Negative pressure testing, also know as inflow testing, offers oil and gas companies a reliable way to test well barrier integrity. These tests are so critical that regulators have stepped in to require them via the Code of Federal Regulations (CFR) Title 30 § 250.721(g). During a negative pressure test, displacement occurs through the use of a lower density completion fluid, and with pressure lowered, the well barrier is monitored for leaks. The process is highly controlled, which makes these tests incredibly safe to perform.
The upsides to negative pressure testing are numerous. Yes, such tests are required for anyone who operates an oil or gas well, but they should be viewed as gifts rather than curses. They’re an effective tool for ensuring safety at the drill site, enabling efficient operation of a well and avoiding costly damage down the line.
Here are a few reasons for why negative pressure testing is so important.
The wellbeing of the crew should be top-of-mind for any oil or gas company, whether workers are stationed on an oil rig or spend their time at some other type of well. Drilling is a risky job, as is maintaining a live well. Every step should be taken to ensure your team is protected, and that starts by keeping a close eye on every potential failure point.
Negative pressure tests can identify well barrier integrity issues before they develop into something more serious. If a leak exists, the test will catch it, giving you an opportunity to address the issue and possibly prevent injury or — in the case of a catastrophic blowout — loss of life. That is reason enough to take these tests seriously.
The purpose of your well is to extract oil or gas from the earth, and to do so efficiently. You want optimal performance — a benchmark you can’t achieve if there are issues with well barrier integrity.
If you fail a negative pressure test, that is a sure sign the well production recovery process is being impacted. When that’s the case, you are operating inefficiently, consuming the same amount of energy while falling below your peak recovery potential. Regularly scheduled tests help you diagnose slips in performance — even before you reach the point of failure — so you can make improvements and keep your well operating at a high level.
Not every well barrier breach develops into a disaster. In fact, some simply render a well inoperable for a not-insignificant period of time while repairs are made to fix what’s broken. This is what makes a proactive process like negative pressure testing so crucial. By performing tests at regular intervals, you can get a sense of how your well barrier is going to hold up in the future.
Negative pressure testing grants you knowledge about which aspects of the barrier are in good shape, and provides insight into where integrity is starting to slip test after test. With this data in hand, you can plan for maintenance ahead of time instead of being forced into it at a moment’s notice. Should some sort of failure occur, you could be looking at costly repairs and replacements. Reconditioning your system while everything is still intact will save you a lot of time and a lot of money.
IPT has decades of experience helping the oil and gas industry perform negative pressure tests. Countless companies rely on SureTec for consistent and accurate testing, and SureView for reviewing data and documenting trends both on-site and remotely.
Contact IPT today for more information on our digital testing solutions, and to learn more about how SureTec and SureView contribute to safe operation, efficient production, and cost-effective maintenance.
In an industry first, IPT Global has enhanced their testing capabilities by connecting with downhole pressure gauges. SureTec software was successfully connected to data feeds from permanent downhole gauges in the completion in parallel to surface data feeds.
This integration enabled verification of pressure above and below the SCSSV valve and the top of the fluid loss isolation barrier valve in the lower completion. Simultaneous instances of SureTec were run, verifying the equipment during the completion installation and provided high confidence and assurance of the effectiveness of all barrier elements.
This breakthrough was performed on the recompletion of BP’s XP1 project and was accomplished by trapping pressure between the SCSSV and fluid loss valve.
The tests were validated using the upper gauge and applying inflow test criteria across the SCSSV, while at the same time using data from the Lower Gauge and applying positive test criteria to validate the completion between the SCSSV and the lower completion fluid loss valve.
The result was a successful verification of the completion barrier elements, proving the SCSSV in the direction of flow and providing remarkable confidence that the completion was installed with pressure integrity. Simultaneous testing added operational efficiency and reduced overall completion installation time.
The execution of the test required collaboration between IPT (field and software SMEs), the operator, and the gauge manufacturers. Once the correct equipment IP and Modbus addresses were aligned with the SureTec software, a thorough validation (and troubleshooting) process was completed to identify the individual pressure sources in SureTec and ensure the correct data was being received.
This is yet another notable example of IPT innovation and collaboration with clients to effectively enhance operations and increase critical path efficiency. Well integrity is crucial during well construction and completion operations; the application of SureTec eliminates subjectivity and future risk for IPT customers.
The BP Completions Engineer expressed his satisfaction with the SureTec setup, and the enhanced assurance it provided.
Lessons learned from this achievement are now part of the IPT “best practices” and will be applied in future installations. Ongoing research and improvements to processes and technology solidify IPT Global as the leader in Well Integrity and Assurance.
Negative testing, also known as inflow testing, offers oil and gas companies a reliable way to test well barrier integrity and remain in compliance with the Code of Federal Regulations (CFR) Title 30 § 250.721(g). During a test, displacement occurs through the use of a lower density completion fluid — thus lowering pressure — and the well barrier is monitored for leaks.
For a long time, Horner analysis has served as the industry standard for the study of negative test results, with the Horner plot being the de facto choice for recording such results. There’s now evidence to suggest, however, that this has been a mistake. The truth is Horner analysis and Horner plots aren’t just discouraged in this testing scenario — they really shouldn’t be used at all. Here’s why.
Horner plots are most often used to test buildup pressure. Results are recorded onto a graph with a sloped line, where the line, according to Crane’s Petrophysical Handbook, represents “a cross plot of buildup (or drawdown) pressure (Pi) on the Y-axis versus a dimensionless time coefficient (HTi), usually called Horner Time, on a logarithmic X-axis.”
Horner analysis utilizes the same radial flow equation used to record pressure build up inside shut-in wells. Later, it was discovered this equation had enough in common with thermal diffusion equations for it to predict static formation temperature. When the connection was discovered that inflow tests created thermal effects and subsequently caused flowback, Horner analysis appeared to be a logical choice for interpreting test results.
The issue with this approach, unfortunately, stems from details that are seemingly ignored and assumptions that must be made. Use of Horner analysis — and the Horner plot — requires one to disregard temperature change, heat generation, and heat transfer between fluids. It also assumes system and formation temperature will remain the same with a change in pressure, formation temperature is not impacted by distance from the wellbore, and temperature is consistent at the wellbore. None of these are true.
As a result, even the tiniest tweaks to variables can result in a Horner plot trend line that is misinterpreted. This led James Peyton to conclude in a 2021 paper that Horner analysis “should not be used for analyzing flowback or pressure buildup during an inflow test.” Fortunately, a more accurate testing method exists.
Some methods of validating inflow tests, such as Horner plots, are either unsound scientifically or are prone to misinterpretation. This problem is eliminated with SureTec.
SureTec records tests with an unmatched level of precision and consistency. And because test results are digitally compared to the required pass-fail criteria, an objective result is produced.
Increased accuracy in testing is not the only benefit of going digital with SureTec. Our SureView platform enables viewing of testing data locally or remotely.
And if you need help with any of our solutions, IPT is ready to help. Experts at our Real-Time Operations Center are on hand 24/7 to provide support and answer any questions.
Contact IPT today to learn how digital solutions like SureTec and SureView can make negative testing more accurate and help you access your data from anywhere.