This alternative to sucker rods improves production in unconventional plays.
by Ryan Orr, Weatherford
November 14, 2014

Historically, the vast majority of artificial lift deployments have been in vertical wells that produce oil and gas from conventional reservoirs. The last few decades, however, have brought a dramatic shift to both conventional and unconventional oil and gas production from deviated wells, including horizontal, S-shaped and slant well trajectories. Deviated wells have presented a major challenge for artificial lift operations—including the accelerated wear of downhole equipment and tubing. The friction between the tubing and the rod string can wear holes in the tubing, which leads to production delays and costly, time-consuming repairs and equipment replacement.

Tailored Rod Lift for Deviated Wells

Service providers attempt to overcome this problem by tailoring lift solutions to meet the specific challenges of deviated wells. Reciprocating rod lift (RRL) is well-established in conventional wells and is gaining popularity in unconventional ones. In conventional wells, this lift method brings fluid to the surface through the reciprocating pumping action of a surface pump attached to a rod string and downhole rod-pump assembly. Conventional rod lift systems deploy a sucker rod string consisting of individual sections that are joined together by threaded connections at each end. A conventional sucker rod string requires a coupling every 25 to 30 feet to connect two sections of rod. In many wells, this amounts to several hundred connections and significant manpower hours. Continuous sucker rod lift, which deploys a continuous rod with no couplings, has replaced conventional sucker rods in RRL and progressing cavity pumping systems in many applications. Continuous rods are a beneficial alternative to conventional sucker rods in many production scenarios, primarily because of the lack of threaded connections. Continuous rod strings require only two threaded connections—one at the top and one at the bottom of the string—which significantly speeds up overall string deployment. Each connection in a traditional sucker rod string introduces a point of possible rod failure. Under- or over-tightening the joints with tongs may promote fatigue failure, for example, and manual joint tightening may result in improper make-up torque. A conventional rod also increases safety risks because two dedicated rig hands are required on the floor at all times during make-up and breakout.

Continuous rod string set-up downholeFigure 1. An example of a continuous rod string set-up downhole

Uniform Body Design

A key feature of a continuous rod string is its uniform body design, which yields three major benefits. First, the uniform design helps reduce contact loads between the tubing and the rod as the rod moves up and down during pumping. The couplings in a conventional rod string set up concentrated contact loads with the tubing, which increases the rate of wear at the contact site. The continuous rod, by contrast, does not create concentrated sites of wear. Instead, it distributes the contact load evenly across the entire tubing. This dramatically reduces wear rates and extends the run life of the entire system, which results in fewer interventions and a longer lifespan for the assembly. Second, the uniform body design creates a larger annular clearance between the rod string and production tubing, reducing pressure losses and potentially increasing production without changing the surface equipment. A larger and more uniform annular space also helps ensure that the flow of the fluid is laminar, compared with the turbulent flow that arises in traditional sucker rod strings with couplings. The elimination of couplings, centralizers and rod guides also increases overall system efficiency and reduces lifting costs. Third, the uniform body design delivers a continuous string that is up to 8 percent lighter than a sucker rod string of equivalent length. This ensures less loading on the surface unit and allows operators to deploy the rod farther into the well for improved pumping efficiency.

Reduced Rod Stress

Continuous rods offer an additional benefit over conventional sucker rods in terms of rod stress and fatigue. Bending stresses are typically magnified near rod-coupling connections because the coupling is stiffer than the rod body. The curvature experienced at these connections is magnified up to 10 times, but the uniform diameter of a continuous rod ensures that rod curvature equals the curvature of the wellbore. This distributes the contact load more uniformly at a bend in the wellbore.

Case Study

Continuous sucker rod lift systems have been used in conventional oil and gas wells for nearly six decades, garnering a track record of reliably boosting production with minimal downtime. One company has deployed more than 2,500 systems in wells in California; 1,000 throughout Latin America; and nearly 20,000 in Canada. In deviated wells, this technology has been deployed for 50 years with similarly high levels of success.

Continuous rod in wellbore curvatureFigure 2. The uniform diameter of the continuous rod (right) better follows the changes in wellbore curvature, which reduces bending stresses and distributes contact loads more evenly when compared with a conventional rod string (middle and left).

For example, an operator of an onshore oilfield in Colombia needed an alternative artificial lift solution for its highly deviated wells (final hole angles were up to 80 degrees in some cases) with a high gas-to-liquid ratio (GLR), limited available space for surface equipment and no electricity source in the vicinity. Other typical well conditions include formation depths between 4,000 and 8,000 feet (1,219 and 2,438 meters), water cuts of less than 5 percent, fluid rate up to 700 barrels of fluid per day (111.3 cubic meters of fluid per day), 24-degree (American Petroleum Institute) gravity, less than 0.1 percent sand production and low viscosity. The field was initially equipped with progressing cavity pumping (PCP) systems, but the high GLR created challenges for the elastomers in this pump type, such as swelling and high torque variation during operation. The pumps had a run life of less than 30 days before elastomer failure, which caused a lengthy waiting period for workover rigs and an unfavorable amount of downtime. The operator considered electrical submersible pumping (ESP) systems as an alternative to PCPs. While the ESPs satisfied the surface space limitations and worked well, their initial high investment costs and energy requirements to overcome their efficiency limitations made their use across the field impractical. A field analysis indicated that a RRL system was the best alternative, based on the space limitations and results with previous artificial lift systems. The entire RRL system consisted of a variable speed hydraulic unit and a gas pusher pump as the main components. These were chosen for their ability to adapt to continuously changing well conditions and to work effectively in a high-GLR environment without serious detriment to system efficiency. The system also included rod-pump controllers, which provided continuous monitoring of well conditions, and continuous rods to reduce the wear associated with the well deviation. Gas separators were incorporated to handle free gas at the pump’s intake. The installation of the RRL system with continuous rods eliminated most of the failures experienced with the previous artificial lift solution. The system has been running in the field for more than 800 days without significant downtime or maintenance issues. The operator recouped its investment in a relatively short time period, which enabled continued development of the field. Successes such as these are spurring greater interest in continuous rod lift systems globally. Enhanced recovery methods of conventional and heavy oilfields and new developments in unconventional fields require more aggressively drilled deviated and horizontal wells.