A new line emerges on linear lift

Linear lift systems (LLS) are emerging from their traditional niche to fill a more central role in production systems applications. A variety of new products has hit the marketplace recently, all falling under the category on linear lift, but each with different features and advantages.

Fundamental advantages are well-known
All linear rod pumping solutions have some similarities that offer compelling advantages to the well operator. Compared to rod-pumped wells that use traditional pumpjacks, LLSs offer a greater load range and longer stroke that, for any given production rate, requires less up/down cycling of the sucker rods. This can greatly reduce rod fatigue, resulting in less downtime and fewer workovers. It is also argued that pump and tubing wear are reduced as well.

Particularly in viscous crude production, the long slow stroke attainable by LLS minimizes fluid mobility issues and is less likely to bring on premature water breakthrough. This advantage can be realized in low viscosity production as well. A typical provider offers systems ranging from 7 to 30-ft (2.13 to 9.14-m) stroke at loads ranging from 7,500 to 80,000 lb (3,409 to 36,364 kg). This provides the ability to pump wells 16,000 ft (4,878 m) deep.
Because of the kinematics associated with LLS, it is possible to attain more optimal dynamometer curves than can be easily obtained by traditional pumpjack kinematics.

The physical differences between LLS and pumpjacks offer a decided advantage to LLS users. In general, LLSs are lighter and more easily transported and installed. They do not require a large concrete pad, and they are easily adapted to all wellheads and downhole systems. A longer polished rod may be required, but basic wellhead equipment stays the same.

LLSs have a small footprint and a slim, vertical profile, making them popular for use in built-up areas or environmentally sensitive sites. Often, they are camouflaged with mottled paint patterns of greens and browns to blend in with the environment surrounding their well site.

Two basic long-stroke styles available
Long stroke LLSs are available in hydraulic or mechanical styles. The latter uses a rack and pinion arrangement where an electric motor drives a pinion gear via a right-angle gearbox that engages a long rack gear that attaches to the polished rod. It offers positive up-down power. The entire moving portion of the mechanical system can be housed in a protective shroud for operation in extreme environments of dust, sand, salt spray, or ice. All variations in pump action are imposed by the electrical pump controller, including downhole dynamometer optimization for maximum efficiency.

Figure 1. Rack and pinion drive mechanical LLS.

Hydraulic systems use a motion-multiplying piston/cable (or piston/belt) arrangement. A hydraulic pump drives a vertical piston that provides lift on the up-stroke while the down-stroke is gravity-driven. At the top end of the piston is a sheave wheel. Cables (or in some cases a belt) pass over the sheave wheel connecting the top of the polished road to a dead-man anchor. Thus, for each upward increment of the piston rod, two increments of pump stroke are obtained.

An advantage of the hydraulic system is that on the gravity-driven down-stroke the hydraulic pump becomes a motor, turning the electric motor into a generator. That generates clean electricity that is returned to the power grid as a credit. As much as 40% savings on recovered electrical power costs has been reported.

As with the mechanical version, linear motion is governed by the pump controller, so virtually any downhole dynamometer response can be programmed. Pump performance can self-adjust in real time to react to instantaneous well conditions such as loading or pump-off, which can be experienced with multiphase flow regimes, low-mobility hydrocarbons, or variable fill rates. For example, on the up-stroke the controller accelerates the pumping unit to maximum speed without exceeding the polished rod tension limit. The subsequent down-stroke speed is determined by the controller, which automatically adjusts the speed to maintain 100 to 200 lb load on the polished rod without separation as fluid viscosity changes. Analyzing polished rod loading and ram position on each previous stroke automatically optimizes up- and down-stroke speeds. If the well pumps down, the up-stroke speed is adjusted to maintain a constant fluid level.

What’s the right pump for your well?
The answer, like almost every answer to an oilfield question, is “It depends.” Operators must ask themselves several questions before they can arrive at the correct answer. Even that answer may vary depending on the situation. For example, a good first question might be, “Is the proposed application for a new well, (e.g., a well that has not been on the pump before), or is it for a well that has been rod pumped previously?” If a legacy downhole pump, rod string, and associated wellhead equipment already exist, the decision might be simply whether it makes sense to retain the status quo or change out the surface equipment from the previous configuration to an LLS. Another choice might be a downhole progressing cavity pump driven by a surface motor and gearbox that will turn the rod string rather than reciprocate it. Progressing cavity pumps might make sense, for example, to dewater a gas well that has a very low fill rate or to pump a well that has a fairly high concentration of solids in the production stream.

For new well installations, all technologies should be considered, with the best choice usually being the system that offers the best run life with fewest interventions while delivering maximum well performance. This opens the door for other artificial lift techniques such as electrical submersible pumps, gas lift, or plunger lift systems. Most artificial lift providers have software programs that help them advise their customers on the system that makes the most economical sense.

If the decision is centered on rod-pumping, and assuming the traditional pumpjack and surface-driven progressing cavity pump have been ruled out; then the question may boil down to the type of LLS that makes the most sense. Generally LLSs offer distinct advantages when the production is low-gravity crude or if the up-stroke load is high. In these cases, the reduction of cyclic stress on the rod and pump system offers the likelihood of longer system life. Tubing wear is also reduced, although this can be mitigated by using low-friction composite rod guides. It can be argued that the system offering the lowest operating expense is probably the best choice. Electrical power costs can be considerable and over time can represent the highest cumulative cost of running the system. Some operators have had success using field gas to power natural gas-aspirated engines to power the pumping system; others find that this just adds a measure of complexity — one more thing to break down.

Figure 2. Hydraulic cable/sheave type LLS.

What about the well itself?
Well/reservoir behavior and fluid characteristics are added factors to consider. For oil producers, a critical question might be, “What is the maximum sustainable pumping rate without risking sanding or coning?” For gas producers, the operator wants to know the water situation: “What volume and rate must I dewater to keep the hydrostatic head low enough so the gas will keep flowing?” The corollary is, “How much water can I pump before I experience pump-off?”

For many wells and reservoirs, there is no firm answer to these questions. That is why a real-time dynamic operating system is a good investment. These systems can sense when the pump is working at its optimum rate and automatically adjust speed, and in some cases stroke, to keep the pump operating within limits and at maximum hydraulic efficiency.

Recently, many operators have found that they can optimize the performance of the entire field by monitoring each well and using the data to adjust the dynamic reservoir model.

Instrumentation is available that measures both well performance parameters and pump performance. The data is transmitted to a field production office or company headquarters, where production engineers can perform surveillance and head off many problems before they become serious ones. Sometimes third-party monitoring and surveillance services are provided by a service company so the operator must only address wells that are performing outside of established norms. The third-party service providers can even perform remote emergency shut-down of a pump if it is warranted. If pump performance monitoring is included, equipment can be shut down before serious damage occurs, thus reducing downtime, maintenance, and repair costs.

Advantages of long stroke LLS are worth considering
In many cases, the advantages of greater production volumes at lower operating costs make the decision to switch to LLS an easy one. No longer relegated to the niche markets of low-gravity crude or high-lifting load situations, LLS can provide compelling benefits in nearly every pumping application. Capable of operating with conventional jointed sucker rods, fiberglass rods, or Corod, LLS is the ideal solution for situations with changing rod loads.