Mesa Natural Gas Solutions has a goal of building and maintaining the best professional relations in our industry. Part of completing this goal is having an honest transparent, reliable relationship with our customers. In order to do this we see great value in creating a more informed consumer. Electrical Submersible Pump Systems (ESP) can be an area of great confusion and we get a variety of questions in this area. The focus of this article is to inform you on the basics of ESP’s in order to help you make the right choice for your power generation needs.
The term “production characteristics” encompasses a variety of measurable and, often, augmentable physical attributes of a well, the underlying geological formation(s), and the hydrocarbons trapped within. Given an appropriate combination of these characteristics, the natural energy of a reservoir can be enough to push oil and gas to the surface. The “oil gusher” where oil squirts from the ground after being tapped is the quintessential example of such an occurrence. The image of oil shooting hundreds of feet into the air and of workmen scrambling to escape the torrent of oil has played out in popular culture for the better part of the past century. Today, engineers use advanced drilling techniques and put in place mechanical barriers to prevent such blowouts. Even then, accidents can and will happen.
While some wells are capable of natural production, most wells are not, therefore requiring some sort of assistance referred to as artificial lift. Not only may a newly completed well not be capable of natural production, but the reservoir pressure and production rate of older wells and mature formations will fall off over time, as well. The decline is inevitable. Engineers today use decline curve analysis to extrapolate trends in the production data from oil or gas wells. Doing so allows them to predict, within a certain level of confidence, future production rates and the estimated ultimate recoverable (EUR) reserves.
A typical decline curve analysis.
Beyond a certain point on the decline curve, there will be insufficient pressure in the reservoir to lift the produced fluids to the surface. It may be years, even decades, before production reaches that point, or it could be a matter of months. If it is determined to be economically viable, engineers can employ a method of artificial lift to drive further production. One such method is the electrical submersible pump, typically called an ESP.
An ESP is an efficient, reliable and highly versatile method of lifting production fluids to the surface. They can handle a wide range of fluid volumes and lift requirements, as well as operate in a range of harsh environments, such as in high-temperature wellbores or in the presence of corrosive fluids. An ESP system is typically comprised of the following components:
Multistage centrifugal pump
Three-phase induction motor
Power solution (Mesa Generator)
The components normally hang from the wellhead on a string of production tubing, the pump on top, seal section in the middle, and motor attached below, all connected to the surface controller and power source via the power cable. The final design of both the surface and downhole components can vary significantly depending on the specific application, conditions or operating requirements. Typical downhole ESP components are manufactured in varying lengths up to approximately 30 feet (9.14 m). The overall length and diameter of the ESP system are a function of the casing diameter, production characteristics and horsepower necessary to deliver the desired flow rate. If need be, it is possible to multiply any one of the components and connect them in series.
The pump itself is a multistage centrifugal pump comprised of stages stacked in series. Each stage consists of a rotating impeller and stationary diffuser, which directs the flow of the production fluid to the next stage. Driven by the induction motor below, the impeller transfers its energy to the fluid in the form of kinetic energy, corresponding to the velocity at the impeller’s edge. The stationary diffuser forces the fluid to turn up into the next stage, thereby converting the velocity of the fluid into pressure. As the impeller spins faster or increases in size, the velocity and conversion of energy increases, as well. The fluid passes through each successive stage, incrementally gaining pressure until it reaches the designed discharge pressure.
ESP stage – rotating impeller and stationary diffuser
The pressure rise created by the pump is often referred to as the total developed head (TDH). Head refers to the height of the liquid column the ESP could create from the transfer of kinetic energy to the fluid. The ESP will pump all fluids – independent of specific gravity – to the same height given the rotational frequency of the shaft remains constant, the only difference will be the amount of power necessary to rotate the shaft at the proper rpm.
The ESP motor is typically a two-pole, squirrel cage, induction electric motor. They are manufactured in a variety of horsepower ratings, operating voltages and currents. On a 60 Hz system, two-pole induction motors run at 3600-rpm synchronous speed or roughly 3,500-rpm actual operating speed. One type of surface controller, the fixed speed drive, maintains a constant motor speed with no regard to changing downhole conditions. This can reduce the efficiency and run life of the ESP system, increase operating costs, and result in higher incidences of downtime. A variable speed drive (VSD) adapts to changing well conditions by adjusting the speed of the motor. The ability to operate across a wider range of speeds increases the run life of the ESP system, decreases downtime and operating costs, and enhances production.
Oil and gas operators are increasingly turning to portable natural gas generators to supply power to VSD’s….