The Time Has Come For Coiled Rod Reprinted from Well Servicing magazine
The development of flush-by well service units and stand-alone coiled rod injector head technology has helped grow the coiled rod service fleet three-fold over the past five years. By DAVE JONES Norris Coiled rod is a new technology that was developed nearly four decades ago. Thanks to technological advances, expanding service availability and a growing need to give operators new options to address some of the failures that have plagued artificially-lifted, rod-pumped wells over the years, coiled rod s time has finally come. Coiled rod technology was developed in the early 1970s in Canada as a way to reduce service costs and improve run performance in rod-pumped wells. The idea was to do away with connections in a conventional rod string, solving connection failures that can occur as a result of the loss of displacement, usually from improper makeup or operational problems such as fluid pound or pump tagging, which causes connections to loosen. The connection itself also causes a piston effect that restricts fluid flow in higher-volume wells. In deviated wells, conventional rod connections can cut tubing and create stress cracking on the rods in bend sections because of the ridged concentration of force at that point. With coiled rod, a smaller and longer cross-sectional area can follow these bends and turns better with less concentrated force on the tubing (Figure 1). In addition, coiled compliments the application of progressing cavity pumps because of the high volumes of fluids and solids that do not have to pass over connections and create pressure drops that are detrimental to this type of artificial lift (Figure 2). Many U.S. operators have given coiled rod a try, and although the technology may have proven effective at saving service and downtime costs related to downhole failures, coiled rod suffered from serviceability issues in the past. One of the single biggest issues was that a separate dedicated service unit was needed in conjunction with a conventional workover rig to run and pull coiled rod and trip tubing. Moreover, a limited number of coiled rod service units meant that oil and gas companies that had purchased coiled rod found themselves waiting sometimes for weeks for a service unit to become available while their wells remained offline and generating no revenue.
Conventional Rod Coiled Rod Figure 1 - Conventional versus coiled rod in bend sections. No matter how intriguing the benefits of coiled rod may have appeared, the service problems associated with running coiled rod eventually led most early adopters of coiled rod to go back to conventional rod strings in their wells. Fortunately, a number of technological and commercial developments are overcoming the limitations that coiled rod experienced in the past and providing oil and gas companies with a new and innovative approach to the service aspects of coiled rod technology. Technology developments One key advance has been the development of flush-by units, a new type of well service workover unit that can be used with coiled tubing. Pioneered in Canada, flush-by units are designed with the ability to perform several well service functions off one piece of equipment. They are equipped with telescopic masts for pulling and running rods, seating or unseating pumps, changing out polished rods, or running a wireline tool. The units are also equipped with 50-barrel tanks and triplex pumps for pressure testing tubing, flushing a progressing cavity pump after lifting the rod string into the derrick, loading tubing or injecting chemical or acid into the well bore. Another important step in making coiled rod technology viable for operators was the development of a new model for servicing coiled rod. In order for coiled rod to become a larger participant in rod-pumped wells, a service infrastructure had to be developed to address the problems associated with servicing coiled rod. Consequently, control of servicing coiled rod has been put in the hands of the companies that were already in that business well service contractors. But service companies had to have a way of running and pulling coiled rod without requiring a separate piece of dedicated equipment that had to be run by a different crew. To overcome that problem, a standalone coiled rod injector head has been developed that is similar to the injector head on a coiled tubing unit, but it can be a stand-alone piece of equipment that is pulled into the derrick by the traveling blocks of conventional workover rigs. Once in place and secured, it can run off the service rig s power supply or a separate power supply. Stand-alone injector heads can be provided to well service companies to offer timely and costeffective service of coiled rod, or to the operators that want to own the injector heads to be used by the service companies of their choosing. The development of the stand-alone coiled rod injector head has grown the coiled rod service equipment fleet from 30 units worldwide five years ago to 90 units today. With a viable option for servicing the running and pulling of coiled rod in place, the ability to weld the coiled rod on location when repair or length adjustment are necessary became the next critical issue. To accomplish that objective, a self-contained oxy-acetylene burner that uses gas butt fusion welding instead of electricity has been developed that is portable enough to use on location. The footprint of the welding system allows it to fit in the back of a pickup or on a small trailer. The process for welding either connections or two coiled rods together is to set the two pieces in the provided jaws, remove grease or wax from the ends, clean the faces to be fused from any bluing effect from saw cutting, and then butt the two ends together. As the burners begin to melt the steel, an impact screw applies pressure to push the ends together. Collectively, these advances allow producers to evaluate the benefits of installing coiled rod to reduce lifting and maintenance costs without ongoing questions about service for the life of their wells controlling the decision. And as the industry continues to make strides in directional and horizontal drilling, the benefits that have been proven in these types of
applications will continue to offer operators even more choices. Benefits of coiled rod In Canada, coiled rod has been used to reduce consistent well failures such as connection failures from inadequate makeup processes or operating conditions that cause connections to loosen. The technology has also proven valuable in wells that had experienced other types of downhole failures, such as tubing failures resulting from concentrated coupling/tubing pressure points. Because coiled rod provides a uniform contact on the tubing, premature tubing wear is minimized, especially in directional and horizontal applications. In terms of the production response from the well, continuous rod can result in increased production for a number of reasons, including the elimination of the rod coupling-piston effect and the capability to use larger rods in smaller tubing. The technology also reduces fall rate friction and increases plunger travel. Fluid passing over the coupled connection area in a conventional rod string causes pressure drops and creates drag forces that impact how the rod string falls. In essence, it tends to float on the downstroke, not allowing the plunger in the pump to fall easily. The longer the stroke at the bottom of the hole, the more fluid can be displaced. Coiled rod also offers the ability to handle heavier loads and produce more fluid. In 2 3 / 8 -inch tubing, the largest conventional coupled sucker rod that can be run is 7 / 8 -inch, reducing the load that can be applied to the rod string and limiting pump size and the amount of fluids the well can produce. However, up to 1 1 / 8 -inch coiled rod could be run in the same size of tubing, which would allow a larger pump and produce more fluids, provided the surface equipment can handle the extra load. Because coupling restrictions do not apply, coiled rod is also ideal in slim-hole applications. Again, the upset and coupling at the connection area create limitations using conventional sucker rods in small-tubing applications. With coiled rod, a largerdiameter rod can be run inside slim-hole tubing with no restrictions. In terms of maintenance costs, coiled rod reduces mechanical tubing wear by eliminating the concentrated pressure points at the connections in conventional rod strings that create contact patterns inside the tubing and eventually wear to the point of failure. The technology also increases rod service life by eliminating connection failures, and by helping reduce accelerated wear on tubulars cased by pumping water and abrasives, which tends to be concentrated at the rod couplings. Additionally, coiled rod can help reduce paraffin buildup. In conventional rod strings, paraffin buildup begins at the connections, when the fluid carrying the paraffin stalls as it slows across the upset and coupling. From there, the buildup grows on the rod because the pressure drop does not allow the fluid to pass unabated up the tubing. Figure 2 - Production flow with conventional versus coiled rod strings. Removing contact points The operator essentially has only one course of action for solving rod and tubing wear problems: remove the concentrated contact points. That can be accomplished in three ways. The first is to install coiled rod, which significantly reduces or even eliminates the contact points without sacrificing the strength of the rod string. The second option is to invest in rod guides that attach to a conventional rod string close to the upset to keep the rod and especially the connection from contacting the tubing. However, installing rod guides can sometimes cost more than the rod itself. The third option is to utilize slim-hole couplings. In some cases, to reduce the pressure drop and create a more uniform contact between the rod connection and the tubing, slim-hole couplings can be used that have the same outside diameter as the upset pin shoulder on the rod. This creates a consistent transition across the connection, but because the cross-sectional area of a slim-hole coupling is far less than a full-size coupling, strength is sacrificed. Operational problems associated with rod-pumped wells will continue to be a concern in the future as operators utilize more optimized drilling techniques and older wells continue to be plagued by problems such as connection failures and tubing leaks caused by overpumping wells or inexperienced well service personnel not trained correctly in the proper procedures for making up conventional sucker rods. Operators will continue to look for ways to reduce costs associated with well failures and expensive workovers.
Even though coiled rod technology is 40 years old, new service options and technological developments are giving operators a better and more efficient way to produce their wells, changing coiled rod s application envelope from a niche market to a possible step change in the way oil and gas companies operate producing wells. Coiled rod strings are now available in 1536 carbon steel for light to medium loads and no corrosion, 4120 chrome-moly steel for light to medium loads with mild but treated corrosion, 4320 nickel alloy steel for light to medium loads with high but treated corrosion, and 4330 nickel allow for heavy loads and mild but treated corrosion. With the development of more service options, new methods for welding coiled rod on site, a larger selection of steels and strengths, the increased application of directional and horizontal drilling, and the rising costs that have led producers to rethink their operations will all have an impact on the growth of coiled rod in the future. ABOUT THE AUTHOR: Dave Jones is sales manager with Norris, a Dover Company, in Dallas. He holds a B.S. degree in business from Texas Tech University. Notes