Reciprocating rod pump (RRP) and progressing cavity pump (PCP) artificial lift systems both rely on rod strings to transfer energy and movement from surface equipment to the downhole pumps. Consequently, any loss in integrity of what can range from 1,000 to 10,000-ft-long rod strings, halts production and requires intervention. This impacts well economics through lost production, associated intervention servicing, and equipment repair/replacement costs.
In recent years, there has been a trend toward rod strings operating in more challenging environments. These include higher fluid rates and depths that increase baseline rod loading; deviated wellbores whose curvature induces bending loads in the rod; and aggressive fluids that can attack and damage the rod. As a result, rod string failures are often one of, if not the most, common reasons for intervention and, accordingly, can significantly impact operating costs.
Although it might seem intuitive that rod string failures would be due mostly to loads exceeding the material strength, this is not the case. RRP loads are primarily axial in nature and vary significantly from the upstroke to downstroke and along the length of the rod string, resulting in a cyclic stress scenario.
While PCP loads are primarily torsional and secondarily axial, both of which are normally relatively steady state, when operating in wellbore curvature, there is cyclic bending and contact that, together, result in a complex multiaxial stress state. With both systems, the cyclic rod string stresses can give rise to fatigue wear at stresses well below their material strength. The rods are progressively weakened over time, potentially leading to component failure.
Since both RRP and PCP systems rapidly generate cycles (5 spm = 11.5K cycles/day; 300 rpm = 432K cycles/day), their associated fatigue behavior is classified as “high cycle,” which encompasses lower stresses, elastic deformation, and failures after 10,000 cycles. In the case of sucker rods, where 25-to-30-ft lengths are joined together, their connections also can be a common source of failure, due either to decoupling or failure within the connections themselves.
Rod string fatigue usually starts at the rod surface, with the initiation of cracks that grow slowly in a first stage with each loading cycle until they reach a critical size. They then propagate more rapidly in a second stage until sufficient rod cross-sectional area is compromised, resulting in final fracture.
Crack initiation on the surface can also occur at natural discontinuities in the as-manufactured rod body; mechanical damage, due to handling or downhole interaction; and corrosion damage, including pits and cracks. In severe cases, failures can occur within weeks or a few months within a new rod string. Often, after an initial failure, there is a series of failures, as the damage develops over time at various rates in different locations. Fig. 1 illustrates a typical rod body fracture in an RRP application.
Fig. 1. Typical rod body fatigue failure in an RRP application.
Industry design practices for RRP rod strings are outlined in API 11BR, “Recommended Practice for the Care and Handling of Sucker Rods” and are fatigue-based, using a Modified Goodman methodology originally customized through extensive rod fatigue testing and field experience. This methodology is well-suited for uniaxial high cycle fatigue, and the industry uses several correlations, depending on rod grade and material.
For Grade D sucker rods, the maximum allowable stresses are as low as 25% of the material tensile strength (T/4) at high-stress ranges and, even with low-stress ranges, are a maximum of 57% (T/1.75). Since the allowable values are for non-corrosive service, they should be reduced through the application of service factors to adjust for unfavorable or challenging downhole conditions. With respect to PCP rod strings, there are no similar standardized design practices; rather, suppliers publish maximum torque ratings for their different products. These torque ratings are normally based on the maximum rod body stress, which occurs at the outside rod surface, being at or above the material yield strength and in cases approaching tensile strength. This static evaluation approach leads to considerably higher localized stresses than associated with the RRP fatigue methodology.
However, because of PCP application experience with failures well below the published torque ratings, fatigue approaches are being used more commonly to downgrade torque ratings when there are cyclic loading components, due to wellbore curvature or pump load variations. Due to the complex multiaxial loading conditions and the lack of representative fatigue test data for the PCP application, this approach is less refined and reliable than that used for RRP applications.
Corrosion, due to its ability to significantly alter the rod surface producing stress concentrations that act as crack initiation points, is frequently a contributor to, or the root cause of, rod string fatigue failures. Fig. 2 shows several examples of rod body corrosion damage.
Fig. 2. Continuous rod corrosion damage.
Based on historical PCP and RRP rod failure inspections, corrosion is a primary contributor more than 50% of the time, when the failure mechanism is classified as fatigue. When corrosion-induced failures occur, the first mitigation option is normally the use of alternative rod chemistries. Rods are available with corrosion-resistant alloying materials, such as chromium, nickel and molybdenum, but the levels combined are usually less than 2%, limiting their effectiveness (in comparison, stainless steel contains a minimum of 10.5% chromium and 8% nickel).
Another option, when loading conditions allow, is lower-strength/hardness rod grades that are less susceptible to certain types of corrosion. Corrosion inhibition is also common, but it can be costly and its effectiveness diminished under certain well and operating conditions. When corrosion cannot be mitigated effectively, then service factors are normally applied to downgrade the allowable stresses in the case of RRP applications and rated torque values for PCP applications. In severe environments, service factor values of 0.5 or lower may be required to avoid short-run fatigue failures.
CONTINUOUS ROD
Jointed sucker rods have been in use for over 100 years and are the predominant sucker rod string in RRP applications, as well as widely used in PCP applications. The only rod string alternative is continuous rod. It was initially to address rod and tubing wear challenges created by the increasing use of directional wells in Canadian thermal heavy oil operations that produced solids.
Continuous rod consists of a single, long section with only two connections on each end of the string. As a result, the rod contacts the tubing along its length, distributing and reducing the contact loads and minimizing the associated wear. In comparison, jointed sucker rods contact the tubing at their connections and, where applicable, rod guides, resulting in localized contact loads that can reach high values and lead to elevated levels of wear.
Other benefits of continuous rod related to the elimination of connections include minimizing tubing flow loss restrictions, which reduce pump and system loading; elimination of localized rod bending stresses, due to connection to body stiffness changes; and 8%-to-10% lighter weight, which can be important in highly loaded RRP applications. Continuous rod is produced in similar chemical compositions, mechanical strengths, and diameters as jointed sucker rods.
Continuous rod utilizes special transportation, handling, and servicing equipment which has, and continues to, evolve with the expanding application requirements. The rod is transported on large-diameter reels, and running and pulling operations utilize special servicing equipment. The main servicing component is a gripper that uses a rotating parallel chain system with integrated gripper pads to move and suspend the continuous rod string. Fig. 3 shows a self-contained continuous rod rig running rod off a service reel into an RRP well.
Fig. 3. Continuous rod rig installing rod in RRP well.
ETHYFLEX COATED ENDLESS ROD
To protect continuous rod from mechanical and corrosion damage and associated rod fatigue failures, the EthyFlex coated Endless Rod product was devised. EthyFlex utilizes a high-density polyethylene (HDPE) thermoplastic outer coating material, similar to that used for wear and corrosion protection in common grades of lined tubing. HDPE is known for its high strength, relatively low cost per volume, and ease of processibility.
EthyFlex is manufactured in a continuous extrusion process that molds the HDPE material around the rod and shrink-fits the coating on the rod body. The coating can be applied to all rod sizes and grades in a 0.125-in. thickness, thus increasing the overall coated rod diameter by 0.250 in. Servicing uses bare continuous rod equipment; however, the EthyFlex unbonded design limits rod string weights to ~10,000 lbs. For 7/8-in., 1-in. and 1 1/8-in. rod sizes, this equates to maximum vertical rod lengths of 4,500, 3,500 and 2,750 ft, respectively.
More than 4,000 EthyFlex Endless Rod strings, forming over 6 million ft (2 million m), has been deployed within the Western Canadian Sedimentary Basin. All are PCP applications, due to the servicing depth constraints and HDPE temperature (<110ºF) and fluid (<35ºAPI) limitations. Most installations are shallow, horizontal wells, with high curvature (up to 15º/100 ft), operating with moderate capacity pumps producing cold heavy oil with solids.
Prior use of bare continuous rod experienced reoccurring failures every several months, usually at loads below the rod torque rating. Inspections characterized the failure mechanism as fatigue, usually with corrosion as a contributing factor. EthyFlex increased run times, in most cases, to more than a year (three to five times historical rates) and, in the best cases, up to several years. It has been, and continues to be, deployed in other Canadian PCP applications, including medium oil, high water cut wells with a history of sucker or continuous rod fatigue failures. Similar reductions in fatigue failures and associated rod-related well interventions have been experienced, with cases of product in benign applications having run for over five years without any rod failures and the coating in good condition when surfaced.
KeBOND COATED ENDLESS ROD
Building on the EthyFlex success in reducing rod fatigue failures, along with the associated field servicing experience, Lifting Solutions developed a second-generation coated Endless Rod targeting a broader application range. The resulting KeBond Endless Rod product has a multi-layer composite bonded design with a high-toughness fluid-resistant Polyketone (PK) outer coating. Fig. 4 shows the KeBond design and product.
Fig. 4. KeBond multi-layer composite coating design and reel of KeBond product.
Comprehensive laboratory testing evaluated critical coating mechanical properties, including low temperature ductility, heat aging, and fluid and gas resistance. Extensive coating wear testing was completed against steel and lined tubing under a variety of fluid composition and contact loading conditions. Subsequent full-scale service equipment testing of the KeBond product resulted in refinements to gripper pad geometry and identification of the associated servicing procedures.
Based on product and service testing, the maximum rod string servicing weight was doubled to 20,000 lbs (9,000, 7,000 and 5,000 ft for 7/8-in., 1-in. and 1 1/8-in. rod sizes), downhole temperature limits increased to 175ºF, and oil gravity limits increased to 50ºAPI. These weight/depth capabilities, along with the increased downhole condition, specifications, greatly expand the application range and make the product an option for many RRP applications.
Field testing of KeBond began in July 2023 in routine Canadian PCP and RRP applications, after which the servicing and application difficulty was ramped up over time. Testing eventually progressed into deeper U.S. RRP applications that were near or above the upper end of the product specifications. Currently, there are approximately 100 PCP and 30 RRP installations.
Servicing capabilities were the first to be confirmed through field testing, since they only require the successful running and pulling of strings and are not highly application-dependent. Product capability determination requires extended downhole operational time across the full application range. Since much of the initial field testing was in wells with a history of repeated rod fatigue failures, confirmation of the barrier protection capabilities and associated elimination of short-run failures occurred quickly. Determination of the product’s full potential requires several years of operational history across a broad range of applications.
KeBond PCP installations have pushed beyond the original EthyFlex range in terms of depth and fluids but remain well below the upper end of its product specifications. Many of the initial installations were shallow (max. of 2,600 ft), with the deepest being 4,400 ft. While the depths were limited, the trials encompassed a wide range of fluids, CO2 and H2S, and highly directional wellbores; and when combined, led to the wells having a history of sucker and continuous rod failures.
Several heavy oil fields in Saskatchewan, Canada, had a historical mean time between failure over the last two years of 48 days, primarily due to rod breaks, compared to 16 KeBond installations with an average run time to date of 195 days without any failures. In another high water cut, medium oil application in Chauvin, Alberta, Canada, the introduction of KeBond reduced the continuous rod breaks from 46 in first-quarter 2023 to 18 in first-quarter 2024, with further reductions expected as it is installed in more of the problem wells. A highly corrosive application near Macklin, Saskatchewan, Canada, with larger high-torque pumps had a history of short-run fatigue failures, with the worst wells having over 25 rod-related service jobs over the previous two-year period. The first KeBond installation in this field has over 250 days of continuous run time, with four others having surpassed 150 days.
Overall, across all PCP KeBond installations to date, there has been only one failure in a coated section, which was located near a weld and associated with bare rod preparation. Multiple strings have been surfaced for other reasons, enabling inspection of the KeBond coating. Almost all confirmed the coating was in either undamaged or slightly worn condition ,allowing the strings to be re-run.
The exception was three instances, where there was significant coating wear that exposed the bare rod. In two of these cases, the problem areas were cut out and replaced; and in the third, the string was redeployed to a non-critical application. These cases confirm that, despite the thick wear-resistant KeBond coating, there are application conditions, normally highly deviated wells producing abrasives, that induce substantial wear that requires a preventative maintenance approach to avoid it progressing to where the coating integrity is compromised, and rod failures may occur.
The first KeBond RRP installations were in Leduc, Alberta, Canada, using 1-in. high-strength 3,500-ft strings weighing ~10,000 lbs. Four wells are operating without any failures to date. The longest has reached 270 days, relative to a historical field average of 180 days between rod failures with severe corrosion. Surface loading has decreased under similar operating conditions, which is attributed to reduced friction between the thermoplastic coating and steel tubing. One string was pulled for a bottomhole pump failure after 105 days. A wellsite inspection confirmed only light longitudinal wear marks with no measurable coating loss.
The initial US RRP installation was a hybrid string with bare continuous rod on the top 3,300 ft and 1-in. KeBond on the bottom 1,800 ft. The associated field did not have a history of rod corrosion fatigue failures but rather issues with friction and rod/tubing wear, due to the bottom portion of the rod string being deployed in deviated wellbore.
Specifically, in this first case, the pump was landed at a 45o hole angle, and wellbore curvature ranged from 6o to 10o/100 ft between 4,500 ft and the pump landing location. Historically, lined tubing was deployed from the kick-off point to pump seating nipple to reduce friction and wear, with the KeBond being run as an alternative approach. After about 30 days, the rod failed in the upper bare string and inspection of the bottom KeBond confirmed no damage.
Subsequently, the entire string was converted to KeBond and has run a total of 150 days without intervention. Based on that initial success, another 10 full 1-in. x 7/8-in. tapered KeBond strings, averaging 5,300 ft in length and landed at up to 60o hole angles, have been run with no rod failures to date, due to fatigue or wear, despite the elimination of the lined tubing. Additionally, reduced upstroke loads and improved rod fall have been reported, confirming lower friction between the rod and tubing.
Another series of U.S. RRP KeBond field trials is underway in unconventional oil wells in the Permian basin. These applications have tapered 1-in. x 7/8-in. x 1-in. (sinker) rod strings with lengths of 6,200 to 8,200 ft and associated rod weights as high as 20,000 lbs. The downhole environment is 40oAPI high water cut fluids, C02 and H2S and temperatures of 130oF. The length and downhole conditions are near the upper end of the KeBond product specifications, providing a strong test of serviceability and downhole product performance.
To achieve the target fluid rates from these depths, the rod strings are highly loaded, with little-to-no safety factor to accommodate corrosion damage. On the problem wells included in the trials, prior rod failures occurred after 20 to 200 days, with the KeBond operating target being a minimum to double those runtimes. Ten strings have been installed without any problems, providing confidence in the ability to achieve the full range of servicing specifications. In terms of downhole performance, the longest running string has operated for 150 days, half have surpassed the previous run time, and three have met the targets. To date, there have been no rod failures or requirements to surface the rod strings. Additional operational history is required to fully evaluate KeBond performance in these types of challenging applications.
VALUE PROPOSITION
The addition of a thick, durable barrier coating to Endless Rod has been proven to reduce fatigue failures, including those induced by corrosion, and substantially increase run times. The coated Endless Rod lowers lost production costs and reduces operating costs through lower well intervention and equipment repair/replacement costs. Depending on the application conditions, additional demonstrated benefits include reduction in rod/tubing wear and reduced friction. New KeBond Endless Rod significantly expands the coated continuous rod products application range, including RRP applications. Field testing is ongoing to evaluate the improvements in these applications.
About the Authors
Lonnie Dunn, P. Eng.
Lifting Solutions
Lonnie Dunn, P. Eng. , is the Engineering and Manufacturing vice president for Lifting Solutions, where he leads technology-focused efforts to drive product innovation. He has over 35 years of experience in the artificial lift sector, specializing in progressing cavity pumps and continuous rod and has numerous papers, several patents and contributions to industry standards. Mr. Dunn holds a BSc degree in mechanical engineering from the University of Alberta, Canada.
Dr. Karthik Shanmugan
Lifting Solutions
Dr. Karthik Shanmugan is the Materials Engineering specialist for Lifting Solutions. He specializes in polymeric materials development, including elastomers, thermoplastics, and thermosets, with a focus on formulations for oil and gas applications. Dr. Shanmugan’s extensive expertise extends to developing manufacturing processes, such as continuous extrusion and tandem extrusion. His mastery of materials has directly contributed to the engineering and development of Lifting Solutions renowned elastomer and coating materials, which enhance the performance of several of our high-quality products.
Ryan Rowan
Lifting Solutions
Ryan Rowan is the Technical & Application Support director at Lifting Solutions, leading a dedicated team of application specialists. These specialists are committed to assisting clients with their most complex well challenges. With over 28 years of experience, Mr. Rowan has made significant contributions to the design, development, manufacturing and application of rod-driven systems. His profound understanding of artificial lift, wellbore environments, and the intricacies of production operations positions him as an invaluable resource working closely with clients. Mr. Ryan serves as a trusted advisor, consistently providing solutions that address some of the industry’s most demanding applications and also enhance well performance.
Taylor Krenek
Lifting Solutions
Taylor Krenek , serving as a Technical Application specialist for Lifting Solutions, operates from Houston, Texas. His role involves a synergistic partnership with both the engineering department and the global applications technical team, aiming to address the most difficult well challenges faced by clients. With a wealth of experience spanning over a decade in crafting artificial lift solutions tailored for the most demanding U.S. well environments, Mr. Taylor takes pride in delivering outcomes that not only meet client expectations but consistently surpass competitor offerings.
