Because of their extremely high viscosity, heavy oil, extra-heavy oil, gas, and bitumen typically call for the application of specialized production methods. The use of progressive cavity pumps and flow assurance solutions are essential, despite the fact that the majority of industry participants have been concentrating on processes such as steam-aided gravity discharge (SAGD), cyclic steam injection (CSI), and steam recovery. When it comes to the transportation of multiphase fluids that have a high viscosity like crude oil, positive displacement pumps, and in particular the Progressive Cavity Pump (PCP), are an excellent choice. When compared to more typical pumping options available in the field, PCP is an efficient and cost-effective solution. Sand, water, natural gas, and crude oil are all found in these well streams. The relative amounts of each can change depending on the reservoir and the region. There are economic, environmental, and facility management benefits to be gained from combining the flow from the well with that of the collecting and treatment facilities rather than separating the components of the well site.
In order to successfully complete this transfer, the pumping system needs to be dependable, risk-free, and capable of adapting to a wide range of fluid characteristics and operating conditions. In recent years, numerous attempts have been made to boost production rates by implementing innovative reservoir stimulation strategies. The vast majority of these approaches are comprised of flow assurance and surface transfer mechanisms. When moving multi-stage fluids, such as those made up of a mixture of oil, water, gas, and solids, it is essential to select pumps that are up to the task (sand). In normal field developments, multiphase fluids will typically flow easily to collection stations through surface lines, which are driven by the natural formation pressure. However, heavy oil and extra-heavy oil provide particular difficulties for the flow of oil via pipelines due to the increased viscosity that results in significant friction losses. In order to effectively manage production rates, flow assurance is essential. The resistance of the flowline has an effect on output rates. When deciding on a production strategy for locations rich in heavy oil, this is a crucial consideration. A straightforward approach to increasing the flow of water from a well to the collecting and treatment plants makes use of a multi-stage pump and places one of the pumps near the wellhead. In this scenario, multiphase pumping is nothing more than a method of providing energy to the untreated fluids in the well.
This makes it possible for the mixture of liquid and gas to be moved over long distances without first being separated. Conventional separation close to or at the well site, as well as the utilization of multiphase pumps, are two examples of typical scenarios involving field separation operations. It is not always possible to achieve separation near to the location of the well, and if it is, it may require major infrastructure and financial expenditure. This results in an increase in the expenses associated with investments for installations due to the complexity or severe environmental conditions. According to the results of the analysis, the utilization of several pump stages is the approach that features the least amount of logistical complexity. A closed gas handling system that needs to vent the gas to the atmosphere very occasionally, if at all, is a more preferable alternative from an environmental point of view than an open system. In order to function properly, wellhead pumps and pumping rigs must be able to adapt to shifting process circumstances brought on by variations in the behavior or configuration of the wellbore. This is especially true due to the fact that multiphase pumps installed in depleted reservoirs frequently exhibit unstable circulation behavior, which consists of periods of active production followed by periods of inactivity in the production process. Another interesting fact is that inherent fractions of free gas can reach up to 90% in multi-phase crude oil streams.
Already confronted with challenging circumstances, the pumping team must persevere. It is possible for the pump to be affected when intermittent runs are factored into the equation. The amount of time that gas flow is restricted by slowdown might range anywhere from 15 minutes to many hours. The pump is responsible for adjusting to these variations. It is possible that the liquid will be transported along with the gas in either liquid or vapor form during the times when the gas is ascending. The worst-case scenario for the pump is when it runs dry over an extended length of time, which is also known as a dry pump. In order to guarantee the dependability and effectiveness of the equipment now in use, these difficulties in technical design and control need to be resolved. The flow of oil production is often a complicated mixture of oil, gas, water, and particles that frequently undergoes shifts in both their content and their speed. The synthetic lifting systems that are employed in more than 90% of oil wells across the world are made more difficult by the dynamic environment in which they operate. When designing a lifting system, one must keep in mind that all lifting systems are subject, albeit to varied degrees, to erosion and erosive attack by solid-laden product fluids. This fact is taken into consideration when the design is carried out.
The decentralized screw pumping method of artificial lifting is an efficient and affordable method that streamlines production, is resistant to erosion threats, and saves money. Stepper screw pumps, also known as positive displacement pumps (PCP), are used to move fluid by passing it through a succession of small cavities that are generated by the rotation of a helical rotor that is housed within the stator. These pumps are not only efficient at pumping viscous and abrasive liquids, but they also have the added benefit of being easily customizable to create liquids with variable temperatures, pressures, flow rates, and amounts of particles. At this time, PCP is extracted from around 50,000 wells across the globe. A PCP training and background system is often included as part of most PCP systems. The downhole positive displacement pump has both a stator and a helical rotor in its construction. The stator consists of a shell made of tubular steel with an inner sleeve made of elastomeric material that has a helical pattern on the surface of it. The action takes place in a shaft that is located beneath the production line. The rotor is a screw with a relatively small diameter that features deep, circular threads and a significant pitch (the distance between successive thread peaks). It is often constructed of carbon steel that has been chrome plated, and it is attached to the base of a chain of sucker rods. The arrangement of the coil that is housed within the stator casing is identical to that of the rotor; the only difference is that the stator coil has one additional thread than the rotor and a longer pitch.
The rotor is a perfect match against the stator, and it spins very well while it is contained within it. This configuration results in the formation of a number of cavities between the rotor and the stator that are of constant size but move in response to the rotation of the rotor. These cavities transport the production fluid through the pump in a pulsing linear flow. The PCP is able to pump at very low flow rates. However, the seals can leak at higher pressures because of the higher pressures. Using a longer downhole pump that has more cavities is one way to overcome this problem; positive cavity pumps (PCPs) typically have anywhere from two to twelve cavities. The PCP drive system is often installed above ground and consists of a motor that turns the drill string, which in turn rotates the spinning component of the stator. This cycle continues until the PCP drive system is completely exhausted. However, operators can prevent rod and casing wear in wells with long profiles or a high degree of bias by installing electric motors underground to revolve the rotor. These motors can be installed using electric motors. When compared to PCPs that use traditional surface drive systems, rodless PCP systems have the potential to lower failure rates by between 30 and 50 percent in oblique and horizontal wells.