Monthly Archives: September 2014

EPA NSPS OOOO: Are VRUs and VRTs the answer? (Part 2 of 2)

Picking up from our last installment, you should now know that when it comes to our VOC emissions, “what gets measured gets managed”. Essentially, you should understand the importance of (1) how to measure your VOCs, (2) whether you fall under QuadO rules, and (3) what to do about it (if anything!) so that you can rest easy at night.

If you missed that post or just want a refresher, you can check it out by clicking here.

Are VRUs the answer?

The short answer: “Possibly”.

Basically, the Vapor Recovery Unit takes non-product output (hydrocarbons that aren’t making you any money) off the top of your storage tanks, collects the gas, compresses it, then pushes it back to the sales line.

In the past, the oil & gas industry considered type of revenue stream as “non-core function” — essentially, oil companies were oil companies, and they didn’t really care about the associated gas. Gas companies made gas, they didn’t care about the condensate. But, that’s quickly changing…

And, even though operators must keep an ever more watchful eye on the compliance of their facilities, there is still only one criteria you need to determine when contemplating to install a VRU. The simple question you must ask yourself is: “will it make me money?”

If installing a VRU doesn’t pay out, don’t install it. If it does, go for it. Just make sure you let the numbers make the decision for you.

But what you must understand, a VRU is not a control. It’s classified as a piece of “process equipment” (which basically means it’s not in the rule books). Basically, when we install a VRU system and collect these emissions, any emissions returned back to the sales line won’t count toward our annual total allowed by the EPA.

The Savvy Operator understands the benefit of returning emissions back to the salesline are threefold. First, you’ll be able to profit from these emissions. Second, you’ll be 100% in compliance with QuadO. And third, by “selling your emissions”, VRUs will drop your tanks below the 6 tonne threshold allowing you to drop out of the EPA system altogether. All in all a pretty sweet deal.

Over the past several years, VRUs have received quite a bad rap. A lot of people have gotten burned because they simply didn’t work (facilities with rich gas and liquids will cause VRUs not to work…) Even most VRU dealers will tell you it’s probably one of the most complicated pieces of equipment on site.

Understand, VRU systems are ‘closed systems’. They’re set to kick on under specific pressures in the tank or when they sense gas. Oklahoma & Texas both classify VRU systems as only 95% efficient.

Why do they fall short of a 100% solution? The reason OK & TX state that the VRUs are only 95% efficient is because the VRU will probably fall offline sometime during the year, and the States want to know what you’re doing with your gas when the unit is down…

That being said, if you can prove you’re sending that gas somewhere else (ex: a combust or or some sort of redundant system), you can make that VRU 100% compliant.

The cool thing here is that the ‘burden of proof’ isn’t on the State — the Feds won’t tell you how to run your leases. The ‘burden of proof’ that you’re capturing everything is on you. Prove it to them, and use it to your advantage.

First rule of thumb for VRUs: don’t. go. cheap. There are different VRUs that serve different purposes. And, inexperienced installers will get you into trouble by not sloping lines correctly and accidentally trapping liquids which will cause your VRU to go offline.

What happens when that (p.o.s.) VRU goes down? You fall out of compliance, and you open yourself to being fined… exactly the sort of stuff we’re trying to avoid by installing a VRU in the first place!

The story generally goes like this: independent receives proposal for a $30K VRU unit. Instead, they go low-bid and spring for the $20K system. Eventually, the VRU shuts down, and the independent operator now finds itself out of compliance. What’s worse, the $10K that was saved could cost the company $100K+ in fines…

Basically, don’t buy cheap — that means no compressors from Home Depot. Get an expert. Better yet, get someone to train your field guys on the proper maintenance of the unit. Also, be damned sure they offer ongoing support (why? because you need someone who has replacement parts that can get out there and fix it in 24 hours… you can’t be offline any longer, it’s gotta be up and running…)

We realize this sounds like a lot of work, but a properly installed VRU can pay for itself in a very short amount of time.

Also, large operators take note, too: refinery spec VRUs are overkill. Many times, large independents will spend $250K on a unit when a $30K unit would put them exactly where they need to be. Standardized systems are all that’s required (from what we’ve put together, we’re recommending no custom VRUs, and no one-offs…)

Enter: The VR Tower

Developed by Anadarko in the 1990s in the Giddings Austin Chalk Field, the VR tower netted Anadarko $7-8MM per year from 1993 to 1999 in gas sales and eliminated 99% of their headaches caused by compliance.

The VR tower is a new twist on an old industry standard: basically, it’s a glorified gun barrel. The VR tower is an atmospheric flash vessel, generally about 30 ft tall, 36 inches in diameter, with a capital cost of about $30,000. Now remember, 90% of our gas breaks out during flash. From your heater treater or low pressure separator, you bring in your crude, it splashes — boom! (kinetic energy) — and you get your flash.

VRT VRU.JPG

However, in a VR tower, not only does crude drop 30 feet (that’s some serious flash!), but you also have a 10 ft of vapor headspace. There is a liquid seal — this means there’s no way to ever get oxygen to your sales line. All the gas and live oil is turned to dead oil, and your stock turns to dead stock.

What’s more, is that when you open that lid to take a gauge measurement, you don’t get that ‘whoosh!’ of gas anymore — it’s all been broken out in the VRU tower. That being said, it’ll save you from worry of being fined because a purchaser or pumper accidentally leaving a thief hatch open. So, when oil falls from 50psi to about 5 psi in the VRU, it completely switches the compliance equation to benefit the operator. Your tanks no longer fall under Quad0, and you now drop out of the EPA’s system!!

Towers are (relatively) cheap. In fact, some consultants think it’s the future of the oil & gas industry. Basically, instead of having a heater treater and separator dumping straight into a tank, oil will flow through a flash vessel / VRU tower first.

Remember, the more headspace you have (i.e. the taller the tower), the better. Essentially, it’s a cheap way to comply with the rules… everybody wins: you, the EPA, and the environment.

Again, this isn’t for those stripper wells, it for those higher volume wells producing 50-100 bbls a day w/ a lot of gas flashing off.

Side Note: We’ve heard Chesapeake is starting to install these towers. They’re flaring off the top, and using this method as a very effective means of reducing the gas coming off their tanks.

What’s that you say? You’re nowhere near the size of Chesapeake? While you may not be able to afford a VR tower at every site, we always encourage the idea of ‘plug-and-play’ equipment. A VR tower only be economical during the first few months of flush production. That being said, over the lifecycle of a well, you’re going to need 2-3 different types of VRU units. That’s why we so strongly discourage ‘one offs’ customized to each site and promote the idea of moveable, skid mounted equipment.

Essentially, the idea is as soon as one well starts to fall off (and you bring another one on), you shift this equipment around. Mounting your VRUs and combustors on skids lowers your CAPEX, and enables you to use the right tool for the job.

Think about it: this doesn’t just apply to your VRUs and combustors… the idea is just as easily transferable to expensive sensors and SCADA equipment. There are many different camps of thought around the use of SCADA and at what level of production is necessary to justify the costs. Although technologies like remote operations and SCADA have sought to address productivity and efficiency issues, many independent operators are of the mindset that a mature well is going to produce what it is going to produce regardless of whether its production is monitored or not.

Even in the case of high-flow wells, most operators require that their pumpers visit these sites several times a day, trumping some of the potential benefits a wireless monitoring device may tout… but I digress, we’ve written about oil well monitoring with a smartphone app a lot, even in an article published by E&P Magazine which you can check out here:

http://www.greasebook.com/blog/oil-well-monitoring-with-an-ipad-app/

VOC Detection via Drones

Ever been in the field before? (ok ok dumb question) Ever smelled gas before? We thought so. Usually, that means you’re crossing a gas trail. The interesting things about VOCs is that they generally don’t disperse; they often hang tight and travel along a specific trail. These gas trails will travel along 4-5 miles crossing highways, fence lines, and backyards.

Like in every other aspect of the oilfield, technology is changing. Infrared cameras used to detect emissions are now old technology. Yes, it came from the military. Yes, it’s $100k per camera. But, they’re labor intensive and fail to find many of the leaks.

New tech to detect emissions is now commercially available. In fact, many folks are talking about these new emissions sensors being attached to fixed wing aircraft or drones. When combined with meteorological instrumentation and sophisticated software, these technologies can detect methane plumes and quantify emission rates from your tanks — all from authorities sitting inside a parked van controlling the drone.

Drone from the movie Terminator 3: Rise of the Machines

And, while these technologies aren’t quite ready for prime time, the fear they incite may be used by your local VRU dealer to conjure up a few early sales ;-P

Looks like we’ve got two choices: (1) open season on drones, or (2) get compliant. Understand, a new playing field is quickly evolving. Rest assured that the EPA will be checking it’s list, checking it twice… gonna find out who’s. . .

Got something to add in the comments below? If so, post it!! Other independents like you wanna hear it!

EPA NSPS Subpart OOOO: The Good, The Bad, and The Savvy (Part 1 of 2)

As an independent oil & gas operator, it’s important to know what the EPA is doing and what they’re thinking.

In this post, we’re going to explore the good, the bad, and the savvy regarding tank emissions, how they jeopardize your oil & gas operations, and what exactly you need to do about them.

NSPS Subpart OOOO (for the Savvy Operator)

“I never worry about action, but only inaction.”

Winston Churchill, Widely regarded as one of the greatest wartime leaders of the 20th century.

The New Source Performance Standards (NSPS) — aka QuadO — is the most radical piece of legislation or rules to come down on the oil & gas industry. However, it’s not QuadO that scares us; it’s the thought of independent producers not understanding the rules that has us worried…

Operators in Oklahoma and Texas are getting a lot of misinformation from consultants. And, when slapped with a fine, a “but I didn’t know, Sir” ain’t gonna get you off the hook. Essentially, if you’re generating BOC (biogenic organic compounds) emissions of 6 tonnes or more per tank per year, which are C3+ (not methane or anything below), you’re required to reduce those emissions by 95%.

What in the world does 6 tonnes look like? (yah, we had no idea either…)

  • 33 lbs of emissions per day
  • 1 MCF per day coming off your tank (which is about 1300 BTU of gas…)
  • 1 bbl of condensate produced / day (40 API and above)
  • 20 bbls of oil produced/day
  • 2000 bbls of produced water/day (remember: produced water produces VOCs… so heads up you disposal site and water flood play owners!!)

So, if you’re making 20 bbls of oil per day, you’re more than likely making 6 tonnes of gas per year per tank.

So, when did all this happen??

August 23, 2011 is where the authorities draw their line in the sand. Essentially, anything coming online after August 23, 2011 falls squarely under QuadO. That being said, anything before August 23 isn’t affected…

Why aren’t our production assets with an earlier spud date affected? Because the EPA feels that these sites will generally be in decline and any emissions issues will resolve themselves — which actually makes pretty good sense.

However, if you go back in and rework a well from the late 1980s, that property will now fall square under the regulations of the EPA.

So, what happens if you do fall above the 6 tonne threshold?

We know some of the shiftier operators would like to say, “hell, we’ll just throw a few more tanks out there and simply fall into compliance with those SOBs…”

Which leads to an interesting question: 6 tones is great and all, but can we average tanks? 

It’s a good thought, and while the State rules take into account site wide emissions, the federal rules explicitly state 6 tonnes per year PER TANK.

Many consultants and trade associations say you can average tanks, but the EPA rules say you can’t. The EPA is effectively saying 6 tonnes per single facility or source.

Now, a lot of us have read about certain States are coming down heavy on companies who flare (high volumes of) gas because they see that as potential revenue going up in flames (Much Of North Dakota’s Natural Gas Is Going Up In Flames…)

It’s interesting to note that there are three essential areas of VOC creation:

  1. working losses (tank levels moving up and down from loading and offloading…)

  2. standing losses (temperature changes causes oil to expand and contract)

  3. flash (Bingo! 90% of our emissions happen here)

Why do 90% of the emissions happen from flash?

Two words: Live. Crude.

“Live Crude” is simply product that contains gas in the solution, and is still remains under pressure as it moves through the equipment of our tank batteries.

Flash happens because crude is dumped into atmospheric tanks — generally from a separator or heater with 30-50 PSI — that reside at an atmospheric level. It’s sort of like soda coming out of a can… when opened, all the gas wants to break out. And, this is exactly from where the majority of our emissions are coming…

Now that we know the source of 90% of our emissions, let’s approach this methodically. That first tank we’re flashing into from our separator or heater, we must take our VOC measurement from that tank.

**Fun Side Note: Here at GreaseBook, we hear all sorts of good stuff that we like to pass along. And while we never promote doing the wrong thing, we do like to make sure independents are as informed as possible so that they can make their own best decision…

That being said, the Savvy Operator knows that if you really want to tip-toe around the rules, you can set up your sites to ‘load parallel’ — essentially, load all your tanks evenly.

By doing this, you’d be sending a stern message to the EPA of ‘don’t tread on me / leave me alone…’ But, you may also invite unnecessary scrutiny from your inspector…

New Source Performance Standards

In this case, we think it’s easier to just play by the rules. The more quickly we understand the rules (and abide by them), the more quickly we can get back to the business at hand (ie producing oil).

Hey EPA! So, where do Stripper Well Operators fall in all this? 

Don’t worry — the EPA isn’t out to put us out of business.  If each source is below 4 tonnes per year, you can dodge the draft altogether as you aren’t required to have controls. We still gotta have our thief hatches etc — but no combustors, and definitely no VRUs.

Fear: The Great Motivator

Colorado has been in the news for having some pretty strict compliance rules. And, many of the 23 oil producing States (including Ohio, Utah, Wyoming…) are looking at the CO rule book as a blueprint. However, until these States pass similar regulations of their own, be aware that fear-mongering is a well-known tactic to sell you compliance equipment you may not need…

Just a few weeks ago, a VRU consultant told us in passing that if a “Colorado inspector sees visible emissions, hears hissing, smells gas, sees smoke off a flair, they’ll write you a fine on the spot. No negotiations. No notice. No bull.”

He went on to say, “You have two tank lids open left open by a purchaser or service co? Boom. Each one is $15K violation.”

We thought that was pretty strong…

Good thing Denise Onyskiw, P.E. (owner of Onyskiw Engineering out of Denver, CO) wrote in to clear a few things up for us…

Denise wrote in to say, “I used to work for Colorado in their oil and gas unit at the Air Pollution Control Division. The State of Colorado doesn’t have statutory authority to issue you a fine right on the spot if they find a violation. A Notice of Violation (NOV) will be issued and they go back to the office to prepare it.”

Denise went on to tell us, “There is an opportunity for negotiation. The State may not give in but you can try. There may be a situation such as you just bought the facility and are about to start getting everything in compliance… this may not get you off the hook but you can enter into a compliance plan.

The emissions ARE measured per tank. Any tank with a potential to emit of 6 tons or more is subject to Quad O (unless it was built and not modified before August 23, 2011). Rearranging your facility to avoid this situation may meet the letter of the law but still violates the spirit of the law. The same emissions that the regulation is trying to control end up not controlled. States may not allow you to permit a facility with a rearrangement to avoid a regulation.

It’s very frustrating to try to calculate the emissions inventory of a facility if the records are inadequate or missing. EVERYONE needs to keep accurate, complete records, even the small operators. This regulation applies to many small operators and states don’t want to hear excuses for poor recordkeeping. That’s also something that will get you an NOV.”

(Excellent insight, Denise! GreaseBook thanks you!!)

You can’t manage what you don’t measure. So, we recommend the carpenter’s rule: measure twice, cut once. Again, the idea is to know how many VOCs you’re producing before someone comes to tell you how many VOCs you’re producing!!

(Tank emissions detected with the FLIR GasFindIR infrared camera at an oil and gas storage facility located in Fayette County, Texas.)

How to Measure those VOCs

“What gets measured gets managed.”

Peter Drucker, Austrian-born American management consultant, educator, and author, whose writings contributed to the philosophical and practical foundations of the modern business corporation.

So, just how much gas is coming off each source / tank? Breathing and working loss emissions from produced water tanks can be determined using the current version of the TANKS program (the EPA’s free software), available for download here:

www.epa.gov/ttn/chief/software/tanks/index.html.

Again, it all comes back to knowing what you got. Figure out whether you need to act so that you can get on with the business of producing.

**Update: 10/6/2014**

Many of our readers made us aware that the EPA’s TANKS Program is defunct and no longer working. Shortly thereafter (leave it to private industry!), we were contacted by a Halker Consulting (Denver, CO) who has built a free tank emissions app which you can download straight to your iPhone.

Essentially,  the app helps estimate emissions of volatile organic compounds (VOCs) and hazardous air pollutants (HAPs) from fixed and floating roof liquid storage tanks. The user inputs the tank dimensions and conditions, ambient conditions, and component specifications, and the app calculates the estimated emissions from the specified type of tank.

Enjoy!

https://itunes.apple.com/us/app/tank-emissions/id909367908?mt=8

 

EPA 101: One Class You Don’t Wanna Fail

Basically, there are two dates you need to get your homework in by…

Group 1: from August 23, 2012 to April 12, 2013 — any production coming online during this window, you must make a determination how many tonnes have been produced off. If you haven’t done this, you’re already out of compliance.

Basically, every well you had, emissions toneage had to be determined by October 15, 2013 and you had to notify either the State or the EPA by January 15, 2014. If you haven’t done this, you’re already out of compliance.

Group 2: April 12, 2013 to Today — these wells that have recently come online are in the EPA ‘system’. So, once the well has stabilize, you have 60 days to bring it into compliance. Basically, the feds give you 30 days to determine your emissions, and 30 more to get your controls onsite.

Finally, mark April 15, 2015 on your calendar (whoops!), as this was our ‘due by’ date to put any necessary controls onsite.

While none of us are Hot for Teacher when it comes to the EPA, some savvy operators have come up with some Cliff’s Notes which may help some of us get through the class that much easier…

In our next installment of this two part series, we’ll explore the Vapor Recovery Unit, the VRU tower, and why some industry consultants believe it’s the future of the oil & gas industry.

Did we get something wrong? Do you disagree with something we said?  Or, maybe you’re just a big Van Halen fan?? 

Whatever it is, other independents can benefit from your input.

So, your comments below, other independents would like to hear about it…

New Rules for Injection Wells in Oklahoma: Monitoring Volumes and Pressures

The earthquakes in Oklahoma has brought a lot of attention to the industry over the past few months. That being said, the Oklahoma Corporation Commission has established some new rules for new & existing disposal wells.

Image Credit: EMSNews

For those of you with production in Oklahoma, more specifically production in the Arbuckle formation, heads up!

As of September 1st (2 days ago), disposal well operators injecting into the Arbuckle formation are required monitor daily volumes, casing pressure, surface injection pressure.

Remember, GreaseBook tracks daily cums, pressure, and casing. That being said, most of you are probably already doing this — which is great!

If not, please holler and we’ll be happy to get you set up immediately…

Let us be very clear: while you are required to monitor your wells, the submission of the information is only required upon request.

Essentially, you are not required to report it unless it is specifically requested by Commission staff or Oklahoma Geological Survey staff.

The commission is paying special attention to disposal wells within seven “areas of interest” in central and northern Oklahoma. The areas are near the epicenters of the 20 magnitude 4.0 or greater quakes the state has experienced over the past five years.

Oklahoma is dotted with nearly 12,000 water injection and disposal wells — that being said, it seems there are only 97 wells in which they are particularly interested…

For more background information, check out the article printed in the Sunday Oklahoman on August 24th, entitled “Quake Study Leads to Cooperation”:

http://newsok.com/quake-study-leads-to-cooperation/article/5335369

Special thanks to Glenn Blumstein, President of GLB Exploration, Inc. and his team in Oklahoma City for tipping us off…

And, a BIG thank you to Brian Woodard (the OIPA’s former VP of Regulatory Affairs, now Director of EHS Regulatory Affairs at Chesapeake) for helping GreaseBook to clarify the new rules!!

Wanna take a look at the new rules for yourself?

You’ll find them attached below…

1.      Oklahoma Corporation Commission (OCC)

a.      Joint Advisory Subcommittee and Technical Rulemaking Conference Highlights

i.     OIPA representatives attended OCC’s Technical Rulemaking Conferences held on January 14th, January 29th, February 7th, February 19th, February 28th, in addition to the final, hearing en banc which was held before the Commissioners on March 13th. Substantive rulemaking items which were addressed, include:

 1.      OAC 165:10 – Oil and Gas Conservation Rules

a.      OAC 165:10-3-15 (A-E) Venting and Flaring

1.      Provides a 72-hour exemption period for conditioning producing wells and provides a 14-day exemption period for gas flared subsequent to initial flowback of a newly completed or recompleted well. Moreover, the rule provides for an additional 30-day period exemption if gas volumes flared are less than a rate of 300 mcf/d on a rolling average basis. The 14-day timeline commences following >50 mcf/d of combustible gas flow.

b.      OAC 165:10-3-17 (D) Required Lease Signs

1.      Requires API number and Global Positioning System (GPS) coordinates on lease signs for wells completed following the effective date of the rulemaking (July, 2014).

c.      OAC 165:10-3-26 (A-D) Well Logs

1.      Revises all instances where “wireline logs” are referenced to be more robust through the inclusion of the verbage “geophysical formation evaluation type well logs.” Also, the final rule requires producers to submit sonic logs to the OCC and allows the Commission to request additional well logs.

d.      OAC 165:10-5-6 (D)(1)(A)Testing and Monitoring Requirements for Enhanced Recovery Injection Wells and Disposal Wells (D) Subsequent Mechanical Integrity Tests (MIT).

1.       Requires operators of non-commercial disposal wells permitted for injection at volumes equal to or greater than 20,000 barrels shall demonstrate mechanical integrity by using one of the following methods:

a.       Conduct a pressure test of the casing tubing annulus at least once every five years year according to the minimum testing standards of (3) of this subsection, or

b.      If a continuous pressure monitor is installed on the casing tubing annulus that will automatically notify the operator of a mechanical failure, then the well shall demonstrate mechanical integrity at least once every five years according to the minimumtesting standards of (3) of this subsection.

e.      OAC 165:10-5-7 (b) (3)(B)Monitoring and Reporting Requirements for Wells Covered by 165:10-5-1 – Required Monthly Monitoring

1.      On a daily basis, the operator of each well authorized for disposal into the Arbuckle formation shall monitor and record the volumes, the casing tubing annulus pressure and the surface injection pressure for the well. The operator must maintain the information required by this subparagraph for a minimum of three years. This information shall be produced upon request by an authorized representative of the Commission.

f.       Additional items concerning the concurrent development of horizontal and non-horizontal drilling and spacing units were a significant topic of discussion during these technical rulemaking hearings. The following was a significant provision adopted within the Ch. 5 and Ch. 10 rulemaking.

1.      OAC 165:10-3-28(e)(4) – upon the formation of a horizontal well unit that includes within the boundaries thereof one or more non-horizontal drilling and spacing units, the Commission may provide that such horizontal well unit supersedes one or more of such non horizontal drilling and spacing units or mayshall provide that such horizontal well unit exists concurrently with one or more of such non-horizontal drilling and spacing units, In the event the Commission provides for the concurrent existence of a horizontal well unit and a non horizontal drilling and spacing unit, as provided above, and each such unit may be concurrently developed.

New Feature: Better Trending and Production Monitoring Alarms

Update! GreaseBook now reduces the number of ‘false anomalies’ and enables you to set much ‘tighter’ trending alarms in the monitoring of your Oil, Gas, and Water production levels.

Basically, as opposed to comparing the historical running average production against today’s production, we’ve changed the anomaly alarm structure by enabling you to compare the historical running average against the last several days of production.

How does this help you as an operator?

First, with the old way of oil well monitoring, many operators were experiencing ‘false anomalies’. Basically, they would be alerted to an issue when there was in fact, no issue at all.

This could’ve been due to a well cycling twice on some days and only once on others. Or, in some cases, a stripper well that may have produced nothing at all.

That’s now been addressed.

Please note, this ability to compare two sets of production numbers will enable you to configure a much tighter (potentially ‘truer’) trending alarm for those higher production flowing wells, too.

As a good rule of thumb, we recommend starting with a 20% variance for both Oil and Gas, a 30 day moving average count, all compared against 3 most recent average days

To get on board with our new trending alarm set-up, log in to your Exec Dash at http://execs.greasebook.com.

Go to ‘Administrator’ Tab > and click, ‘Company’. Once you’ve got your variances and days the way you want them, be sure to click ‘Save’.

Also, to be sure you’re set to receive these types of production alerts by clicking ‘Users’ > then ‘Executives’ (both of which fall beneath the ‘Administrator’ tab…)

Now, find your name, and check any of the following three alerts:

Oil: Production >X% Change

Water: Production >X% Change

Battery Sales Meter > X% Change

Once you have your anomalies set the way you like, click “Save” and then sit back and let GreaseBook alert you to any inconsistencies in your production!

As a kicker, GreaseBook will even display the % variance in your anomaly alerts…

Traditional paper gauge sheets and production reports got nothin’ on the GreaseBook!

Side note: once you’ve addressed the alert and the issue has been resolved, clearing the anomaly by clicking the red Authorize? button notifies your team that everything has been taken care of!

A BIG thanks to Nathaniel Harding, petroleum engineer and President of Harding|Shelton in Oklahoma City for such a great suggestion.

We look forward to your feedback n the comment section below…