A privately held exploration and production (E&P) company operating in the Denver-Julesburg (DJ) Basin was facing difficulties boosting production from its mature wells as the basin’s gas‑to-oil ratio (GOR) trended higher.
Part of the E&P company’s challenge was inherent in the economics of maximizing the efficiency of mature wells on artificial lift. Once a well reaches a stage of steep production declines, investing in expensive stimulation techniques or equipment rarely makes financial sense. More modest investments, such as installing a simple gas separator, can also be largely futile if the well also uses a standard tubing anchor catcher (TAC) above the pump, as many of the region’s wells do.
For more than a decade, it has been recognized that traditional B2-style TACs can create a chokepoint within the well because the annular space between the anchor’s outside diameter (OD) and the internal diameter (ID) of the casing is so small (URTeC 1918491). In many cases, the chokepoint invites plugging, traps formation gas, and creates a significant pressure drop within the well, accelerating the formation of scale.
Possible Solutions, Unique Circumstances
While slim-style TACs have proven very effective at allowing formation gas to flow around the anchor and up the annulus of a well without disrupting production, situations may arise where a TAC with a reduced ID is not compatible with a company’s preferred well design. For example, factors such as excess sand or regional preferences can influence the specific downhole placement of a tubing anchor.
In the case of these mature wells with 5.5‑in. OD, the operator chose 2⅞-in. tubing to accommodate a large pump and required that the TAC be placed above the seat nipple with the pump running through it. With a 2-in. ID, a 5.5-in. “slim” TAC can be set above or below the pump with 2⅜‑in. tubing, but only below the pump when 2⅞‑in. tubing is used.
That meant this operator had to use a standard B2-style TAC in its wells, which in turn led to struggles with gas interference and plugging. The E&P company wanted to find a solution that could meet the design requirements of its wells while also promoting better flow-by to minimize the risk of gas locking.
A Slim Anchor With a Fullbore ID
Working with the technology developer, the production company chose to test a new TAC system. The anchor leverages a novel design that allows it to provide significantly more flow-by area around the anchor while still maintaining an ID large enough to allow rod pumps designed for 2⅞-in. tubing to pass through it. If successful, the new TAC would help to mitigate gas interference and increase production across three mature wells while meeting the requirement to be placed above the seat nipple.
Three prototype anchors were manufactured and shipped to the production company via an oilfield equipment supplier in September 2024. By mid-November, all three TACs were downhole and in production. Each was set above the seat nipple with the pump running through it.
Early Results: 0 to 30 Days After Deployment
According to the E&P company, the rig crew encountered no issues running in the prototype TACs. One of the anchors did have to be removed shortly after running in, but not because of a deficiency with the TAC. Rather, the tubing had a hole in it.
However, the unexpected removal did give the rig crew a chance to test releasing and then rerunning the TAC after it was redressed, which proceeded without incident. The E&P reported that the TAC was simple to set and release and that no issues were encountered during installation or removal.
The E&P also noted a significant increase in the volume of gas coming out of the wells, suggesting the anchor’s slim design was working well for gas-interference issues in wells with 5.5-in. casing. Specifically, the wells each saw a 25 to 30% increase in the volume of gas being discharged on the surface.
Additionally, pump-fillage rates improved in each of the wells, according to dynamometer card data. Production staff within the E&P reported increased pump fillage on wells that were converted to the prototype TAC, with increases typically ranging between 15 to 25%.
Longer-Term Impact: 1 to 6 Months After Deployment
Over the next 5 months, all three mature wells continued producing without any need for workovers or interventions.
The TACs continued to hold tension in the production string, enabling efficient operations and avoiding unnecessary wear and tear. The increased volume of gas coming off the wells remained consistent, mitigating the risk of gas locking, despite the gassier composition of this area of the DJ Basin (East Daley Analytics, 2025).
The most significant benefit, however, came in the form of increased production. Without making any notable changes to the production strings of these three wells other than using the new prototype anchor, each went from producing roughly 40 B/D to almost 80 B/D, marking a nearly 100% increase.
Comparison Study
The increased production experienced in the three test wells is largely tied to the greater flow-by area provided by a slim-style anchor. A recent independent computational fluid dynamics (CFD) research study compared a 5.5-in. standard B2 anchor with the new slim-style prototype TAC of the same size.
The study used CFD to compare gas flow within the annular space around two different types of a 5.5-in. tubing anchor catcher. Among the key findings were that the standard B2 TAC demonstrated a significantly higher level of kinetic turbulence and vorticity compared with the slim TAC. This turbulent flow, which can trap formation gas and lead to deposits of scale, paraffin and iron sulfide, is largely the result of the reduced flow‑by area of the standard B2 TAC vs. the slim‑style alternative.
According to the report, Fig. 1 illustrates how the “observed abrupt changes in the pressure field along with the potential presence of flow field obstacles in the case of the standard TAC is expected to generate more turbulence within the flow field along the TAC in comparison with the [slim-style] TAC.”
The report also noted that “the vorticity strength in the flow field of the standard TAC is expected to be significantly present in comparison to that of the [slim-style TAC’s] case,” as illustrated in Fig. 2, which shows the vorticity field with strengths ranging between 0.0001 and 0.005.
Conclusion
For wells struggling with persistent gas locking or scale issues that necessitate placing a TAC above the seat nipple, a new prototype slim TAC with a fullbore ID offers an alternative to conventional anchoring solutions. In the DJ Basin, one E&P operator adopted this slim-style TAC, enabling higher production from mature wells despite a high and rising GOR.
For Further Reading
DJ Basin Shifts to a Gassier Play, East Daley Analytics. (2025).
URTeC 1918491 Tubing Anchors Can Reduce Production Rates and Pump Fillage by J.N. McCoy, O.L. Rowlan, C.A. Taylor, and A.L. Podio.
Brad Crist is the president and owner of TechTAC, a tubing-anchor-solution provider that operates across several major US basins. Crist acquired the business in 2023 after more than 2 decades with critical materials management firm Savage Companies, where he held several leadership roles. He most recently served as president of the firm’s infrastructure sector, overseeing about 140 locations and 2,500 employees across the US, Canada, Mexico, and Saudi Arabia. His background includes managing operations at refineries, petrochemical plants, and transload facilities. Crist holds an MBA from the Wharton School of the University of Pennsylvania and a BA in economics from Brigham Young University.