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With more than 95% of wells requiring artificial lift installation from the outset of production, selecting the appropriate artificial lift option is vital to production economics.
Editor’s Note: Part 2 of a two-part series provides an overview of progressing cavity pumps, jet pumps, plunger lift and gas lift.
Although a full range of artificial lift solutions is available with various capabilities to tackle the task of increasing the flow of crude oil from a producing well, the traditional sucker-rod pump tends to outweigh the others. In addition to the many advantages described, sucker-rod pumps are typically the preferred method for long lateral and deviated wells. Further, these systems provide stronger reliability and flexibility than the other artificial lift options.
Yet, sucker rod pumps should not be the automatic choice for all artificial lift solutions. In each instance, it is critical to determine what lift system will deliver the best results for a particular well instead of trying to always apply one method across-the-board to the wide range of wellbore conditions.
It is also necessary to carefully consider variables such as the economic input, system reliability, horsepower usage, equipment maintenance and service personnel limitations, and the overall operations.
Progressing Cavity Pumps Are For Shallower Wells
Widely utilized throughout the oilfield, the progressing cavity pump system (PCP), in the most basic description of its parts, is comprised of a stator and rotor (Fig. 2).
|Figure 2: Details are shown of the 44 Series Downhole PC (Progressive Cavity) Pump. [Illustrations courtesy of NOV Monoflo]|
The rod string and rotor are the only downhole moving parts. As the rotor turns inside the stator, it displaces liquid through progressing sealed cavities forcing the fluid to the surface, effectively handling a range from high viscosity crude to multiphase fluids.
PCPs are able to achieve relatively high volumes and are more suitable than most other artificial lift options when wellbore solids are a concern. These pumps have proven to handle more than 50% solids in production.
These have also proven to handle more than 50% gas production; however, the pumps do require some fluid production to provide lubrication to the elastomer.
PCPs using components manufactured from elastomers may swell and grip the rotor increasingly tighter until equipment failure results. Compounding system elastomer sensitivities and a propensity toward failure, PCPs will not tolerate a lack of wellbore fluid or high levels of H2S and CO2 without causing the elastomers to fail. At an Australian site, where shale gas wells have a high fluid level, the wells were pumped off and then a rod-pump system was installed.
Once operators start pumping off a well, which is the industry-preferred procedure, the well’s gas content is increased, creating the previously discussed problems.
PCPs were originally implemented to pump heavy oil and are mainly limited by design and depth. That suitability is particularly the case when not constrained by high GOR and intermittent inflow issues. For example, some operators state they will successfully run PCPs to depths in excess of 6,500 ft while others see problems after 3,500 ft if the wellbore conditions are not ideally suited.
There are two ways of running a PCP system surface unit, an electric prime mover or a natural gas set-up (Fig. 3).
|Figure 3: C-50 Electric PC Pump Drivehead operates the progressive cavity pump.|
With an electric motor, a transmission line or a gas-powered generator must be installed on the surface. Alternatively, running hydraulics is necessary but is not as efficient when compared to a conventional pump jack.
The adoption of PCP systems has been particularly prevalent In Canada. For instance, one area was primarily pumped with rod pumps in the 1970s and 1980s. Once it was determined that PCPs could handle the oil, most of the wells have been completed with 3.5-inch tubing. The larger tubing is one of the prerequisites to have a sound PCP installation.
When moving into deeper wells, such as tight oil, many producers are reluctant to drill 7-inch casing to run 3.5-inch tubing on the inside. This reluctance is particularly driven by economic consideration, since downhole PC pumps can be considerably more expensive than sucker-rod pumps.
Jet Pumps Are For High Solids, Heavy Oil
A jet pump system consists of a surface pump that moves fluid to the subsurface throat and nozzle assembly, thereby transferring the power fluid’s energy to the wellbore fluid and thus lifting it to the surface. Commonly utilized types of jet pumps are applicable to shallow well and deep well installations. Applications range from crooked wellbores to high solids and heavy oil.
Since jet pumps require fluid input, installation of a high pressure pump on the surface is required. With no moving parts, this pump is robust but is subject to considerable wear and tear as well as being a horsepower burner compared to other options such as sucker-rod pumps.
Taking Canada as an example, jet pump installations have dramatically decreased due to the associated maintenance and other associated costs.
On an everyday basis, jet pumps have as many downsides as upsides. While they can contend with wellbore solids and gas, these pumps are also frequently sensitive to changing wellbore conditions and require high economic investment for the required surface equipment.
When those issues are compounded with a lack of skilled application technicians and operators, it makes for a lift system that is difficult to operate. As a result, jet pumps appear to have a limited future in the oilfield.
Plunger Lift Is Least Expensive To Install, Operate
Plunger-lift systems use the build-up of gas pressure in the casing and tubing to move a steel plunger and the fluid above it up to the surface; the plunger essentially functions as a piston between liquid and gas (Fig. 4).
|Figure 4: Surface and downhole plunger lift system equipment is shown.|
Of all the artificial lift options, plunger lift is the least expensive to install and operate. Given the appropriate well conditions, it is a very efficient form of lift.
When sufficient downhole pressure exists, plunger lift often is the system of choice. However, once fluid level and downhole pressures decline, then a plunger system needs to be replaced. Additionally, when dealing with horizontal or deviated wells, the plunger-lift system has a low operational success rate. While being very economical and efficient, plunger lift yields marginal production over the life of the well.
In the context of horizontals and shale beds with initially high fluid volumes but limited downhole pressure, the plunger-lift lifecycle approaches its end fairly quickly. When the plunger lift cannot maintain the desired production levels following the decrease of subsurface pressure, a rod pumping system is the typical replacement choice.
Gas Lift Relies On Wellbore Gas
Gas lift systems function by injecting gas into the tubing. This process lowers the hydrostatic column weight, which, in turn, also lowers backpressure. That sequence lets reservoir pressure force produced fluids upward to the well surface. In utilizing gas lift, an either/or situation is in play. The system can be very successful, provided the availability of sufficient wellbore gas.
The absence of subsurface gas calls for a completely different approach, i.e. a situation similar to jet and hydraulic rod pumping whereby a heavy investment in surface equipment is required.
To further complicate matters, added economic input and infrastructure are required to supply the necessary natural gas. In remote locations, which are often the rule rather than the exception, using gas lift is especially challenging.
However, servicing is relatively economical since most can be done with wirelines. The major drawback is the availability of natural gas for gasless wells.
Editor’s Note: Derek Krilow is product line manager, engineering and design, with National Oilwell Varco (NOV) Monoflo (Derek.Krilow@nov.com) and Josh Metz is senior production engineer tech, Apache Corp. (Joshua.Metz@apachecorp.com).