Reduce Wellbore Storage Time With a Downhole Shut-in

Pressure transient testing is a form of well testing that requires a flow period followed by a shut-in period on a well. The length of shut-in time can vary significantly depending on well and reservoir parameters, such as permeability. A high-perm gas storage well may only require a 1 hour shut-in whereas a low-perm tight sandstone well may require a month-long shut-in. The longer the shut-in, the more expensive the well test and thus anything that can be done to reduce the test duration without compromising the data can be really useful and budget-friendly.

Wellbore storage, which is the first flow phase upon shut-in, will dictate how long the shut-in must be. A well must be shut in long enough to get out of wellbore storage before any meaningful analysis to be done.

Wellbore storage time is a function of several parameters, including permeability, wellbore fluid, and wellbore volume. While we can’t change the permeability, we can reduce the wellbore volume and thus reduce the wellbore storage time. This is where a downhole shut-in comes in play. If we use a downhole shut-in, such as a bridge plug with gauges BELOW the plug, then we essentially reduce the wellbore volume to just that volume between the plug and the reservoir. This method can greatly reduce the wellbore storage time and thus reduce the overall shut-in time, saving time and money!

If you are curious and want more information about wellbore storage, ​check out this article on our website​.

Run Gradient Surveys Before and After a Well Test

Gradient surveys, which are more formerly known as "static pressure gradient surveys", are a very accurate and straight-forward way to determine the fluid level in a well. This can become a very helpful data point when analyzing a well test, particularly a drawdown/buildup test. A drawdown/buildup test is performed by flowing a well at a specific rate and/or pressure, and then shutting the well in to monitor the pressure during the "buildup", and this is typically done with bottomhole pressure gauges in the well. This test can reveal all kinds of secrets about the reservoir.

Now, because you are flowing the well, often at large flowrates, there is the potential that you could bring reservoir fluid into the wellbore. This fluid influx can be an extremely valuable data point. This is where gradient surveys come in. It is not good enough to only perform a gradient survey AFTER the test, because you don't know what the starting fluid level was before the test. There could have been fluid downhole before the test, or the wellbore could have been dry. The only way to know is to run a survey before and after, so that you can measure the net change in the wellbore during the test.

If you want to learn how to run a gradient survey, check out our Well Insights topic here.

Rule of Thumb - 2:1 Buildup to Drawdown Ratio

Those of you familiar with well testing may be aware of a "drawdown/buildup" test. For those not familiar, this type of test involves flowing a well to create a pressure "drawdown", then shutting in the well to allow for a pressure "buildup". If done correctly, the pressure response during the drawdown and buildup can be analyzed to determine important things like permeability, skin factor, average reservoir pressure, and even boundary conditions.

A really simple rule of thumb for well testing is that a buildup test should be about twice as long as a drawdown. This means that if you flow the well for 1 hour, you should shut it in for buildup for about 2 hours. Often, we reverse-engineer this when designing a test. If you want a larger radius of investigation and you determine that you need a 12-hour buildup, then you should plan to flow the well for 6 hours prior to the buildup.

This rule of thumb is all about data quality and getting the most out of your test. Nothing bad happens if your buildup is too short or too long. You just might have data quality issues. If your buildup is too long relative to the drawdown, you may see some strange things happen on your derivative. These strange things can easily be misinterpreted as reservoir effects, when in reality it's just a mathematical limitation to the pressure transients.

There are a lot of other things that go into well test design as well. If you need help designing a well test, be sure to call your friendly, local well testing specialists (aka FyreRok).

Invest In Information

All of us have big, costly decisions to make. Make the correct decision and you can make your company more profitable. Get it wrong and you cost the company money. Decisions are important, and therefore, having accurate information to work with also becomes important. There is major economic value in good information, and therefore we need to see it as an asset, just like a piece of machinery. Good information is something to be invested in, not an expense to be cut out of the budget.

Let's briefly talk about the difference between expenses and investments. Expenses cost you money, and after the fact you have little or nothing to show for it. The money is gone and it's not coming back. You should do your best to reduce your expenses. Investments on the other hand make you money in the future. Sure, they cost you some money upfront, but (hopefully) that money comes back to you, with profit, in the future. Investments are not something to be eliminated, rather they are something to be carefully and thoughtfully planned out.

Invest in information so that you can make more informed decisions.

A Helpful Formula For Gas Hydrostatic Pressure

Calculating the hydrostatic pressure of a liquid column is straight-forward. In case you need a refresher, the equation is:

P-hyd [psi] = 0.052 * (Fluid Density [ppg]) * (Fluid Depth [ft])

The above equation calculates the exact hydrostatic pressure of a liquid column. But what about for a gas column? The answer is far less straight-forward because the gas is compressible and therefore the density is changing with the depth. There are iterative methods for calculating the hydrostatic pressure of gas, but these methods take some effort. With that said, someone once showed me a simple formula to estimate the hydrostatic pressure of gas, and it gets you surprisingly close to actual data. Here it is:

P-hyd-gas (psi) = 0.25 * (Depth [ft]/100) * (Surface Pressure [psi]/100)

The equation above works for 0.6 gravity gas and if you compare it to actual bottomhole data you will find that it's remarkably close.

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.

Don't Assume All Skin Is Due To Damage

I'm sure you've heard the mantra before, "What happens when you assume? You make and @$$ out of U and ME." That has stuck with me, partially because I've been burned more than once for making silly assumptions, and I'm sure I'm not the only one. We could probably have an entire Engineering Tip just on the topic of assuming, but today I want to get a little more specific.

For those who are not aware, when a petroleum engineer talks about skin, they don't mean the stuff that covers your body. They are talking about "skin on a well", which is a measurement of how good or bad a well is performing relative to it's maximum potential. Simply put, more skin is bad, less skin is good. And we calculate skin through well testing.

With that in mind, here is where I'm going with all of this. When we test a well and get a skin factor, it's easy to assume that the skin is due to damage and that the skin can be removed with a simple workover treatment. While that may be true, there are other forms of skin that can occur on a well, and a simple acid treatment might not due the trick. Other factors of skin include partial penetration, spherical flow, turbulence, inclination and perforations. When you see skin on a well, it's important to take a deeper look and try to understand what might be causing that skin. If you have a well with partial penetration, an acid treatment is not going to solve the problem. The only thing that will remove that skin is deepening the well, which may or may not be practical.

My point here is this, damage is a major factor that contributes to skin on a well, but it's not a guaranteed that all skin is caused by damage. Take a deep look at things and see if there is a bigger issue going on. If not, then by all means go forth and remove the damage. Just don't assume, or you may find yourself haunted by the voice in your head asking, "you know what happens when you assume, don't you?"

If you are interested in learning more about skin on a well, check this out.

Don't Underestimate the Importance of Good Quality Data

Engineering Tip: Don't underestimate the importance of good quality data​
Engineering analysis and modeling are only as good as the data collected. If you collect good quality data, then your analysis and models will be more accurate. If you collect crappy data, all of the fanciest models and calculations won't matter. Collecting good quality data is the first, and perhaps the most important step when arriving at a meaningful and accurate answer. Don't underestimate the importance of good data.

I suspect that most of us are aware this. So why then is it that we often settle for crappy data? It's because the crappy data is cheaper. I'll give you an example that I see often in well testing. Well test analysis relies heavily on bottomhole pressure. The best way to get bottomhole pressure is to run gauges downhole and measure it directly. However, this costs a lot more than just estimating it from surface pressure. So what people often do is go the cheap route and estimate bottomhole pressure from surface, and settle for a less accurate answer. This is a fine strategy and there is nothing wrong with it, so long as you are honest with yourself that the results will be less accurate. We all work for companies who are in the business of making money, and we should all be mindful of costs. However, there is a cost to making decisions on low-accuracy assumptions. Just be mindful of this.

So how do we decide when good data is necessary and when it's safe to cut corners? Well, if the answer you are trying to find is really important and has large implications, then I believe that good data is worth the price. However, if your potential answer is less important and an "estimate" is all you really need, then I'd say that lower-quality data is a fine choice. Keep costs low where you can, so you have a little more to spend where it's really necessary.

Run More Efficient Gradient Surveys

Engineering Tip: Limit Your Gradient Surveys To 4 or 5 Stops​
Static pressure gradient surveys are a great way to understand your hydrostatic pressure. The idea here is to run in the hole with downhole gauges and record the pressure at various depths. This information can give you some key information about your bottomhole pressure, fluid level, and fluid density/pressure gradient. This information is extremely useful when optimizing production from a well.

The mistake many people make is that they run a lot of unnecessary gradient stops. You can calculate everything you need from four survey points, two in fluid and two in gas. A lot of people run gradient surveys with 7, 8 or 9 survey points. This is a bit of a waste of time as there is no additional information gained by all of those extra survey points. The only thing you gain from all of those extra survey points is a larger invoice!

Ideally, I like to run a gradient survey with 4 or 5 five-minute stops. It looks like this:

Point 1: TD minus 1 foot (fluid)

Point 2: TD minus 25 feet (fluid)

Point 3 (optional): TD minus 50 feet (fluid) - gives you one extra fluid point just for consistency, but not necessary

Point 4: Half way between surface and TD (gas)

Point 5: Surface (gas)

The survey points above will allow us to calculate both a fluid gradient and a gas gradient, which tells us everything we need to know. Running 7, 8 or 9 survey points does not add anything to the final calculation, it just adds time and money.

Run Multiple Drawdown/Buildups On A Pressure Transient Test

Engineering Tip: Run Multiple Drawdown/Buildups On A Pressure Transient Test​
Pressure transient tests are a common well testing technique and they are the primary way to identify average permeability and skin factor for a well. In theory, only a single drawdown/buildup is necessary to analyze permeability and skin, as these parameters will not change across different flowrates. However, there is a great benefit to be gained by running multiple drawdown/buildups (at different flowrates) during a single well test. First, you can identify (and quantify) skin due to turbulence, which is the only component of skin that is flowrate-dependent. Additionally, by running multiple drawdown/buildups, you can use the same data to calculate deliverability parameters (C and n), which will yield more accurate AOF and IPR curves.

I prefer to run 3 drawdown/buildups during a single well test. This allows me to get more meaningful data out of my well test, which means I get more bang for my buck!

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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Choose Appropriate Downhole Gauges

Engineering Tip:​ When running downhole pressure gauges, try to run pressure gauges that have a pressure transducer as close to the maximum bottomhole pressure as possible.
For instance, if you are running gauges into a well with 5,000 psi bottomhole pressure, try to run 6,000 psi gauges, rather than 15,000 psi gauges. Doing this will yield more accurate data. Most downhole gauges have an accuracy around 0.02% of full scale, which means that a 6,000 psi gauge has an accuracy of +/- 1.2 psi, whereas 15,000 psi gauges have an accuracy of +/- 3.0 psi. The lesser the gauge transducer, the more accurate the data.​
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Obviously, you do not want to overpressure the gauge, so be cautious when choosing a gauge. Whenever possible, using a lower pressure transducer will generally yield better data.