Clearly Define Your Well Test Objectives

As with most engineering disciplines, well test engineering can be complex. There are a lot of things to consider and plan around, and it's easy to get so caught up in the details that you lose sight of the end goal. There are a lot of things you can learn from a well test: permeability, skin factor, boundary conditions, reservoir pressure, flow geometry, deliverability , fracture pressure...the list goes on. All this information is collected in different ways, and many of them require completely different types of well tests. Stop and ask yourself, "why am I doing this test?"

Ensuring that the money you invest yields a good ROI is crucial. Specifically, you must ensure that your investment gives you the information you want.

Some of you are probably saying, "No kidding, Captain Obvious." Of course you would want to understand your objectives before moving forward with a project, but I have seen far too many instances where someone chooses a well test procedure because, "that's the way we've always done it".

Does this sound familiar? Someone designs a well test in 1984 with a specific goal in mind. 40 years later, a new batch of engineers working for the same company, is still running that same well test, but they're not really sure why. In situations like this, there is probably a lot of room for improvement and optimization. It is likely that some of the objectives and/or standards have changed in the past 40 years, and there is probably a better well test design out there.

Do you want to update your well testing procedure, but don't know where to start? That's what we are here for. Well testing is our bread and butter and we help oil and gas companies design better well testing programs all the time.

Better Test Design + Better Data Collection = Better Analysis

By the way, this concept can also be applied to a lot of other types of projects, not just well testing. If you are working off an old, archaic procedure, ask yourself if there is a better procedure out there.

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).

Be Skeptical of Models

Engineering Tip: Be Skeptical of Models​
Models. We deal with them all the time. Frac models, reservoir models, fluid models, models of models. Lots and lots of models. But models have two major limitations:

1. Inputs - Models are only as good as the data you put into them. If you have inaccurate or misinformed data, then your model is going to be inaccurate and misinformed. Every reservoir model requires porosity as an input. But porosity can change a lot across the reservoir. Often times we are using porosity from a core sample and extrapolating across the reservoir. It's better than nothing, but we need to be realistic about the potential inaccuracy this causes.

2. Understanding of the physics - The universe is a very complex machine. We like to take natural mechanisms and boil them down to one or two variables so that it is understandable. However, most things in nature are an interconnected web of many, many variables. Let's take fracture modeling. People love to reduce fracture growth down to a simple model of pressure and injection rates. In reality, there are a gazillion things that impact fracture growth. We love simple models that show nice, parallel, predictable frac wings, when in reality, we often get a spider web of fractures that grow in many different directions.

Models will always give you an answer. Whether or not that answer is accurate is a different question entirely.

And don't get me started on climate change models...

Please don't read this and think that I am anti-modeling. Models are a useful tool, but they are a tool and not an exact science. When you use a model, be a little skeptical of the results. Ask questions and compare it to other information and intuition that you have. If the model gives you something that seems unreasonable, dig deeper and ask more questions.

At the end of the day, human intuition and historical data can be just as powerful a tool as modeling. Let's not get too carried away with models.

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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