can save oil producers over 5% of lost production by reducing biofouling of heating and cooling systems,” according to the company’s website. “These systems are used by 75% of leading operators to keep their field assets working efficiently.”

Evoqua is also the preferred provider for BOP fluid management systems to some of the largest offshore drillers in the industry, according to the company. Evoqua provides an Offshore Rig Water Solutions line of standard products for the management of critical fluids for its BOP systems.

Over the last five years, the company has deployed dozens of systems for continuous operation in the toughest environments, the website stated.

In addition to more than 100 years of experience in water treatment and purification, Evoqua has more than a decade of experience developing high-purity water treatment specifically for BOP applications, gaining a thorough understanding of the drilling rig environment as well as the industry’s rigorous standards and certification processes.

Fountain Quail Energy Services
Fountain Quail Energy Services seeks to help operators reduce water management costs by integrating the company’s industry expertise with exclusive treating and recycling systems.

The company’s water treating and recycling systems—SCOUT, ROVER, MAVREX and NOMAD—are technologies being used by operators in all shale plays, having assisted in cutting water-specific operating costs by at least 30% and up to 80%.

Fountain Quail’s highly mobile SCOUT system targets suspended solids, oil, iron and bacteria.

The ROVER technology targets the same contaminants as the SCOUT, but each ROVER system is semi-mobile and capable of recycling greater than 30,000 bbl/d to 105,000 bbl/d of clean brine, depending on location. Fountain Quail will customize a ROVER solution for long-term projects.

The MAVREX system utilizes variable feedback controlled chlorine dioxide technology and is effective across a broad range of bacteria and biofilms. Chlorine dioxide is less corrosive than bleach or ozone and has less of an impact on frac chemistry than peracetic acid.

The NOMAD technology employs the most energy-efficient thermal evaporator available in the market. The skid-mounted system made by Fountain Quail engineers is capable of generating 2,000 bbl/d of distilled, surface-discharge quality freshwater.

Fountain Quail owns, operates and is developing an expanding portfolio of Class II saltwater disposal wells that serve the Marcellus and Utica shale plays.

Fountain Quail’s MAG Tank is a modular, aboveground containment solution that provides operators with a flexible, customizable footprint, multiple capacities and a solution that significantly reduces truck traffic.

Fountain Quail designed the mobile SCOUT system for suspended solids, oil, iron and bacteria. (Source: Fountain Quail Energy Services)

Goodnight Midstream
By building, owning and operating produced water infrastructure in the prime oil shale fields in the U.S., Goodnight Midstream has a leading position in the Bakken Formation, a rapidly expanding footprint in the Permian Basin and Eagle Ford Shale, and an emerging presence in the Powder River Basin, according to the company.

According to a November 2018 press release, Goodnight Midstream announced it expanded its revolving credit facility to $420 million from $320 million to fund continued strategic growth initiatives in the Permian, Bakken and Eagle Ford shales as well as support working capital requirements.

In 2018 Goodnight Midstream completed and is now operating 15 new saltwater disposal (SWD) facilities across the basins in which it operates. The company expects to complete construction on five additional facilities in early 2019.

In the Permian Basin, Goodnight Midstream recently completed and is operating two high-pressure, trans-basin systems, the Llano and the Rattlesnake pipelines, serving several long-term contractual customers. This infrastructure will transport the increasing amount of water expected out of the Delaware Basin to the depleted fields of the Central Basin Platform.

For SWD, Goodnight Midstream is able to create tailored, long-term solutions for its  customers. The company now owns and manages a network of more than 45 gathering and disposal facilities connected to more than 420 miles of produced water pipelines on redundant systems, offering greater than 99% uptime for its customers, according to the company.

GR Energy Services
GR Energy Services offers operators technology-driven water management solutions using a unique horizontal pumping system (HPS) that drives gains for saltwater disposal, injection and water management. The versatile system provides advantages to inject or transfer at higher volumes and pressures and to reduce operating costs by eliminating common issues faced by water logistics managers.

The Flex Flow water management system integrates field-proven multistage centrifugal pumps with variable speed drives, surface controls and automated reporting capabilities to lower the total cost of operations. The trailer-mounted systems can be deployed very quickly as cost-effective options for early commissions, step-rate tests or replacement of equipment under repair.

The Flex Flow HPS can be monitored remotely to make adjustments that optimize system efficiency. Digital, cellular and satellite enabled, the programmable logic controller can report to mobile devices and computers with multiple notification options. The system requires little maintenance, so uptime is optimized and service callouts are kept to a minimum.

GR performance advisers can tailor both permanent and trailer-mounted Flex Flow HPS systems to a wide range of operating conditions with flow rates up to 100,000 bbl/d of fluid. Surface facilities engineers using Flex Flow systems have documented lower maintenance and repair costs, longer runlife and greater operating flexibility and efficiency, according to the company.

GR Energy Services’ Flex Flow HPS was designed for saltwater disposal, injection and water management. (Source: GR Energy Services)

Gradiant Energy Services
Gradiant Energy Services offers custom-engineered solutions and technologies for oil and gas operators seeking safe, reliable, economic, environmental and efficient treatment, reuse and recycling of flowback and produced water.

Gradiant’s Selective Chemical Extraction (SCE) is a mobile water treatment process that provides reusable clean brine as hydraulic fracturing fluid. By cleaning water only to the needed level—and not beyond—the SCE process enables the reuse of treated produced water for operations, according to the company’s website.

The company can transform the most difficult water makeup into the highest quality freshwater with its Carrier Gas Extraction (CGE) technology.

“Developed at the Massachusetts Institute of Technology [MIT], CGE desalinates oilfield wastewaters to produce extremely freshwater (less than 500 ppm and even lower in many cases) and a highly concentrated brine solution that can be utilized for drilling, workovers and completions,” the website noted. “CGE reduces the high transportation costs of produced water by treating the wastewater on site, producing freshwater and saturated brine.”

CGE also can be used to generate a concentrated, 10-lb brine that can be used for drilling, workover and completions applications.

Gradiant’s Free Radical Disinfection technology “provides high-volume disinfection treatment to control bacteria and treat water for storage pit maintenance, on-the-fly disinfection prior to hydraulic fracturing operations and pre-saltwater disposal injection” and also reduces H₂S in water, according to the website.

The company’s Carrier Gas Concentration (CGC) technology, developed at MIT, “is ideal for E&P operators in remote areas that have disposal constraints, high trucking and disposal costs or the need to enhance evaporation rates in ponds and pits,” the website stated. “The CGC process involves evaporating water and concentrating dissolved solids in the wastewater stream via a multistage bubble column humidifier.”

Gravity Oilfield Services
As increased drilling activity and high-intensity well completions drive the need for high volume water sourcing, transport and disposal, Gravity Oilfield Services provides infrastructure and logistical expertise to be the single-source supplier on which operators can rely.

With decades of expertise, deep resources, a large fleet of vehicles and high-performance equipment, Gravity has an expansive footprint in the major oil and gas producing basins, particularly in the Permian Basin. Its network of fluid logistics assets and infrastructure includes fresh and brackish water production and storage pits, long-life delivery, produced water gathering, freshwater sourcing pipelines, fluid hauling trucks and saltwater disposal (SWD) wells.

Gravity operates more than 125 miles of permanent pipeline infrastructure capable of managing water needs throughout the life cycle of a well along with an extensive fleet of fluid service trucks and containment solutions. There is also an extensive inventory of more than 5,000 fracturing and mud tanks for every fluid containment need.

The company has an extensive network of strategically located SWD wells in the Permian Basin and Williston Basin. Gravity has several water-sourcing agreements with operators in the Permian Basin and is taking additional commitments.

In June 2018, Gravity acquired McKenzie Energy Partners LLC. McKenzie provides contracted midstream-based water management solutions for some of the most active operators in the Bakken Shale play through a network of produced water gathering pipelines and water disposal wells situated on core acreage dedications, according to the acquisition press release.

Gravity Oilfield Services offers fresh and brackish water production, storage pits, produced water gathering, freshwater sourcing pipelines, fluid hauling trucks and SWD wells. (Source: Gravity Oilfield Services)

H₂O Midstream LLC
H₂O Midstream partners with producers, land owners and other stakeholders to improve the efficiency, reliability and safety of water operations while lowering costs across the value chain.

The company owns and operates the Permian’s only truck-free, third-party produced water hub and pipeline network consisting of 1 MMbbl of storage and 265,000 bbl/d of permitted disposal capacity from 13 disposal wells, all interconnected via 150 miles of pipeline.

In addition, the company has removed more than 350,000 truckloads per year of produced water from Texas roads.

H₂O Midstream owns and operates integrated water infrastructure, including gathering pipelines, storage, treatment, disposal and reuse facilities in the Permian Basin. The company continues to expand its existing system through additional infrastructure to serve the needs of multiple producers in the area.

H₂O Midstream was selected by the University Lands (UL) management group to handle water across its 167,000 acres in the Delaware Basin. UL manages the surface and mineral interests of 2.1 million acres of land across 19 counties in West Texas for the benefit of the Permanent University Fund.

In partnership with Layne Water Midstream, a new University Lands Water Management LLC (ULWM) was formed to service UL’s produced and source water needs in the Delaware Basin.

H₂O Midstream is funded via a private-equity commitment from EIV Capital and co-investments from several of EIV’s institutional partners collectively representing more than $70 billion in assets under management.

H2O Midstream owns and operates the Permian’s only truck-free, third-party produced water hub and pipeline network. (Source: H2O Midstream)

Halliburton
Halliburton has the processes, tools and expertise to responsibly and cost effectively address all water challenges. With more than 1,500 consultants and 5,000 chemists, engineers and scientists, the company provides the upstream E&P industry with expertise and analysis to assist in a variety of water management challenges from surface to subsurface, according to the company’s website.

Halliburton’s use of conformance processes often can improve an operator’s profitability as a result of the following benefits: longer productive well life; reduced lifting costs; reduced environmental concerns and costs; minimized treatment and disposal of water; and reduced well maintenance costs. Halliburton’s EquiSeal Conformance service was specially developed to shut off water production in horizontal or highly deviated wells.

Halliburton can help minimize the use of freshwater in the oil field during drilling and completion of a well, fracturing or thermal operations. For stimulation, Halliburton’s Excelerate friction reducer portfolio was designed to perform exceptionally in produced water, across a broad range of salinity. Additionally, the polymers within the friction reducer portfolio were built with rapid hydration for quick performance and structured so operators can pump less material for reduced residue compared to competitive offerings.

Halliburton’s Conformance chemical portfolio helps reduce unwanted fluid production to efficiently enhance hydrocarbon recovery. (Source: Halliburton)

Hillstone Environmental
Founded in 2015, Hillstone Environmental operates in the Permian Basin, Williston Basin and Marcellus/Utica Shale play providing comprehensive water infrastructure solutions. These services include designing, building, owning and operating water pipeline to disposal as well as providing water treatment, recycling and reuse. The company’s fully integrated water midstream solution allows it to “maximize operating efficiency, reduce costs and reduce environmental footprint,” the company stated on its website. The company’s systems include 24/7 SCADA monitoring and leak detection.

Hillstone’s water pipeline and disposal system in Loving County, Texas, has a total throughput capacity of 480,000 bbl/d across an interconnected network of pipelines and disposal wells, according to the company. Hillstone’s interconnected system in Loving County allows the company to gather, transfer and dispose of produced water across its entire system and manage through spikes or unplanned outages, which the company said “gives customers certainty that their produced water will be disposed of reliably, safely and without interruption.”

The company also has treated more than 100 MMbbl of water in the Permian and Marcellus/Utica. Hillstone’s coagulization process involves using mobile treatment units, each with up to 20,000 bbl/d of treatment capacity, and the process integrates into existing client operations and can be done concurrently with drillout and flowback.

Hillstone’s Cleveland saltwater disposal facility, which is interconnected via pipeline to its other disposal assets, is located in Loving County, Texas. (Photo by Tony Gutta, courtesy of Hillstone Environmental) 

Hydrozonix
To reduce risk and operating cost by optimizing water quality and use throughout the frac water cycle, Hydrozonix offers consulting, technology and services, and works with oil and gas companies to design and implement comprehensive, cost-effective water management programs.

The company’s end-to-end approach includes assessment to ongoing operations and maintenance.

Hydrozonix water treatment technology uses mobile and permanent systems that are ozone-based and require no liquid chemicals as well as portable aeration systems that maintain the quality of stored flowback and produced water.

The company provides “advanced technologies separately or as part of its HzO Trio program, which can replace conventional chemical programs and provide more effective control of bacteria, iron and sulfide at a much lower cost,” according to the company’s website. Hydrozonix has saved operators 60% to 90% over the cost of liquid oxidizers.

The HzO Trio includes HYDRO3CIDE, an automated oxidation system for produced and flowback water; a portable Hydro-Air Aeration System that aerates and mixes water in storage pits and tanks to maintain water quality; and On-The-Fly oxidation systems that disinfect water and remove iron and sulfides without chemicals that can be incompatible with frac fluids.

“Operators that recycle with the HzO Trio combination achieved higher water quality for a fraction of the cost of chemical programs,” the company stated on its website. The HYDRO3CIDE platform includes a dashboard that monitors systems performance and water quality in real time on a PC or cellphone. 

This year Hydrozonix is rolling out HYDROFLARE, a flare-gas fired evaporator, and HYDROPOD, a buoy that measures water quality in pits and tanks and sends data via cellular signal for real-time capture. “Together our systems provide a comprehensive program for low-cost produced water management from recycling to disposal,” the company said.

HYDRO3CIDE is the Hydrozonix automated oxidation system for produced and flowback water that includes a dashboard that monitors systems performance and water quality in real time on a PC or cellphone. (Source: Hydrozonix)

Keane Group
Since every system begins with the base water to be used on the job being tested, Keane Group offers recommended custom solutions that are cost-effective for the customer in terms of operations
and production.

The company’s ReLease ReUse produced water fluid systems are effective in all produced water scenarios, including 100% produced or flowback water. Where the cost of freshwater has an economical limitation, ReLease ReUse enables operators to continue operations with reduced cost and logistics associated with treating produced or flowback water, according to the company’s website.

Keane has systems for slickwater, linear gel and both borate- and zirconium-crosslinked gels, which allow operators to run produced water at any hardness, pH, mineralogy, temperature or salinity level.

Additionally, ReLease Speed is a full line of slickwater systems with friction reducers, which are economically customized for stimulation using either cationic or anionic freshwater solution. Options for high-brine applications also are available, the website stated.

The company also offers ReLease Dry, which is a dry friction reducer alternative that reduces spill risk.

Keane’s ReLease Linear fluid systems are natural or modified natural polymers used without crosslinkers that provide an economic fluid option without compromising viscosity characteristics. Polymers used include guar, carboxymethyl cellulose or cellulose gum, and carboxymethyl hydroxy propyl guar.

In the SPE-172811-MS paper’s abstract, Keane discussed its Stabilized Crosslinked Fracturing fluid systems, which were pumped in the Permian Basin, using borated produced water with levels of total dissolved solids exceeding 30,000 mg/l. The systems are designed to delay the crosslinking time when needed, utilizing the boron already present in the water. This frac fluid system approach has broken the code for recycled water and reduced disposal costs, according to the company’s website.

Key Energy Services
Saltwater disposal wells allow Key Energy Services to handle produced fluids responsibly and efficiently. Key operates more than 60 Class II disposal injection wells, where produced water is run through settling tanks prior to injection, according to the company’s website.

Key’s fluid management services include transportation of fluids used in the drilling and completion process as well as frac flowback and produced water from completed or producing wellbores.

For managing fluid levels within its tank systems, the company equipped its disposal wells with a computer-controlled system for receiving produced water. The facilities are designed to treat and filter water efficiently, therefore injecting the cleanest possible water into disposal wells.

Its 50-plus wells are permitted for a combined 15 MMbbl per month. The company has four permitted fresh and brine water facilities throughout the Permian Basin, each providing more than 1,500 bbl/d, the website noted.

“Significant growth in water volume per completed well is driving total freshwater and flowback water demand. Continued growth in water volumes employed on a per-well basis drive water transfer demand,” said Robert Drummond, Key president and CEO, in a March 2018 presentation.

Key’s energy production solutions and services are provided through its experienced crews, technical expertise, data analytics and fit-for-purpose equipment, according to the company’s website.

The company’s vacuum trucks transport nonhazardous fluid or waste to or from well operations. The materials commonly carried include freshwater, field saltwater, 10-lb brines, calcium chloride/bromide, water and oil-based muds and other drilling fluids. 

Layne Water Midstream

As a full-cycle water midstream business, Layne Water Midstream (LWM) provides upstream oil and gas companies with water sourcing, disposal and recycling services in the Delaware and Midland basins.

LWM was founded as part of Layne Christensen Co., a 135-year-old global water management company. Today LWM operates a growing produced water management and disposal business in the Delaware Basin with existing pipelines, disposal assets and numerous in-process saltwater disposal (SWD) permits that are soon expected to provide more than 400,000 bbl/d of transportation and disposal capacity.

The company also operates an extensive source water business in the Delaware Basin with its 26-mile, 175,000-bbl/d Hermosa pipeline and access to source water in more than 90,000 acres in Reeves and Culberson counties in Texas, either owned by LWM or under long-term, exclusive lease arrangements.

LWM also operates water infrastructure assets in the Midland Basin, including more than 100,000-bbl/d source water assets in Martin County, Texas, and existing SWD permits.

The company’s business includes contracts with landowners for water midstream services on nearly 300,000 acres in the Permian Basin, including an exclusive long-term contract with the Texas General Land Office (covering 88,000 acres in Reeves and Culberson counties) and a preferred water services provider contract with University Lands (covering more than 160,000 acres in Ward, Winkler and Loving counties).

MYCELX Technologies Corp.
MYCELX Technologies Corp. provides advanced solutions for produced, process and wastewater challenges primarily in the oil and gas sector. The company’s polymer has oleophilic and hydrophobic characteristics and is designed to meet the industry’s toughest water treatment requirements.

MYCELX permanently binds with oil and hydrocarbons through the process of molecular cohesion. The company’s engineered solutions offer superior hydrocarbon removal with a smaller footprint and a lower cost to treat. 

As environmental regulations and operational challenges increase across the globe, the need for MYCELX’s water treatment expertise has been recognized by a growing group of industry leaders including Chevron, BP, Anadarko, Schlumberger, SABIC and SNF Floerger, according to the company.

The company will consistently deliver water to specifications chosen by the client and can ensure discharge of less than 1 ppm oil in water if required. The produced water can be safely discharged and meets regulatory standards set by the U.S. Environmental Protection Agency, U.S. Coast Guard, Saudi Arabian Royal Commission Environmental Regulations and Nigerian Department of Petroleum Resources.

The company has designed standardized equipment for its patented media and can undertake primary, secondary and tertiary stages of water treatment for customers. By combining these coalescers, backwashable media vessels and polishers, MYCELX is able to create robust tailored solutions. Systems can handle variable flow rates from 25 gpm to 5,000 gpm.

A single MYCELX system can easily handle high flow rates of up to 120,000 bbl/d, and given its smaller footprint, it is possible to scale up easily to meet whatever flow is required. The flexibility of the company’s engineered systems make them ideal for a wide range of applications and deployments, particularly offshore drilling platforms. 

MYCELX RE-GEN, which is the company’s backwashable media, offers the necessary step-change improvement in water treatment capability that is critical for companies focused on EOR and are hampered by conventional water treatment technology’s limitations.

Oilfield Water Logistics
In the midstream water infrastructure and services industry, Oilfield Water Logistics LLC (OWL) has a focus on pipeline gathering systems, produced water disposal and produced water reuse services.

OWL primarily operates in the Permian Basin, including both the Midland and Delaware basins.

The company has additional assets in the Rockies region, including the Powder River Basin, Wamsutter and Piceance, as well as in East Texas. 

OWL owns and operates the largest produced water gathering system in the northern Delaware Basin and Lea County, N.M. OWL recently completed its Red Hills Water Gathering System pipeline expansion project, which extended its Lea County system into Loving County, Texas. The connection provides access to upward of four additional saltwater disposal wells and numerous new customer connections.

In the Rockies, OWL recently expanded its Thunder Basin facility in Converse County, Wyo., to meet the increasing water management demand in the Powder River Basin.

OWL’s extensive midstream water infrastructure networks offer E&P companies the opportunity to reduce water sourcing and disposal capex while providing redundant systems to effectively handle the industry’s growing water needs, according to the company’s website.

By building supply and gathering lines, as well as reuse infrastructure where appropriate, OWL’s customers are able to maximize efficiency and minimize water management costs.

OSP
OSP, a service and supply company, works with the global oil and gas industry to create solutions for the effects of water and its use. For water treatment, OSP provides microbial testing technology as well as oilfield chemicals, including microbial and scale inhibition products, and water-focused consulting services.

OSP’s 2K7 Bugstick is a solid stick biocide that enables delivery to inaccessible areas where microbes can proliferate, the company said. The company’s biocide is available in several formats and formulations depending on the application.

In 2011 the acquisition of Telomer Corp. expanded OSP’s oilfield chemical products to include scale inhibition, providing chemistries and finished formulations that effectively target scale issues.

In 2017 OSP expanded its service offerings to include microbial identification and evaluation, offering molecular testing, including DNA qPCR and 16S sequencing. “Understanding you can’t mitigate what you can’t measure,” OSP provides the technical services and technology, on site or in the laboratory, to target and test for microbial contamination to achieve microbial control, the company stated on its website. OSP targets, tests and treats microbial-related issues such as corrosion and souring.

Pentair
To provide petroleum producers, refiners and gas processors dramatically improved solids control and hydrocarbon recovery from process water streams, Pentair offers its hydrocarbon recovery technology (HRT) for produced water management, oil removal from wastewater and saltwater disposal.

HRT eliminates the need for expensive excess processing, chemical additives and storage tank capacity. Hydrocarbon recovery efficiencies of 99.98% are available through HRT, according to the company’s website. HRT’s design is scalable and modular for both new capital projects as well as placement in existing operating units.

Benefits to using HRT on process water systems include operational flexibility, reduction of lost energy, savings on chemical additives, lower maintenance costs associated with fouling, and elimination of excursions, the website noted.

Pentair recognizes that produced and flowback water streams must often be treated prior to disposal, reinjection or reuse, and that the capital and operating costs associated with most treatment systems can be very high.

The company provides high-performance filtration and separation systems for produced and flowback water streams that will lower operating and capital costs and add value. The company offers a broad array of secondary water treatment technologies that allow the reuse of produced-water streams for uses such as agricultural irrigation and boiler feed water, according to the website.

Pentair’s Pure Pack system is a portable solution for secondary and tertiary produced water and wastewater treatment, offers superior water quality with a smaller footprint and lower cost of ownership, the website stated. With oil content as high as 5% to 10% at the inlet, the Pure Pack can yield low ppm oil at the outlet. The high-quality recovered oil may be processed or sold to add value to the operator, the website noted.

ProSep
By providing solutions that meet or exceed regulatory and/or other operational requirements, such as reinjection and EOR, ProSep’s produced water treatment system helps operators manage and treat produced water streams. The company’s technologies include TORR, CTour Process and Osorb Media Systems.

The company’s produced water treatment portfolio includes primary, secondary and tertiary treatment options, which can be supplied as individual process units, integrated plug-and-play packages or as complete produced water treatment solutions.

ProSep’s Osorb Media Systems (OMS) utilize the next-generation adsorbent, Osorb Media, for efficient water treatment/polishing. Osorb Media is a regenerable, organically modified silica specifically designed to remove dispersed, dissolved and emulsified hydrocarbons from produced waters, according to the company’s website.

The simple, integrated OMS water treatment systems allow operators to remove benzene, toluene, ethylbenzene and xylene (BTEX); light to heavy crude oil; gas condensate; and some oilfield chemicals to less than 1 ppm. The systems maintain their efficiency in a broad range of applications, including the removal of hydrocarbons from CEOR polymer flood operations.

The TORR coalescing technology has a small footprint and the ability to replace less efficient oil removal equipment. It is a modular, scalable technology that addresses future increases in water cut for offshore operators. The process consists of two or more in-line pressure vessels and an optional spare vessel to be used as standby.

ProSep’s CTour process removes dispersed oil and dissolved hydrocarbon contaminants in the produced water stream through injection of condensate. The process routinely yields residual oil discharges of less than 5 ppm total petroleum hydrocarbons, while at the same time removing 80% to 95% of harmful water soluble organics, such as BTEX. The process is used extensively in Norway, having treated as much as 70% of all Norwegian offshore produced water. This equates to more than 2 MMbbl/d of water.

Purity Oilfield Services
With a complete line of water solution services, Purity Oilfield Services can coordinate setup and disposal as well as handle all other logistics for water service needs for completion services and other operations.

The company’s growing operational footprint includes the Permian Basin as well as South Texas, the Rocky Mountain regions and Canada.

With its diversified portfolio of rental items, trucking services, water services and strategic distribution alliances, Purity offers the flexibility of daily rentals to turnkey package solutions. The company provides services for drilling, completion, production and midstream operations.

Purity has five core divisions: the Water Transfer Division with 10-in. and 12-in. layflat pipe with the associated pumps and equipment; the Blue Line Division, offering a variety of tanks and aboveground storage tanks for water storage, consisting of 20,000-bbl, 40,000-bbl and 60,000-bbl ponds, frac tanks, uprights, bins, open tops and more; the Trucking Division, which consists of trucks capable of transporting freshwater and brine water and supporting the move of oilfield equipment and other oilfield trucking needs; the OFT Well Testing Division, which offers a fleet of well-testing units and services for flowback and well testing services; and the recently added Pure Heat Division that offers a new method to heat water at the well site or transfer source for completion services.

Purity’s freshwater services can be provided with turnkey pricing on services and rentals on a single well site or an entire field. The programs allow the operator to control expenses by knowing the project costs upfront.

Purity Oilfield Services coordinates and handles all logistics for water service needs for completion services and other operations. (Source: Purity Oilfield Services)

Reclaim Water Services
Reclaim Water Services’ solution nonchemically removes contaminates from the water. Reclaim will provide nondetectable levels of hydrocarbons and bacteria and iron less than 1 ppm. Other solutions use dangerous chemicals to change the water chemistry and leave the contaminates in the water. This requires contaminant cleanup somewhere down the road. The treated water can be reused as soon as the system is discharged.

The system offers the following advantages: no retaining/settling ponds required, cleans water more completely than other processes, water is ready to use within 8 hours of entering the system, remote operation offers greater safety with less manpower, costs are competitive with all other processes, and units handle from 3,000 to 40,000 bbl/d and can be combined for larger volumes, according to the company.

Units are designed for volumes from 3,000 to 40,000 bbl/d and can be combined to meet higher demand. (Source: Reclaim Water Services)

Samco Technologies Inc.
For onshore and offshore applications, Samco Technologies Inc.’s oil and gas solutions include a cooling tower water treatment, boiler feed water treatment, wastewater treatment and zero liquid discharge.

Based on its technologies, Samco’s customers “have experienced increased oil recovery, cost-effective injection-water treatment, superior separation and destruction of acid/sour gas, expanded plant productivity, increased process uptime, cost-effective waste reduction and industry-compliant discharge,” according to the company’s website.

In addition to treating produced water for washing crude oil, Samco has developed a seawater desalting solution that performs directly on the platform, using a filtration process that then uses membranes to separate sulfates from the water, the website noted.

To effectively wash the light crude, the seawater is filtered to remove suspended solids and sulfates. It then uses its two-step process for oxygen removal. Samco’s two-step oxygen removal process is a method of removing oxygen from water down to extremely low levels. This method can be particularly useful in offshore EOR, the website stated.

When performing EOR offshore, a lot of water can be brought up with the oil. Samco developed a procedure to remove the water from the oil, recover the oil and safely discharge the water back into the ocean from onboard the platform or recycle it for reinjection.

Schlumberger
Schlumberger offers various services for managing the complete cycle of water management. The company’s experts have a thorough understanding of stimulation fluid requirements, operational schemes, reservoir characteristics, production volumes, hydrogeology, engineering design and environmental considerations.

Schlumberger’s AllSeal water and gas conformance service controls or shuts off unwanted water or gas production with an engineering approach. Schlumberger’s FracCON water-conformance fracturing fluid within the AllSeal water and gas conformance service was developed for high-water-cut wells with recoverable reserves near oil-to-water contact or gas-to-water contact. It features a relative permeability modifier capable of producing enhanced fracture geometry and increased proppant pack conductivity while mitigating water cut after fracture stimulation treatments, according to the company.

In addition, the company’s xWATER integrated water-flexible fracturing fluid delivery service is designed to reduce or eliminate freshwater use and its associated transportation and disposal costs, while also decreasing environmental impact, according to the company. “The service enables operators to use an engineered fracturing fluid customized for the available water, well conditions and reservoir properties—saving on the water-related costs that can account for up to 25% of the total operation cost,” the company stated on its website.

The Schlumberger AllSeal service integrates chemistry, geology, operations, economics and logistics to reduce or eliminate water and gas production for a particular well or field. (Source: Schlumberger)

Select Energy Services Inc.
Select Energy Services Inc. provides oilfield water management services, including water sourcing, water transfer, containment, water treatment, flowback and well testing, fluids handling, and disposal across all major U.S. unconventional basins. Select’s water sourcing services identify, acquire and permit source water to assist operators with water acquisition, storage, evaluation and regulatory handling. The company has about 1.5 Bbbl of water available for operator use in hydraulic fracturing.

Select’s water transfer services are provided through a variety of mobile hose, piping and automated pumping systems to support hydraulic fracturing. The company’s water transfer services include pipe and pump selection, frac support, filtration and flowback support.

AquaView is a suite of technologies developed by Select to remotely monitor and control water assets and provide real-time data, including volume and water quality, all accessible 24/7 through the Aqua- View computer, smartphone and tablet applications. AquaView automated pumps and proportioning systems respond to operator specifications and changing conditions in real time with the ability to remotely set and maintain operational parameters.

For containment, Select offers high-volume aboveground storage tanks, reusable secondary containment systems, tank pedestals, in-ground and surface mount wall steel containments, heating and liners.

Select’s water treatment services utilize a wide spectrum of bio-control, aeration and recycling technologies to prepare source water or tie flowback and produced water back into frac supply for reuse. Additionally, Select has permitted disposal facilities located in the major U.S. shale plays with a permitted capacity of more than 300,000 bbl/d.

Through its Rockwater Energy Solutions brand, the company manufactures and supplies oilfield chemicals to optimize fluids during completion and production. Tidal Logistics is the in-house fluids handling service line that provides fluid recovery and removal, production support and storage.

Select’s Aquaview system includes automated pumps that give remote and timely visibility to water supplies as well as the ability to self-adjust transfer rates to match other equipment in the system. (Source: Select Energy Services)

SitePro
SitePro, a digital oilfield solutions provider, develops real-time, cloud-based software designed to optimize the management of the full water life cycle. The company offers services for producers, disposal and recycling, water midstream, and water sourcing.

For water sourcing, SitePro offers an alternative to manually checking pond levels, turning on water  wells, turning valves and allocating volumes with its remote-control technology, turnkey automation and custom software interface.

SitePro’s new Water Sales Monitoring technology allows users to monitor frac ponds, storage pits and transfer lines in real time and control pumps and valves remotely from a computer or mobile device.

“Our volume allocation and ticketing services complete the life-cycle solution for service companies looking to lower their operating costs and reduce downtime,” the company said on its website.

The volume allocation feature allows users to easily differentiate water volumes from various operators, storage pits and truck sales for accurate and efficient billing and tracking. The technology also allows users to remotely control water wells from their phone or desktop, turning valves on or off based on level or volume set points. 

For disposal and recycling, SitePro offers services for saltwater disposal (SWD) wells that provide total asset management, merging remote control, monitoring and automation with electronic ticketing and invoicing. The company helps operators partially or completely eliminate the need for field personnel. SitePro’s turnkey automation and software products cover every aspect of an SWD facility or system of facilities, including electronic ticketing, access control and flow measurement, surveillance, tank level monitoring, fluid conditioning, pipeline volume allocation, wellhead monitoring, cloud-based reports and regulatory reporting, and advanced analytics.

With SitePro’s Water Sales Monitoring technology, ponds and storage pits can be viewed and controlled remotely, and the remote control technology eliminates the need to dispatch personnel for pump or valve control. (Source: SitePro)

Solaris Water Midstream
Solaris Water Midstream owns, operates and designs water infrastructure assets with a current focus in the Permian Basin. The independent company’s services include produced and flowback water gathering and transportation, wastewater reuse and disposal, water sourcing and delivery, and pipeline design and operation. 

The company’s currently operating water infrastructure systems are located in the Delaware and Midland basins. Solaris’s Pecos Star System in the Delaware Basin has more than 200 miles of active and under construction permanent pipelines transporting produced water and supplying recycled and brackish water for oil and gas operations. The Pecos Star System’s pipeline network is connected to numerous active and under construction disposal wells. Solaris is currently permitting additional wells and pipelines. By the end of the year, the system will have more than 400 miles of large diameter produced water and water supply pipelines and connections to dozens of owned and third party disposal and recycling facilities across Texas and New Mexico. Additional systems are under development in the Delaware Basin, which will have similar service offerings as the Pecos Star System.

Solaris Water’s Midland Basin systems include about 85 miles of pipelines, two recycling facilities capable of recycling 25,000 bbl/d each and connections to 11 disposal wells.

Solaris’ DJK saltwater disposal well is located in Midland County, Texas. The site also serves as an integrated reuse facility. (Source: Solaris Water Midstream)

Sourcewater Inc.
Sourcewater is a geospatial water intelligence platform and water marketplace for the upstream  energy industry. Sourcewater gathers oilfield business activity data from its online water marketplace, which has more than 5,000 water and saltwater disposal capacity listings in the Permian Basin. The company gathers these data from satellite imagery computer vision analytics, which detect and measure every frac water impoundment and well pad in the Permian Basin every five days, matching each feature to surface and mineral ownership and operator lease.

The company also gathers data from state government regulatory filings for oil, gas, water and disposal wells as well as treatment facilities; parcel and mineral ownership records and leases; continuous market research; and Internet of Things and SCADA sensor partnerships to obtain real-time water and disposal levels, flows and pressures from the field. Data are gathered, cleaned, normalized, structured, analyzed and visualized through advanced geospatial mapping tools, custom research reports and an API for larger users.

Sourcewater recently acquired the assets and intellectual property of Digital H₂O, enabling Sourcewater to gather and show the oil, gas and water production of every oil and gas well in Texas, New Mexico, North Dakota and Pennsylvania as well as show disposal well capacity, pressures and utilization for all of these states. In Texas Sourcewater shows the logistical relationships and flows between every commercial disposal and every operator lease.

Sourcewater’s Water Asset Intelligence platform shows the monthly capacity utilization of every disposal and injection well in Texas, New Mexico, North Dakota and Pennsylvania going back to 2013. It also shows the hydrocarbon and water production of every producing lease and maps exactly where each lease sends its produced water for injection and disposal. (Source: Sourcewater)

TETRA Technologies Inc.
TETRA Technologies’ water management services for hydraulic fracturing and unconventional well completions include sourcing, fresh and produced water transfer, pipeline construction, storage and pit lining, treatment and recycling, blending and distribution, and flowback and testing, all of which are automated and remotely monitored.

The company’s water treatment services are “fully automated and integrated to help meet operators’ increasing water requirements by recycling, treating and delivering an optimized fluid for frac operations—all while yielding significant cost savings and reducing operational and HSE risks,” according to the company’s website.

TETRA uses an oil separation system to accumulate and remove residual oil from produced water in real time to ensure treatment performance and compliance with regulatory storage requirements. The accumulated oil can then be put back into the operator’s sale pipeline. In several cases, the volume of reclaimed oil has almost paid for the use of the system.

The company uses an automated water treatment system to chemically treat produced water through a clarification process that enables recycling of up to 50,000 bbl/d of produced water with a single system. Custom systems are built to handle larger volumes. The system uses web-based, real-time monitoring and control technology providing operators with 24/7 access to treatment and recycling operations. This provides a transparent and on-demand view on the chemistry applied to treat the water and its effectiveness. 

TETRA also offers automated blending and distribution technology that provides accurate parameter-based blending and consistent blend quality, whether directly filling frac tanks or transferring to another location. The technology is equipped with real-time, computer controlled, tank-level management ensuring supply and preventing tank overflows.

The company’s storage and U.S. Environmental Protection Agency-compliant pit lining services ensure drilling and completion operations have a sufficient water supply on site and on demand.

This illustration shows TETRA Technologies’ fully automated and integrated water management solution that includes sourcing, fresh and produced water transfer, pipeline construction, storage and pit lining, treatment and recycling, blending and distribution, and flowback and testing for hydraulic fracturing and unconventional well completions. (Source: TETRA Technologies)

Veolia Water Technologies
Veolia provides water treatment, reuse and wastewater services and technologies. Its water treatment technologies include more than 350 solutions to manage, optimize and recover water and wastewater for municipal and commercial systems. The company’s focus is on increasing and extending the value of water and wastewater resources.

ShaleFlow is a transportable, modular system that utilizes proven technologies to treat up to 10,000 bbl/d (300 gpm) of produced water with a simple drop-and-go approach.

The company’s CoLD crystallization process for desalination of produced water is designed to eliminate the need for expensive pretreatment of the produced water, thereby reducing capital and operating costs, according to the Veolia.

In addition, Aquavista is the company’s new digital services platform that offers a wide range of customized digital solutions for water treatment systems.

ShaleFlow is a mobile solution for produced water reuse. It is a transportable, modular solution that utilizes proven technologies to treat up to 10,000 bbl/d (300 gpm) of produced water with a simple drop-and-go approach. (Source: Veolia)

WaterBridge Resources LLC
WaterBridge Resources LLC, a portfolio company of Five Point Energy LLC, provides producer-focused water management solutions through integrated pipeline networks for produced water, transportation, disposal, supply and recycling. 

WaterBridge owns and operates more than 1.3 MMbbl/d of produced water disposal capacity throughout the Southern Delaware Basin and Arkoma Basin that are connected by more than 450 miles of pipeline.

WaterBridge recently acquired assets from and entered into a long-term produced water management contracts with Concho Resources Inc. and Halcón Resources Corp., both in the Southern Delaware basin. Including these transactions, WaterBridge has approximately 285,000 dedicated acres under long-term contracts with 19 producers in the Delaware Basin and approximately 182,000 dedicated acres under long-term contracts with three producers in the Arkoma Basin.

A WaterBridge produced water handling facility is located the Southern Delaware Basin. (Source: WaterBridge Resources LLC) 

Water Standard/Monarch Separators
Water Standard builds and delivers water treatment solutions and services to the global energy industry. The company specializes in compact modular membrane and ultrapure water systems and mobile onshore and offshore facilities. They offer flexible contract options for products and services ranging from specialized engineering and design to the supply of turnkey and rental systems.

Water Standard’s subsidiary, Monarch Separators, designs, engineers and manufactures separation technologies for removal of oil and solids from produced water and wastewater in the energy industry.

Together, the companies provide products and services that allow energy companies to safely and responsibly reuse their water as an asset and/or discharge it back into the water cycle. For example, their H₂O Spectrum platform technology provides operators with a wide spectrum of produced and flowback water treatment options, including disposal, recycle and reuse, and treatment for safe surface discharge.

The companies’ combined expertise in water treatment applications include waterflooding, IOR and EOR; produced and flowback water treatment; desalination, sulphate removal and/or softening; membrane deaeration; filtration; ultrapure water; mobile units; and fixed facilities. Additionally, the company’s water treatment technologies for discharge or disposal are designed to improve oil and water separation, treat EOR emulsions and minimize footprint and storage requirements.

Monarch Separators designs, engineers and manufactures separation technologies for removal of oil and solids from produced water and wastewater in the energy industry. (Source: Water Standard/Monarch Separators)

[ceo_energemsier + 1,818]

More breakthroughs for good oil production and resource conservation and management, but to tech deniers , nothing matters or nothing will matter!!!!

___________________

 

Technology Reduces Produced Water By 50%

Proppant-bonded technology reduces formation water without hindering oil and gas production.

Produced or formation water is by far the largest byproduct of the oil and gas industry. Estimates show that for every barrel of oil recovered, 4 bbl to 10 bbl of formation water also are produced.

Formation water often contains salts, bacteria, organic chemicals and other contaminants. This can make the handling of formation water problematic. Most formation water is disposed of by injecting it into subterranean wastewater disposal wells; however, the added cost of hauling the water can severely impact well economics. Some companies treat the water for reuse in hydraulic fracturing or agriculture. Likewise, water treatment for reuse is not always an economical option.

The storage, transport, treatment and disposal of wastewater accounts for 89% of water management costs. The U.S. upstream industry was estimated to spend $34.7 billion on water management in 2018. Over the life of an individual well, produced water costs can total as much as $6 million. This represents nearly half of a well’s operating expenses, and these costs are predicted to increase.

Restrictions
Many states in the northeastern U.S. have tight restrictions on wastewater disposal, prompting higher associated transportation costs to neighboring, less-restrictive states for production water disposal. In Oklahoma additional restrictions have been placed on disposal wells due to water reinjection and seismic activity correlation. These restrictions limit the rate at which water can be reinjected and, consequently, increase costs associated with water management.

While efforts to manage fracturing flowback and produced water continue, little attention has been focused on limiting water production by addressing the issue downhole. Current technologies, such as gels or swelling chemicals, can limit formation water production, but they also restrict hydrocarbon flow. 

Hexion developed the AquaBond formation water reduction technology, which has reduced produced water by as much as 50% without hindering oil and gas production. The technology is bonded to the proppant, making its water-reduction properties effective for the life of the well. With the application of this technology, the costs associated with wastewater management can be reduced, leading to a lower cost per barrel of oil equivalent.

How it works
This advanced technology alters the relative permeability of the proppant pack to admit hydrocarbons and reduce the admission of water. Proppant coating functional group modification results in a tailored critical surface tension that is hydrophobic as well as oleophilic. This creates an impelling force that admits oil while restricting water flow through the proppant pack.

A test apparatus was developed by Hexion to demonstrate the technology’s preference for flowing hydrocarbon over water. The testing device consists of a bonded proppant core, attached to a tight-fitting rubber cap, encased in a reservoir cell. The rubber cap is affixed to a tube that extends from the reservoir cell and empties into a graduated cylinder. The reservoir cell is filled with oil and water, submerging the core. A vacuum pump pulls the fluid from the reservoir cell through the proppant core. The fluid is collected in the graduated cylinder, and the water-oil ratio (WOR) that has moved through the core is documented.

The AquaBond technology proppant core was tested against a control sample of traditional resin-coated proppant. The reservoir cell was filled with a 2-to-1 WOR, submerging the core. Testing indicated the AquaBond technology core admitted less than 5% water without hindering hydrocarbon flow, and the control proppant core admitted approximately 60% water and less overall oil. Testing was repeated using various crude oil and formation water samples to account for North American regional differences in oil/water composition. Similar results were noted in corresponding tests.

The proppant pack is a porous medium, allowing water to flow through the pack when oil is not present. This prevents water blockage in the pack or at the formation surface/proppant pack interface. A 5-to-1 WOR was added to the test apparatus to demonstrate this. Only water was in contact with the proppant pack at the onset of the test. Once the test began, water flowed through the core until oil made contact with the core. Upon contact, oil preferentially flowed, leaving remaining water behind in the reservoir cell. When tested, traditional resin-coated proppant continued to flow water after oil contacted the proppant core, resulting in most of the oil being left behind in the reservoir cell.

Case study
A trial was conducted in the Granite Wash Formation in the Texas Panhandle to prove the effectiveness of AquaBond technology in the field. A 23% tail-in of AquaBond technology on 40/70 substrate was utilized on two horizontal wells. These wells were compared with 11 nearby offset horizontal wells. Three of the offset wells used a 23% tail-in of 40/70 traditional resin-coated proppant, and eight wells used 100% uncoated frac sand.

Each well had a true vertical depth of about 11,000 ft, with a lateral length of 4,000 ft, bottomhole static temperature of 180 F, and a total proppant volume of approximately 2.3 MMlb per well. 

Traditional proppant and the uncoated frac sand offsets performed similarly over the trial period.  Comparatively, AquaBond technology wells had a 30% lower water cut and a 43% reduction in average cumulative water production, with no observed impact to total fluid production.

The chart depicts the average water cut for AquaBond technology wells and offsets in the Granite Wash Formation. (Source: Hexion)

Using the technology
Lead-ins, tail-ins or total proppant designs can be utilized, depending on formation characteristics, desired water reduction and water issue severity. The technology also can be used as a remedial treatment for existing high-water-cut wells.

The technology can be pumped downhole using the same method as traditional proppant. Frac water returns to the surface per typical flowback procedure. Hydrocarbons and formation water then come in contact with the proppant pack. The technology preferentially flows hydrocarbons over water, and more hydrocarbons (and less water) are produced to the surface.

This has been demonstrated in laboratory tests using an array of samples in varying WORs from numerous regions throughout North America. The Granite Wash case study demonstrates how this technology can reduce the production of formation water without impacting total fluid production. The technology has been further proven in the Permian Basin, Bakken Shale and Haynesville Shale.