The other day, GreaseBook got to speak with Tom DiChristopher, a journalist who covers the oil market for CNBC in New York…

oil production software productivity tough times

Tom was interested to know more about a trend he was seeing in the industry — essentially, a move toward greater emphasis on productivity measures like the GreaseBook oil production software in a tough price market.

We were thrilled to speak with Tom (and we were even more impressed with his depth of working knowledge of the oilfield — very cool, Tom!)

Tom spoke with a few of GreaseBook’s clients as well as several other Tech Firms in the oil & gas space… a fun read, an even fun-ner experience for GreaseBook to be mentioned on CNBC 🙂

To check out the article, click here.

Given the current environment, independent operators around the country are reevaluating the way they operate their wells…

Now, while we don’t have control over the price of crude, we do have direct control over the costs at which we produce it.

My family has been in oil & gas for nearly 30 years. I respect the old guard. And, sometimes new ways of doing things must be considered — especially when it directly lowers our company’s marginal production costs (the point at which we shut our wells in…)

Understand, most software companies would like for you to believe it’s the technology that’s important. However, what they don’t disclose is that whatever technological advantage they’re trying to push often comes at the price of worsening the team’s sociology.

Instead of building procedures to support your folks in the field, many of these companies limit the contributions of people. They set a tone of rules and rule following rather than thinking and rule adjusting (or even rule improving!)

With apps, it’s different. People actually want to use these tools…

Remember, the first rule of any technology used in a business is that automation applied to an efficient operation will magnify the efficiency. The second is that automation applied to an inefficient operation will magnify the inefficiency.

Basically, we don’t add people to broken systems. People are expensive. If Operator A manages 100 wells with a staff of five people and Operator B manages 100 wells with a staff of twelve — all things being equal — Operator A wins. His investors win. His employees win. And, the company will carry on in nearly any environment. (click here to see what happens when operators refuse to go mobile...)

For Operator A, Sub-$60 oil doesn’t look so bad anymore. It ain’t party time, but no one is closing their doors either.

Admins’ and ops supervisors’ days are full. And, many times they leave the office (exhausted) and ask themselves, “what did I really accomplish today? How did I move the company forward? How am I securing a future for myself at this company?”

Rather than comparing sales tickets against oil purchaser statements and clawing back that money, Admin is stuck tracking down missing run tickets. They know they should be sending out reports to managers, investors, and State agencies, but they’re trapped just trying to organize these reports into something workable…

They can’t break the cycle of meta-work. Essentially, work that fills our days but isn’t really that important.

Does it keep us busy? Oh yeah.

Does it move the company forward? Not really.

As for management, it’s a completely different set of issues. Given their current tools, many accept that ‘skimmed oil’ is just part of doing business. They realize they must trust their pumpers (the front line!), and short of going to the field and gauging the tanks themselves they have no way to verify their production numbers. If they knew, many skimming oil purchasers and services companies would be immediately dropped (that said, you may like this write-up we did on The ‘Perfect’ Oil Production Report (and the Magic of ‘Proper’ Pumper Management…)).

oil production spreadsheet template

Sometimes it’s tough to know where to point the finger. Sometimes, drops in tank volumes are simply a function of a change in weather. That being said, randomized quarterly checks by a 3rd party roustabout is a very cheap (and very effective!) form of production insurance.

It sounds funny, but problems are like mushrooms: when it’s dark and rainy they multiply. Under bright light, they diminish. In an organization where there is nowhere to hide, the problems are easily illuminated.

Folks, systemized daily production reports can create that strong light.

We’ve seen examples of pumper production reports from all corners of the country. Some of these gauge sheet templates haven’t changed since the 1940s. Still others are works of art!

To the degree you can clarify your systems and hone them, you will run your business as opposed to having it run you. The culmination of identifying, documenting, and having everyone follow the core processes of your business is the way.

When you have a clear way, you immediately increase the value of your business, strengthen your control over it, and give yourself options. From there, you may grow the business, let someone else run it, sell it, or simply take more time off.

My dad and I both own and operate our own software companies here in Oklahoma. My dad founded SSI (a well-known E&P accounting platform) in 1979, and I built an iPad app (GreaseBook: Production reports that don’t suck!) for oil & gas operators in 2013.

That being said, we take frequent trips between Tulsa and Oklahoma City. On more than one occasion, my dad had mentioned to me an old pump house that he’d seen off the East side of the I-44 Turner Turnpike…

Now, growing up in Oklahoma, I spent a lot of time outdoors. While hunting and fishing with my pops, I got to see a lot of pump jacks up close as a kid.

My dad said he’d seen a few of these — one wheelhouse in Kansas he said ran 5 rods/wells. However, at 32 years old, I’d never come across anything like this…

Due to all the foliage, the old pump house is especially difficult to see during the summer. However, if you look hard enough, you can see it tucked back in a knoll on the NE side of the S 209 West Ave overpass.

Anyways, it was a nice day (and I’m kinda weird and like this oilfield history stuff), so my dad and I thought we’d pull over and check it out.

Check out the video and photos posted below…

After poking around onsite, I immediately did a Google search on the Superior Gas Engine Co (which I found very interesting!)

So, we’ve also included a little background on the Superior Gas Engine Co below…

The Superior Gas Engine Co.

In 1889, the PJ Souvlin machine shop opened its doors in Springfield, Ohio, to accommodate the booming Lima, Indiana, oil field that had been discovered only a few years beforehand.

Souvlin’s machine shop at it’s outset was just a repair facility, but it soon joined the ranks of firms competing to develop an internal-combustion engine that could use well head gas for power. At that time natural gas was viewed as an annoying and sometimes dangerous by-product of production (ahem, North Dakota anyone?)

Photo (and much of the article’s content!) Accredited to Gas Engine Magazine

As you can see, the engine in the pump house was built by Superior Gas Engine Co. From what I’m told, the company relied on its reputation for ‘superior’ quality to promote sales. The oilfield is a small community, and word gets around quick — Superior’s practice of showing-by-doing must’ve worked, as several other manufacturers built engines many people now call “Superior clones” due to their similar design.

Superior engines were favored for their somewhat better fuel efficiency. They used a four-cycle mock-up in the oil field where gasoline production was scarce. And, some of you folks who’ve been around for awhile in the oilfield may be able to confirm this, people tend to agree that Superior engines were at the higher end in the world of oil field engines.

Basically, if Reid and Bessemer engines were similar to a Chevrolet or Ford, then Superior engines might be the Cadillac or Lincoln of the oil field — not really any better, but definitely had all the bells and whistles…

Superior, All Grown Up

PJ sold his first engine for oil field use to the Ohio Oil Co. based in Findlay, Ohio (the predesescor of today’s Marathon Oil). Originally, all Superior engines were sold directly to the customer. However, as the engine maker continued to grow, so did the need for a distributor.

A deal was struck with the newly organized National Supply Co. to become exclusive sales agents of Superior engines to the oil industry. As both companies continued to grow, National Supply acquired another oil field engine builder: Spang, Chalfant & Co.(one of the oldest names in the US oil industry, dating back to 1828).

During World War II, Superior employed nearly 2,000 men and women. It received the Maritime Commission ‘M’ award and Victory Fleet Flag for its record of building the diesel engine for the U.S. Liberty ships.

In April 1955, National Supply Co. sold its Diesel Engine Division to the White Motor Co. of Cleveland, which was among the leading manufacturers of large, heavy-duty trucks and tractors. Several years later, National Supply was acquired by the Armco Steel Corp. of Middletown, Ohio.

The Superior plant in Springfield became known as the White Diesel Engine Division. In the 1950s and 1960s, the company’s engines were being used in nearly every type of application you could conceive: marine, defense, transportation, municipal and, of course, the oil industry. And, in 1964, Ohio experienced another oil boom not far from Springfield, and Superior engine-compressor units were installed.

With gas engines re-established as important products, the name was changed once again from White Diesel Engine Division to White Superior Division. When the company was purchased by Cooper Industries in the early 1970s, the majority of Superior markets were in the oil and gas industry, with some sales among municipalities and occasionally to government groups. Additionally, the division completely withdrew from marine diesel production.

It’s a cool piece of Oklahoma history — better yet, of Oilfield history.

Do you see a lot of these pump houses around the Ohio area?

Any Texas or Kansas folks who wanna chime in??

Better yet, do you know if any are still in use??

If you have insight or a cool story, please leave it in the comments below!! We’ve got tons of great stories already, I’m sure we’re not the only ones who’d like to hear about it! 🙂

Man, do we like to talk about productivity.

What’s the newest software? What’s the latest horizontal drilling technique? What’s the best way to manage my field staff? How should I manage my oil and gas production data? What should I do about delegating? OMG, i need a admin assistant!

However if we take a step back and we’re honest with ourselves, how many of these things have positively influenced our business in the past month? In the last year? In the last 5 years?

Do we ever just search for the latest app, the latest tactic, the latest tool without ever asking ourselves what the real fundamental challenges are with productivity?

A Good ‘ol Boy (from Italy)

Born in the late 19th century, Vilfredo Pareto was an an engineer by training, and controversial economist-cum-sociologist. Vilfredo began his career overseeing coal mines, and was later named chair of political economy at the University of Lausanne in Switzerland. His seminal work, Cours d’economie politique, explored a then unexplored “law” of income distribution… it later became to be known as “Pareto’s Law” or the “80/20 Principle”.

The 80/20 rule is powerful because it’s a law of nature – much like the Golden Ratio, the Butterfly Effect and chaos theory are laws of nature. In fact, it’s driven by the same underlying causes…

How in the world does this apply to the oilfield?

Basically, Pareto’s Law can be summarized as “80% of the outputs result from 20% of the inputs.”

Other ways of phrasing this might be:

  • 80% of your company’s production comes from 20% of your production assets
  • 80% of your engineer’s headaches come from 20% of your wells
  • 80% of your administrator’s headaches come from 20% of your pumpers
  • 80% of your skimmed (ie ‘unaccounted for’) oil comes from 20% of your purchasers & service companies

We could come up with an exhaustive list to apply this principle to in the oilfield. Heck, you may have even encountered this principle as being skewed even more severely: 90/10, 95/5, or even 99/1 aren’t unheard of.

So, as an operator we must make a choice: we can continue to shovel more coal, or begin the dissection of our operations and workflow through the lens of Pareto.

Elimination before Delegation

Oil and Gas data management, oil production software

Scotty: She’s all yours, sir. All systems automated and ready. A chimpanzee and two trainees could run her!

Captain Kirk: Thank you, Mr. Scott. I’ll try not to take that personally.

— Star Trek

Delegation from the office to the field is to be used as a further step in reduction, not as an excuse to create more work and add to the unnecessary. Remember, unless a task is well-defined and important, no one in your operations should be doing it (you can also check out our post on Why it’s Crucial You Organize Around Data (Not Personalities) in Oil and Gas Asset Management.

We must eliminate before we delegate.

Remember: never automate something that can be eliminated, and never delegate something that can be automated or streamlined. Otherwise, we’ll waste your employee’s time as opposed to our own.

Before attempting to automate the field (not just workover reports, well history files but production reporting, run ticket reconciliation — the whole enchilada), principle number one must be to refine rules and processes before adding people. Adding people to a refined process multiplies output, however using people as a fix to a poor process multiplies your problems…

While working toward increased efficiency and effectiveness, let’s keep two truisms in mind:

  1. Doing something unimportant well does not make it important.
  2. Requiring a lot of time does not make a task important.

If you’re an independent operator and you take the long view on oil, understand one thing: What you do is infinitely more important than how you do it. Efficiency is still important, however it’s useless unless applied to the right activities.

And, the ‘right activities’ when managing the oilfield isn’t the collection or organization of production data. It’s enabling your admin and ops supervisor to conduct revenue-generating activities by presenting them information about your production in the right kind of way (check out this post on eliminating human error in the oilfield…)

Folks, there is a far better option than a ‘results-by-volume’ approach, and it will do more than simply increase your productivity, it’ll increase your profits, too. Believe it or not, it is not only possible to accomplish more by doing less, it’s mandatory.

The time is never right

Focusing on the 20% of your workflow that delivers 80% of the results is the name of the game. You, your administration, and your operations supervisors must put aside everything seemingly urgent and undergo the most truth-baring analysis possible — you must apply this principle to everything, from how you organize your people to how you manage your production assets.

Don’t expect to find you’re doing everything correctly (or that everyone is operating honestly). The truth often hurts. The goal is to find our inefficiencies (problem pumpers or a skimming vacuum truck operator) and eliminate them. Then, find our strengths so that we can multiply them.

These simple changes can be difficult, even emotionally challenging for the independent producer. But no doubt it’ll effectively change the way you operate forever. After all, the idea is to enable your company to run more efficiently or grow exponentially, depending on your goals.

Do you know the secret of the most effective, cost-efficient oil producers in the game today?

It’s not some new age approach to their hiring practices. It’s something much simpler, folks… these teams have mastered the art of elimination, automation, outsourcing, and delegation.

These four methods are very, very powerful. In fact, each one of them used alone will increase the bottom line of your operations. However, using all of them in combination on a regular basis will bring about rapid operational reprogramming. The sooner and more rapidly we get on-board with these methods, the more rapidly you’ll bring operational effectiveness. And, operational effectiveness is where the money is at…

Stupid Simple

It’s so simple in theory, but how many operators put these cost-slashing activities into practice?

“But this boom is different!” they cry…

“Why count nickels and dimes in the office when there are dollars to be made in the field?!”

Look folks, if you take the long view on oil, you understand the importance of running an effective operation. When distributing responsibilities to your team, it’s important you work through your list of responsibilities and tasks.

Essentially, it’s the perfect opportunity to utilize the 80/20 rule to throw out non-essential tasks. Rather than distributing 100% of the work of the manager, the savvy operator will divide the work into two groups:

  1. the 20% that is the most important to keep within the company, and
  2. the 80% that can be eliminated, automated, or outsourced.

How do we do this? It could be as simple as throwing the company’s tasks on a whiteboard and striking a line between the “crucial 20%” and the “other 80%”. You must ask yourself what can we eliminate? What can we automate? What can we outsource?Then (and only then!) should you delegate what is left…

In an another post entitled “Field Data Capture (and the secret of the most effective, cost-efficient Oil Producers in the game today…)“, we outline how automation applied to efficient operations magnify the efficiencies, while automation applied to inefficient operations magnify the inefficiencies.

How efficient are your operations? How much extra work are you creating for yourself and your team by not first reviewing the validity and importance of each task?

Basically, you need to distribute responsibilities throughout the team (or to outside the team) in ways that aren’t going to add a lot of extra work. That’s why it’s so important to eliminate, automate, and outsource before delegating to your team members.

Transparency: Holding Lease Operators and Production Teams Accountable

For core activities that simply can’t be eliminated, oftentimes we can still cut 80% of the field reporting, production monitoring, well checking, and performance auditing.

Understand, the oilfield has been run the same way for a long time. However, there’s no reason why we can’t get a little creative. For example, rather than having a process to pre-approve expenditures, have you considered eliminating the approval process all together?

Before you knock it, why not try it? It’s a great example of effective elimination and transparency. On a wall, post everyone’s expense reports or team expenditures against budgets. Not only does this breed transparency, but with type of expenditures method in place you also create a process in which employees must seek advice from others before spending money. It could be a process in which a peer — not a manager — must approve the expenditure.

One of our favorite examples we’ve seen of effective elimination and transparency was a company that posted the performance of the routes of every lease operator. Monthly overhead averages that were necessary to maintain a pumper’s wells and daily average production numbers for the route were on display at the field office for all to see.

Sure, some wells were going to produce more than others. And you’re right, a few outlying wells were going to be more troublesome (read: cost-intensive) than the others. However, spread out over a pumper’s route of 15-40 wells, a company is able to see a distinct differentiation of performance among its employees (and thus reward production teams accordingly!)

Both the ‘old pros’ and the ‘young know it alls’ are difficult to manage. Getting them to understand how their engagement (or lack thereof) with their route affects the bottom line of the company can be difficult. However, when companies are fully transparent, poor performers are left to argue with the numbers (and we all know that ain’t much fun! ;-P)

These methods of peer review may be reserved for only the most progressive companies in the oilfield, but we believe that transparency is a much more powerful and productive combination than administrative rules and regulations.

Automation of Your Production Reports

After eliminating and reducing as much as possible, go through and map out what you can automate or outsource, in ways that will both free company time and improve your results.

Most great oil companies have come up with crafty ways to eliminate paper. Have you ever asked yourself what conditions would have to exist for the team and executives to get all the reports and analysis they need with the click of a button? By submitting production numbers in real-time (such as with an app like GreaseBook), ask yourself whether you could eliminate the need for someone to do reporting altogether…

In doing a lot of this elimination and automation, understand “data-addiction” is a real issue. As a company, you need to ask yourself which reports are nice-to-have versus completely necessary. It is common for executives and board members who ask for reports to forget that many take considerable time and energy to produce, and that time isn’t free because it takes people away from the true business at hand (ie pumping oil).

Rather than blindly producing reports, ask them their business goal for the report. It’s not uncommon that they need something other than for which they’ve asked. Help executives understand the cost of the reports they want, so they can prioritize their requests.

Ask yourself how you can reengineer your reports to be more useful. Reports are often created just because someone wants it without a clear idea of its purpose. Ask, “What decision will this report help you make better? What is the goal of this report?” If a report doesn’t help you prioritize your energies or make better decisions, it should probably be reworked or thrown out. In doing so, staff is able to automate oil purchaser reports, and push out many of the duties that were originally intended for in-house admin to the pumpers in the field.

Never Give Up

Why does it feel hard to develop self-managing people and teams? Assuming you have hired good people (which many times isn’t the case), a main cause of failure is giving up too soon.

No doubt, adhering to elimination, automation, outsourcing, and delegation requires patience and practice. For some of you, it might take eight weeks to make a team self-managing. For others, it could be eight years. But if you give up along the way, you for sure will never make it happen. Stay committed, your bottom-line depends on it!

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.


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:

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!

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:

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.



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…

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”:

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.

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

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…

One does not accumulate but eliminate. It is not daily increase but daily decrease. The height of cultivation always runs to simplicity.

— Bruce Lee

This isn’t an exhaustive post, rather a short treatise into the workflow of today’s independent oil field operator. More specifically, the daily oil production report!

It’s meant to be short, simple, concise. We’ll talk about some of the problems independent operators face as we try to work in a world of overwhelming complexity. And we’ll look at some simple ways to solve those problems.

daily production reporting

The key is itself simple: focus.

We must focus on key levers of the oilfield. It’s not that “less is more”, but that “less is better”. Focus eliminates the clutter, and in doing so, have more time for what’s really important to our businesses: managing assets more efficiently, and scaling our business more effectively.

Focus forces us to choose, and in doing so, stops the excesses that has led to a breakdown of communication between the office and the field, and ultimately, losses in production and opportunity for growth.

If you don’t know us, GreaseBook (an app that simplifies the daily oil production report process) wants you to be aware of some of the new practices many up and coming operators are applying to their businesses…

And, you’re right: there is nothing new under the sun. Therefore, let this serve as a reminder for the independents to free themselves from the tactical work of the oilfield. To focus on managing the system rather than doing the work. To engage ourselves in strategic work.

Through observing and working with hundreds of oil & gas professionals (engineers, pumpers, owners, admin, foremen — from the $20BB level down to the mom & pops), it’s become apparent that smaller, more nimble operators have a leg up in this brave new world of oil & gas.

Stated quite simply: there has never been such a power reversal away from the Majors in favor of the smaller independents in the history of oil & gas.

Independent operators, swing away while the Big Boys look on from the side lines…

Automating the Oil Production Report Process

The first rule of any technology used in a business is that automation applied to an efficient operation will magnify the efficiency. The second is that automation applied to an inefficient operation will magnify the inefficiency.

— Bill Gates, cofounder of Microsoft, richest man in the world

Most of the majors are shifting their E&P primary focus away from “Exploration & Production” in favor of “Efficiency & Productivity”.

Why try and execute costly drilling campaigns when there is oil and money to gain by merely changing the way we operate? Quite simply, the best place to find oil is where it’s already been found. And, much like a factory, the operator who takes a long view on oil will be to eliminate as much overhead as possible while maintaining (or increasing) his hydrocarbon output. However, while “efficiency” may be today’s buzzword among the largest of operators, just how effective they are in achieving these efficiencies is up for debate.

Wall Street, more than ever before, is demanding greater capital discipline and increased financial returns from these larger companies and is placing increased pressure on management to improve their operational performance (read: a greater need to control costs…)

And, at the core of operational performance is process.

What’s this mean for the independent? Whether your goal is increasing the total number of properties you operate or just running your business as lean as possible, the future of oil will no longer tied to success in exploration, but to operating scale and greater efficiency in drilling and completion, as well as the daily operations of the company…

C-N-O-M-M-O-U-N-I-C-A-T-I (unscrambled = Communication)

The vision is really about empowering workers, giving them all the information about what’s going on so they can do a lot more than they’ve done in the past.

 — Bill Gates (you can tell we like this guy :-D)

One of the greatest impacts mobile devices can have on your company is the dissemination of information. Many savvy operators have realized that leveraging their field personnel is one of the most effective (and underutilized) methods to pump more oil, waste less time, and make more money (check out this post entitled: The ‘Perfect’ Oil Production Report (and the Magic of ‘Proper’ Pumper Management…)

Wait, what? Leverage our field guys? … What the hell do you think we pay these guys for?!

You’re right. It’s been said that any pumper or foreman worth his salt shouldn’t need a lot of supervision. A good employee should already know how to maximize a well’s production, while minimizing the costs of production. But, we’re not talking about cracking the whip on your lease operators — we’re talking about engaging your crew in a creative, inventive, and more proactive way…

Employees: If you’re an employee working for an operator, listen up! Integrating consumer frienly apps like Dropbox, Apple’s Reminder app, or even the simple smart device camera (all which we’ve written about here:  will increase your value and make it more painful for the company to fire you ;-P

Owners: If you’re an owner or actively participate in your company’s wells, you’re the direct beneficiary of increased productivity. The goal is to decrease the amount of work you do while ultimately achieving increased revenues. This sets the stage for replacing both yourself and members of your team with automation, enabling every counterpart to work on the business, not in it.

Empowering field personnel refers to being able to accomplish many tasks or make certain types of repairs without first obtaining permission or information. Being micromanaged (or micromanaging someone else) consume your company’s resources.

What mobile has done is blend the new with the old… where pumpers have virtually no interaction with our properties laced with SCADA and real-time sensors, manual data collection via mobile apps force pumpers to tune-in to the pulse of the well while still eliminating much of the work for the folks in-house. This pays out dividends in time savings to engineers and operations managers, who no longer have to spend time micro managing their pumpers, and admin who no longer have to track down and file those greasy run tickets 😉

For field personnel, whether it be your head pumper or field supervisor, the goal is to have complete access to necessary info and as much independent decision-making ability as possible… for the savvy operator, the idea is to grant as much information and independent decision-making ability to his army of pumpers, consultants, and field personnel as he’s comfortable with… given the right information, you’d be surprised just how much your guys are able to take off your plate!

Teams are not machines, they are composed of people. Today, the Big Boys are eyeing smaller, more nimble operators with increasing envy… many aspects of the Major’s operations that took the better part of a decade to design and build, can now be replicated by the small independent operator, with better results, in less than an afternoon. In many respects, the sociological aspects that consumer tech is built upon can now deliver more than the hired expertise, or even the money that larger operators have always been able to deploy.

And, while the current systems may be too well stitched into the fibres of the Majors for them to abandon, your company is probably very different…

When consumer tech (smart phones & tablets) is invited into the company and takes over the computation and dissemination of information, people all the way down the line learn to be effective decision-makers. You don’t have to solve the production problem for the whole institution — if you can solve issues for your own people, you’ll be way ahead. And, if your group is more productive, that just proves you’re a better manager. Now, by blending consumer tech with the lessons learned from our Bigger Brothers, your piece of production can hop.

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