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).

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.

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!