#techtac

With traditional B2-style TACs, the benefits gained from securing a well’s tubing must be balanced against the negative effects of the anchor itself. A traditional TAC essentially creates a “choke point” within a well, because the annular space between the anchor OD and the casing ID is so small. In turn, that choke point can create a pressure drop that leads to the formation of scale, iron sulfide and paraffin. When those minerals are present, plugging is often the result. Plugging occurs when sediment bridges off on top of the anchor and effectively cements it in place. No fluid can fall past the anchor, and no gas can flow up.

The Slimline® TAC — and variations like the Slimline® Full Bore TAC and Slimline® QuickSet™ TAC — mitigate these issues. The Slimline anchor’s reduced OD creates up to 245% more flow-by area than a standard B2 TAC. That increase allows the Slimline TAC to deliver the benefits of anchored tubing without creating additional challenges around scale formation and gas locking.

Petroleum engineers well understand the value of including a tubing anchor catcher (TAC) in deep-well downhole production strings. With relatively shallow wells of 5,000 feet or less, however, the consensus is not as universal.

Sometimes operators will leave shallow wells unanchored to maximize profit margins. The rationale is that the additional cost of adding a TAC would outweigh any resulting gains in productivity. But research tells a different story.

Use caution when running the anchor in and out. While this piece of advice sounds obvious, it’s especially important when working with the Slimline® QuickSet™. Because the QuickSet™ anchor can be set and released in 1-to-3 turns, as opposed to the traditional 6-to-8 turns, being cautious and deliberate about how the anchor is run in and out of a well is even more important than with a traditional TAC.

Put a right-hand turn in the tubing occasionally. To prevent the tool from setting while running in, it is advisable to occasionally (about every 5-to-10 stands) put a right-hand turn in the tubing. Doing so will help prevent the anchor from setting prematurely. (If you are running a right-hand set TAC, put a left-hand turn in the tubing.)

Use a pipe wrench instead of power tongs. When adding that right-hand turn every 5-to-10 stands, it’s important to use a pipe wrench instead of power tongs. The pipe wrench will allow you to feel when the tool is fully released and avoid damaging it. If you use power tongs, you could over-release the tool and shear the pipe plug. In turn, the anchor could bind up and fail. If there are times when it isn’t feasible to use a pipe wrench to add the right-hand turn – such as in very deviated or deep wells – the power tongs should be set to slow speed.

TechTAC® has a network of more than 130 Authorized Dealers throughout North America. That number includes large national suppliers and small local pump shops. In either case, the TechTAC® team is available to provide technical support for any anchor-related issues. Some of the most common questions our shop managers field include:

What steps can we take to mitigate or eliminate anchors setting while running in or out of the well?

What is the best way to set a tubing anchor in deep or deviated wells?

Do you have a TAC that will work in a well that’s been patched?

What are the measurements and specifications of a Slimline® anchor compared to a standard B2 TAC?

What is the shear strength of your anchors?

What are the most common mistakes people make when assembling a tubing anchor?

What casing range does the 5.5″ Slimline and standard TAC cover?

What is the ID of a 5.5″ Slimline?

Can we set a TAC in or below our perforations?

Why is everyone who works at TechTAC so damn sexy?

TechTAC® does not sell directly to production companies. However, that doesn’t mean our shop managers don’t field a lot of questions from them. In developing the best downhole tool assemblies for their wells, engineers will sometimes use our team as a resource, just like dealers will. Those engineers often want to discuss the impact of different tubing anchor designs on the flow dynamics of a well.

In addition to those one-to-one conversations, TechTAC® has also produced an Engineering Info Packet as a self-service resource for inquiring PEs. The packet is available at no cost and contains a host of valuable content, including:

An independent computational fluid dynamics (CFD) study comparing the Slimline® TAC vs. a standard B2 anchor across multiple flow parameters, such as pressure drop, velocity and turbulence

Technical specifications and use cases for the Slimline® TAC

Testimonials from TechTAC® customers

A list of TechTAC® Authorized Dealers

One of TechTAC’s core values is to earn our customers’ trust with every interaction. Fulfilling that goal means connecting them with knowledgeable people who understand tubing anchor catchers and common downhole challenges. That’s why TechTAC® doesn’t have “salespeople” in the traditional sense of the word. Instead, we have shop managers who can offer TAC technical advice and not just an invoice.

“All of our shop managers – from Williston to Midland – began their work at TechTAC building, breaking down and redressing anchors,” said TechTAC® President Brad Crist. “They’ve also spent hours working side by side with service companies disassembling and examining equipment after it comes out of the well. “That experience gives them a deep understanding of the mechanics of tubing anchor catchers,” Crist added. “It also makes them experts in best practice setting and releasing procedures, assembly tips, recommending the right anchor for different well conditions, and many other areas.”

Many varieties of oilfield anchors, or tubing anchors, are sold to accommodate the needs of different well designs. No matter the style, however, the anchor’s primary purpose remains stabilizing the production string. For decades, the industry has relied on standard B2 tubing anchor catchers to perform this important function. Unfortunately, standard B2 anchors can also inhibit a well’s production. A study by Echometer Company examined the production rates of 11 oil wells. Each well had high fluid levels and the pump intake was located below the perforations. Yet despite these seemingly favorable conditions, nine of the wells showed a pump fillage rate of less than 90%.

According to the report: “In these wells that exhibited high fluid levels … the fluid distribution in the wellbore below the liquid level was not uniform. The wellbore in the vicinity of the pump intake was primarily filled with gas with a minimal volume of liquid. …The presence of a tubing anchor set high above the pump intake is considered to be the main cause of this uneven distribution of fluids in the wellbore.

“The particular tubing anchor used in these wells provides a flow area of about 2.9 square inches between the body of the anchor and the casing compared to a flow area of 14.4 square inches between the casing (4.892-inch ID) and the tubing (2.375-inch OD). The small flow area could increase the velocity of the upwards flowing gas to the point where it would be difficult for liquid present in the upper part of the annulus to flow downwards past the depth where the tubing anchor is set. The anchor would essentially act as a choke and also cause an increase of the annular back pressure.”