Frac Plug Testing

ISO & API have developed several testing protocols that downhole tools must follow to claim pressure and temperature ratings. Many people will be familiar with the V rating as designated by IS0 14310 and API 11D1. The summary of these tests is as follows:

V0 - Gas Test with Axial Loads & Temperature Cycling
V3 - Liquid Test with Axial Loads & Temperature Cycling
V6 - Manufacturer Defined Testing

When a provider states their packer is rated V3, this requires a specific procedure and customers understand how it will perform. There are similar ratings like this for production packers, swellable packers, safety valves, etc. One class of tools without an equivalent testing specification is Frac Plugs. How does a customer know how a plug will perform? Without a testing standard, all plug companies have individually developed their protocols for verifying the viability of their design under different conditions. Their testing goal is to verify the plug will not fail and cause losses for the business.

The V ratings described above prove a packer can hold a certain pressure with minimal leak rate under different conditions, e.g. mandrel under tension and compression and or with temperature cycling. The procedure is deigned to accurately recreate the pressures, temperatures, and forces experienced in the well. A packer is run slowly into the well, set, and then seals under the pressures and temperatures of the well. It is not a dynamic system.

Frac plugs are different; they must achieve success during run-in, setting, frac, and then mill up easily. Verifying performance for each challenge cannot be done with one lab test and some of the challenges are difficult to replicate. Each provider proves the performance of their plug differently. When deciding on what plug to choose for your well it is important to understand what procedure the company follows to allow them to claim a 10,000 psi or 500 ft/min run in speed rating.

I familiar with several different methods to test each challenge. Each method has positives and negatives for determining the success of a plug in the well. I’ll share the challenges associated with each stage of the plugs deployment, testing methods, and pros/cons for these methods.

Run In

The Plug & Perf procedure begins with the wireline BHA (plug, setting tool, and perf guns) drawn into the wireline lubricator. The lubricator is installed on the wellhead, allowing the wellhead valve to open so the BHA can drop into the well. As the plug falls through the vertical section of the well the fluid accelerates upward relative to the plug, applying an upward force against the plug components. Additionally, the accelerated fluid creates a low-pressure zone, which can cause flexible components (element) to move.

The only way I am familiar with testing this is to keep the plug steady in casing and pump water around it while monitoring the pressures in the system. Eventually, a pressure spike will indicate something about the plug has moved. Recommendations from the provider will ensure critical velocities are avoided during operations.

I have developed a run-in/pump-down calculator that will tell you the velocity of fluid past a plug when falling in the vertical.

Pump Down

When the plug reaches the kick-off point, the operator will turn on the pumps to start the pump down phase of the plug operation. During run-in, the concern is fluid velocity running from the bottom of the plug upwards. During pump down, fluid rushing past the plug downward becomes the concern. The pump-down fluid velocity effect on the plug is tested in the same way as run-in, though the fluid is pumped the opposite way. When calculating the speed of the fluid passing the plug during pump down, you have to take into account:

The velocity of the plug
Pump rate
Casing Size
Plug OD

The pump-down calculator also provides the fluid velocities around the plug during pump-down.

A secondary concern during pump down is the plug OD wearing down as it drags along the casing wall. This wear, if excessive, will expose the buttons/wickers on the slips causing a preset. Plug wear is a difficult test to perform and would be restrictively expensive to replicate on the surface. When choosing your plug provider, especially if it is a relatively unproven technology, it is critical to understand the amount of gauge protection for the slips. The difference between the plug and buttons/wickers OD should be a minimum of .05-in per side.

Setting & Pressure Testing

A Baker, Owen, or Disposable setting tool sets the plugs in a well. Each setting tool contains a power charge that, when ignited, creates pressure to exert mechanical force to set the plug. When testing, using a power charge is riskier than what a safety group will allow. To avoid explosions, plug providers convert an explosive setting tool to use hydraulic pressure.

In the well, the casing is cemented in place, to support the pipe. In the lab, test casing can either be actual casing cemented inside another joint of casing or mechanical tubing that is machined to replicate the ID of the casing required for the test. Both of which must provide enough safety factors to ensure the casing does not burst during testing. Bull plugs connect to and contain the pressure on the ends of the test casing.

To start, the plug installs on the setting tool similar to field operations. The plug and setting tool is lowered into the test casing when an engineer uses a high-pressure pump to pressure up the converted hydraulic setting tool. The hydraulic pressure will cause the setting tool to stroke and set the plug. The test engineer will remove the setting tool, fill the casing above the plug, and install the top bull plug. The top bull plug will contain an NPT port for connecting the high-pressure pump to the test fixture. Once the completing the test fixture, the pump will apply pressure to the plug to determine the pressure rating.

The ISO and API ratings discussed above have specific acceptance criteria for calling a packer qualified. For instance, only losing 1% of pressure over a 15-minute hold. Again, with the lack of a frac plug standard, it is up to the providers to develop their success criteria. I have experienced providers applying the same methodology to their plugs as a V-rating. I've heard of providers maintaining the pressure above the plug for a set time, even if it requires continuous pumping. I have experienced 15-minute, 30-minute, and 1-hr pressure holds. One operator in Canada has a specific qualification procedure that providers must follow and pass to supply plugs, including several pressure cycles at different intervals. For large operators, this is a good strategy for vetting potential tools. Develop qualification requirements and have the providers test to this standard. If the opportunity is large enough, the providers will do the testing (in most instances at their own expense).

Handling Temperature

All plugs will have a temperature rating in addition to a pressure rating. Providers have developed different procedures for handling temperature as well. Several examples include:

Water Soak + Test
- Soak the plug in water at 200F
  - At ambient, water boils at 212F
- Heat the test fixture and water to 200F
- Set the plug at 200F and install the top bull plug
- Apply pressure to the fixture and heat to 300F
- Perform the pressure test
Oil Test
- Heat the test fixture and oil to 300F
- Set the plug at 300F
- Cap the test fixture and perform the pressure test
Set then Heat
- Set the plug in the fixture at ambient temperature
- Heat the entire fixture and plug to 300F
- Perform the pressure test

Each of these is a viable strategy for handling temperature.

Mill Up

For testing the mill up of plugs suppliers typically have a setup that will allow rotation of the bit, force against the plug, and a pump to flow fluid through the bit. The force against the plug is done by a hydraulic ram, allowing up to 10,000 lbs to replicate the weight-on-bit. These tests are challenging for recreating what will happen downhole. They are for comparing plugs based on the performance during surface tests, not for how the tool will perform downhole. The challenge for this testing when compared to the actual downhole conditions include:

What happens when you mill through multiple plugs
- I've heard that using carbide buttons for a plug is fine for mill-up performance if you have less than 15 plugs in the well. With more than 15 plugs the buttons ball up and create issues. This would never come to light during a surface milling test.
Plugs at temperature
- Before the mill up, the plugs have been at temperature for hours or days in some circumstances. The material is going to respond differently at 250F than it will at ambient temperatures
The violence of Drilling with a Motor
- At 100 RPM with 10,000' of pipe behind it is going to create a much more violent milling operation when compared to a surface operation.
Sand in the Well
- Mill-up operations come after the operator has pumped millions of pounds of sand into the well. A lot of this sand remains or comes back into the well. Much of the benefit of the mill-out comes from cleaning the well of this sand. The sand adds another variable that cannot be replicated with surface tests.

Surface Testing

Oilfield testing is never going to fully recreate what happens downhole, but it is especially hard for frac plugs due to the number of challenges the tool experiences. When selecting a tool for your well it is critical to understand how it has been tested, to determine how close the testing replicates the downhole experience. “No one is going to be fired for choosing Halliburton,” is typically what new suppliers hear when they’re trying to get an operator to try their product. This may be true, but if every operator stuck with this mantra it would severely limit innovation in the industry. Choosing a relatively unproven product could help your operations and certainly will help the industry move further.

14,500+ plugs installed per month, how are they tested?