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.

TechTAC® joins this SPE Tech Talk to discuss the business impact of deploying slim-style tubing anchor catchers and highlight the case studies of three operators who have seen substantial improvements in production and uptime making that one simple downhole change.

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.

In wells with sucker-rod pumps, tubing anchor catchers, or TACs, can stabilize the production string. That stability creates higher pump efficiency and minimizes wear on rods, tubing, casing and the rod pump.

However, in addition to the benefits, standard B2-style TACs, along with other traditional anchor designs, are also susceptible to several common problems that can hinder production.

In contrast, the design of the TechTAC® Slimline® Tubing Anchor Catcher creates a reduced OD, which in turn provides up to 245% more flow-by area between the anchor and the casing ID.

According to an independent CFD study, that increased flow-by area means the Slimline® creates far less pressure drop, turbulence and turbidity than a standard B2 anchor.

That free flow of fluid helps mitigate the frequency and impact of stuck anchors and gas locking, which in turn can help operators significantly reduce costs and increase production.

A senior completion foreman with a U.S.-based oil and gas company described the benefits this way: “We have one well that had to be pulled every 3 months due to scale. After installing a Slimline TAC, we didn’t need to pull it for 2 years.”

In wells with sucker-rod pumps, tubing anchor catchers, or TACs, can stabilize the production string. That stability creates higher pump efficiency and minimizes wear on rods, tubing, casing and the rod pump.

However, in addition to the benefits, standard B2-style TACs, along with other traditional anchor designs, are also susceptible to several common problems that can hinder production.

During a recent Tech Talk, hosted by SPE and sponsored by TechTAC®, our team fielded several questions from the audience. All the questions were insightful, but one of them stood out. After seeing many varied applications for the Slimline® Tubing Anchor Catcher, the attendee was rethinking her preconceived idea that the Slimline® TAC was just a specialty tool. She asked:

“Based on the data you’ve shared, it sounds like [the Slimline® TAC] isn’t just a specialty tool. Could it be used in any well?”

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.”

The use of oilfield anchors in oil wells brings numerous benefits, all contributing to the efficiency, safety and cost-effectiveness of oil extraction. Here are some key benefits:

Reduced Wear and Tear. Oilfield anchors, or tubing anchors, minimize the vertical movement of the tubing string, which significantly reduces wear and tear on both the tubing and the associated equipment. This reduction in mechanical stress extends the lifespan of the well components, leading to lower maintenance costs and fewer operational interruptions.

Enhanced Safety. The stabilization provided by oilfield anchors enhances the overall safety of the well operation. Preventing uncontrolled tubing movement reduces the risk of accidents and equipment failures, protecting both the workforce and the environment from potential hazards.

Improved Pump Efficiency. In wells that use rod pumps or other artificial lift systems, oilfield anchors improve the efficiency of the pump by keeping the tubing string stable. This stability ensures that the pump operates at optimal performance, leading to better extraction rates and reduced energy consumption.

Cost Savings. The combination of reduced maintenance, extended equipment lifespan, and improved operational efficiency translates to significant cost savings for oil companies. By investing in quality oilfield anchors, companies can achieve a higher return on investment through more reliable and efficient well operations.

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.”

In the oil and gas industry, maximizing efficiency and safety are paramount. One of the critical components that contributes to these goals is the oilfield anchor. Often called a tubing anchor, tubing anchor catcher or TAC, this relatively small piece of equipment plays a significant role in ensuring the smooth operation of oil wells. This post will delve into the purpose and benefits of oilfield anchors, highlighting their importance in the extraction process.

In addition to the value of the catcher feature, a traditional mechanical tubing anchor catcher is especially useful for:

Well repairs that don’t require replacing the anchor. Many well repairs do not require the replacement of the production tubing and anchor. If just a rod, valve or surface equipment need to be replaced, the entire production string may not need to be pulled. However, with a tension anchor, once the upward pressure is released, that anchor disengages. In contrast, a tubing anchor catcher would keep the production string in tension while the repairs are made.

Well designs where cost is a key consideration. Depending on the model, a quarter-turn or hydraulic tension anchor can cost 2–3 times more than a comparable mechanical tubing anchor catcher. In some use cases, that higher cost is well worth it; but in others, it’s prohibitive.