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Sucker-rod systems are the most common artificial lift worldwide due primarily to low cost. Electric submersible pumps offer an alternate but more expensive solution for clean fluids.
Editor’s Note: Part 1 of a two-part series provides an overview of artificial lift systems with pros and cons for operators to best evaluate the options.
The importance of artificial lift systems cannot be overstated with more than 95% of wells requiring artificial lift installation from the outset of production. However, the expense issue is never far from the selection discussion.
As one longtime oilfield engineer put it, “To minimize workover costs, we’ve got to be able to come up with the most reliable means of pumping that’s not going to cost us an arm and leg to keep going.”
Over the years, operators have employed various means of artificial lift to increase crude oil production from horizontal and deviated wells when there is not sufficient pressure within the reservoir to lift liquids from downhole to surface.
Similarly, artificial lift systems may be used in wells that have sufficient subsurface pressure but where producers want to increase the rate of production. Typical lift options include the commonly utilized sucker-rod pump, progressing cavity pump (PCP), plunger lift, electrical submersible pump (ESP), jet/subsurface hydraulic lift systems, and gas lift.
Considering the varying reservoir and well parameters encountered, for example liquid-rich shale and tight oil reservoirs, several factors must be weighed when determining the appropriate artificial lift solution to most effectively produce the well.
This means that lateral length/vertical depth, flow rates, temperatures and pressures, gas-to-oil ratios (GOR) and natural gas liquids (NGL) yields represent some of the conditions that must be taken into account in artificial lift system selection.
Sucker-Rod Pumps Pioneer Artificial Lift
For sucker-rod artificial lift systems, components include a long cylinder produced in either carbon steel or brass called the barrel; a steel cylinder fitting within the barrel to draw the liquids upward by moving up and down that is called the piston or plunger; valves comprised of the seat and ball to form a seal when closed; a piston rod to transfer up and down reciprocation to the surface; fittings to ensure the entire apparatus remains tightly in place; and a filter to prevent solids from being pulled into the pump (Fig. 1).
|Figure 1: Hydraulic, rod-pumping system and downhole sucker-rod pump. (Illustrations courtesy of National Oilwell Varco Monoflo)|
Throughout the decades, the industry has used primarily sucker-rod pump systems. With a stroking up and down motion, the rod string, sucker rod and rod pump work like pistons in an automobile engine to push liquids to the surface. Due to heavy sucker rod pump reliance, the oilfield has produced numerous experts who have come to know these systems, the related applications and set-ups very well.
Therefore, the wide-ranging deployment of sucker-rod systems worldwide has built strong expertise, which most likely accounts for the system’s continued prominence in the oilfield. This implies the use of sucker-rod systems is not an actual endorsement over other options subsequently developed.
Additionally, many sucker-rod components can be economically refurbished. As a result, idle equipment has been readily re-applied to shale, coal-bed methane, and tight oil. Generally speaking, sucker-rod equipment requires lower lifetime economic investment than most other artificial lift options.
From an operational perspective, sucker rod pumping systems are preferable for long lateral wells regardless of most wellbore parameters; the one exception would be high-volume, low-GOR wells. When compared with other artificial lift options, these systems also offer more reliability and flexibility.
An even higher level of flexibility is attainable with a hydraulic surface pumping system, which allows easily adjustable up-stroke and down-stroke speeds. For horizontal or deviated wells, that attribute is especially important since the system’s rod and pump provide superior performance during down-stroke followed by a slightly quicker up-stroke and slight dwell at the top of the up-stroke to ensure optimal pump fillage.
A word of caution, a sucker-rod pump system must be suited to its field usage. Design and application of the rod string and sucker-rod guide placement are critical.
For example, a common error made by operators is to base guide spacing and rod guide placement solely upon the stroke of the surface unit. In actual practice, the system only works successfully when the inclination and dog-leg severity are considered. When used arbitrarily, it can cause increased rod and tubing wear resulting in extended downtime and production loss.
The subsurface sucker-rod pump component operates through downhole force generated by the subsurface pump’s up-and-down reciprocation. These pumps can be manufactured for heavy oil, sand laden or high GOR applications.
In shales and tight oil formations, the subsurface sucker-rod pump has been employed with a high success rate, due primarily to its robust nature and toleration of wide-ranging downhole conditions without experiencing failure. It moves the required fluid to the surface quicker with less equipment servicing required and overall lower operational expense.
Additionally, there are many accessories available to enhance both the reliability and efficiency of the conventional sucker rod pump. When it comes to servicing, these are one of the simplest and lowest cost forms of artificial lift. For example, insertable models are available that only require rod pulls to change the pump while tubing remains in the hole.
Electric Submersible Pumps
Capable of working effectively with wide-ranging flow rates and lift requirements, an electric submersible pump (ESP) system is best-suited for straight, casing sections to optimize the lifecycle. However, ESPs will function in horizontal, vertical or deviated wells. ESPs utilize multistage centrifugal pumps to generate the pressure required to move fluid to surface.
Long active in the oilfield, ESPs were primarily designed for pumping high volumes of clean fluid. These systems are highly reputable not only for the volumes pumped but also for requiring little maintenance when utilized in the right application.
However, as with other systems, downsides do exist. The biggest concern for ESPs is the cost. ESPs have a high initial purchase price and are very expensive to operate. The pump must be run down the well at the bottom end of the tubing string.
In addition, there is the expense of running an electrical cable from the surface on the outside of the tubing. A substantial electrical energy input is required.
Operations are not the only expense, as ESPs are very costly to service and maintain. When an ESP is pulled, the repair takes more time than most other systems and repair locations are not readily available. Aside from high associated costs, ESPs do not tolerate wellbore solids very well.