Use Temperature Sensors At The Wellhead

I spent the first portion of my career in production and I got pretty good at diagnosing and fixing production issues on gas wells. One thing I learned is that you can save yourself a lot of money and headache by identifying and fixing production issues early, before they grow and create downtime. The primary goal of every production team is to keep the wells flowing as much as possible. Measuring temperature at the wellhead is a very practical way to identify potential production issues downhole, such as salt or scale rings. These things don't form overnight and thus they can be really difficult to identify. If you have a gas well, temperature can be a really helpful diagnostic tool, because any flow restriction cause a temperature drop. If that restriction is downhole, then the temperature of the gas at surface will drop.

I am a big fan of measurement and if I was in charge of a production site I would have sensors everywhere. I would have sensors sensoring the sensors just to make sure the sensors don't stop sensoring. That's a little absurd but you get my point. Sensors provide data and data informs us of what's going on so that we can make educated decision quickly and accurately. I get that sensors cost money, but lost production costs a lot more.

A temperature sensor at the wellhead is a really practical way of identifying flow restriction downhole, quickly, so that you can get the well back to full production potential right away.

I'm not a production guy anymore, so I don't have a dog in the fight. But if I were, I'd have temperature sensors on my wellheads.

Try To Avoid Packers Downhole

As you may or may not know, I spent the first third of my career so far in production. In that time I learned a lot about producing oil and gas wells, and one thing I learned is that downhole packers (between casing and tubing) really have a way of limiting your production options. The reason is that it cuts off your access to the annulus, thereby leaving your only downhole access through the tubing, which is where your reservoir fluids are being produced up. When a well has a packer, there is no easy way to provide continuous chemical injection into the well. This means that soap, corrosion inhibitor, salt inhibitor, and a whole slew of other valuable production chemicals cannot be easily injected into the well without shutting in the well. This leads to expensive capillary strings and/or other non-desirable options. For this reason, I don't like packers and I recommend trying to avoid them.

With that said, packers do serve a purpose and sometimes they are necessary. In these situations you will obviously have to install them and deal with the consequences. However, I've seen far too many times where a packer is installed as a part of the completion process, with no regard to the production impacts. I think this is silly. Production is the only point where you make money on a well, and therefore great consideration should be taken when making drilling or completion decisions that will negatively impact production. My advice is to use packers where absolutely necessary, but nothing more.

For those of you in drilling or completions, this may sound silly. Just trust me on this. Your production folks will appreciate it.

Run A Flowing Gradient To Identify Liquid Loading During Production

You may be familiar with a static pressure gradient survey, more commonly referred to as a "gradient". The process for a gradient is simple: run in the well with bottomhole pressure gauges and record the pressure at various depths downhole. From the data you can determine both the fluid depth and the fluid density in the well. Typically this is done with the well shut in, hence the term "static". While this is helpful information to know, when we talk about liquid loading, our concerns are usually related to the production of the well. Therefore liquid loading issues tend to impact us more when we are flowing the well, not when we are shut in. This is where a flowing gradient can be helpful.

As a well flows it pushes fluid up the hole, creating hydrostatic pressure. Even wells that are unable to lift fluid to surface, still lift the fluid at least part way up the hole. When the well is shut in, the fluid then falls back down to some equilibrium point. This problem is amplified in horizontal wells because the fluid tends to fall back into the lateral when the well is shut in. Tubing that was filled with fluid during flow becomes completely empty within minutes of shut-in. If you were to run a static gradient survey on a horizontal well (without a standing valve), you would likely find no fluid in the tubing. Your static gradient survey would not be a good representation of your liquid loading issues. In this situation a flowing gradient would be much more insightful.

If you have a well with liquid loading issues, consider running a flowing gradient survey rather than a static gradient. You might be surprised at what you discover about your well when it is flowing.

If you are interested in learning more about gradient surveys, click here to check out our Well Insights on this topic.

Understand The Limitations Of Echometers

Echometers are a neat tool that uses sound to determine (among other things) the depth of fluid downhole in a well. Similar to radar or seismic, an echometer sends a sound pulse down a well and measures how quickly that sound bounces back. Coupling this data with some math, we can estimate the depth of fluid in a well. It's a cheap, fast and neat way to answer the question, "How much fluid is in my well?" With that in mind, it's important to understand that echometers have limitations. The fluid level calculated by an echometer has some error in it. I've shot echometers on the same well, back to back, and received different fluid level calculations, sometimes off by 50 feet!

This is not an indictment on echometers, but rather my point is to say that you need to understand the limitations of this technology and only use it when appropriate. If you are simply trying to get an estimate of fluid level, or perhaps just trying to figure out if any fluid is downhole at all, then an echometer is a great tool for this application. However, if you are trying to determine your bottomhole pressure for a reserve analysis, then an echometer is simply not going to cut it. In this case you need a lot more accuracy than +/- 50 ft of fluid. If this is the case, then I'd recommend running bottomhole gauges in the well and performing a static pressure gradient, which will result in a much more accurate pressure measurement.

In short, echometers are a cheap and easy way to estimate your fluid, but it's important that you understand their accuracy and make sure sure you are using the appropriate tool for the job.

You Can't Turn A Bad Well Into A Good Well

Oil and gas is a wild and fun industry. Some wells are awesome, and some make you want to cry. It's tempting to think that with really spectacular engineering, that we can save the day and turn a bad well into a good well. Unfortunately, geology is the ultimate determining factor as to whether or not a well turns out good, not us. The truth is that some wells are bad because the geology just isn't on our side, and there not a lot we can do to change that. Don't kill yourself trying to turn a bad well into a good well. Trying to overcome bad geology is like trying to paddle upstream. Our job is to turn good wells into great wells, and to make bad wells not quite so bad. Try to make every well 10% better and in the long run you'll have a lot more success.

Take Care of Your Master Valves

Master valves are your last line of defense on a well. Without a reliable master valve, your well control is compromised, and that is never a good place to be. I have had the opportunity to work on a lot of old, mature wells, some which still have a lot of pressure, and it amazes me how many of them have master valves that are either leaky or extremely difficult to turn. If you were in trouble and had to close that valve quickly, you'd be out of luck.

Why does this happen? The answer is pretty straight-forward. Valves need regular maintenance just like any other mechanical device. It costs money to change the oil in your car, but you do it anyway because your car valuable and the cost of failure is large. Master valves are also extremely valuable. Take care of them. Keep your valves greased up and when they need repaired or replaced, spend the time and money to do it the right way. In the grand scheme of things, this is a small expense to keep your wells safely under control.

Address Liquid Loading Early

Engineering Tip: Address Liquid Loading Early and Save Yourself Headaches​
Liquid loading in a producing well is an inevitable reality for almost every well. Eventually, the stored energy in a well falls below the minimum threshold to lift fluid. This is a fairly straight-forward thing to predict with some basic critical velocity equations. It takes only 5 minutes to calculate the minimum flowrate necessary to lift fluid out of a well. With this number in mind, you can predict with surprising accuracy when a well will start to load up. If you know when to expect liquid loading, it's really easy to identify it when it starts to happen. You're gas and liquid rates will drop off quickly and you're well will appear to decline exponentially faster than it was.

As soon as you see this happen, address the issue right away.

There are many ways to address liquid loading: soap, plunger lift, submersible pumps and pump jacks are the most common methods. Regardless of which artificial lift method you choose, the key is to get on the issue quickly, before the well gets so loaded that it becomes difficult to get back. If wells are neglected and they get loaded up in a major way, it can be challenging and expensive to get the well kicked off again. I've seen wells get so loaded up that they require coil tubing and nitrogen to get them flowing again. This is expensive, much more expensive than a simple plunger lift or chemical setup.

We know that wells are going to load up. No one should be surprised by this. Have a plan in place to deal with this and don't act surprised when it happens. If you have an artificial lift plan in place, then you can quickly implement the solution as soon as the liquid loading occurs. This will save you money in the long run, and it will prevent downtime on the well.

Bonus Tip: Put Tubing In The Well Early

Once again, you know the well is going to load up. It's going to need tubing. Have you every tried to unload a well without tubing? It's like fighting with one hand tied behind your back. Just put tubing in the well and save yourself the headache. If it was up to me, every well completion would include tubing (*and all the production engineers cheered*).

Wells load up. Don't be caught with your pants down (or your well down). Have a plan, identify it quickly, and fix it. You'll thank me later.

Don't Ignore Production

Engineering Tip: Don't Ignore Production​
In upstream oil and gas, production is the only phase in the life of a well where you actually MAKE money. Every other department spends money. Drilling and Completions spend A LOT of money. Building pipelines costs A LOT of money. And where does the money come from to pay for all of these things? From Production!

It may seem obvious that Production is important but if you look at how many companies operate, they seem to place very little value on production. Why is this? It's because all of the big budgets, and therefore all of the attention and focus, is at the drilling and completion level. This is not to say that we shouldn't put a lot of attention on drilling and completion. We should, because there is a lot of money at stake. However, I've seen many many times where decisions are made in the drilling and completion phase, that have huge impacts on future production, yet there is almost no thought given to the impact on production.

For example, how often do we see new wells get completed with high tubing set points, or packers downhole? These decisions have a major impact on the ability of that well to keep up production over time. And far too often these decisions are made by drilling and completion engineers, with no consideration on how this will limit production over time. Too often the attitude is, "TD the well, complete it, move on and never look back".

Production is the only revenue stream for an E&P company. It is literally the life-blood of the company. We should start to take it a little more seriously and quite treating it as the red-headed step child of oil and gas operations. When the money is getting tight and the budgets get slashed, you'll wish that you had prioritized your revenue stream a little more.

Measured Data Is Always Better Than Calculated Data

Engineering Tip: Measured data is always better than calculated data.​
In this industry we are often faced with a decision of whether or not to measure a meaningful data point. It is often cheaper in the moment to calculate a data point rather than measure it. However, measuring something directly always leads to more accurate data. It doesn't matter if its pressure, flowrate, temperature, or any other physical data point - measuring it directly is more accurate than calculating it.

I'll give you an example: At FyreRok, we run a lot of downhole gauges to measure bottomhole pressure. Now, we can calculate the bottomhole pressure based off of surface pressure, but this introduces the potential for error. We always try to run downhole gauges as often as possible to ensure the best data.
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