Also included in the ESP section of the companion poster is a new application of a twin-screw multi-phase pump placed downhole. Hydraulic jet pumps HJP operate by pumping high pressure power fluid oil or water through a nozzle where it is converted to high velocity and low pressure. The low pressure allows wellbore fluids to enter the pump and the two streams are mixed, resulting in a single high velocity, low pressure stream.
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The combined stream then passes through a diffuser that converts the fluids back to low velocity and high pressure. The combined fluids are separated topsides with the power fluid being re-circulated back downhole. Because HJPs have no moving parts, they require little pump maintenance and have long service lives. Since the production rate is determined by the hydraulic fluid injection rate and pressure, jet pumps have good operating flexibility. Some common advantages of HJP's are listed below:.
The hydraulic piston pump HPP operates in much the same way as the jet pump except that the power fluid actuates a reciprocating piston pump downhole, as opp-osed to a jet pump see previous image for HJP. Unlike the jet pump, the HPP has moving parts and therefore may be prone to more mechanical problems. Since the production rate is determined by the hydraulic fluid injection rate and pressure, piston pumps also have good operating flexibility.
Some common advantages of piston pumps are:. The hydraulic submersible pumps HSP consist of a downhole hydraulic turbine driving a downhole centrifugal pump. Because of this, HSPs have a similar overall design as ESPs except without potential electrical problems as well as the ability to handle higher gas volume fractions GVF. HSPs also have a much shorter length than ESP's, which facilitates installation in wells with a high degree of deviation. Some common advantages of HSPs are:. Weir Pumps Ltd. The product, called Varris Vertically Accessed Riser with Retrievable Internal Services , also includes hot water circulation and is intended for use in deepwater risers.
The Varris can be deployed and retrieved using established well intervention methods without the requirement for external deepwater vessels. Also, there is no required infrastructure for installing Varris. It can be installed directly in the riser, including being retrofitted to existing developments. A progressing cavity pump PCP is a positive displacement pump that consists of a single helix rotor turning inside a double helix stator.
PEH:Artificial Lift Systems - PetroWiki
As the rotor turns, driven by a topsides motor, an advancing series of cavities are formed between the rotor and stator, in which the fluid is displaced through the pump and up the tubing. The stator is attached to the tubing string while the rotor is attached to a rod string, attached to and rotated by the topsides pump.
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As they are positive displacement pumps, PCPs have a high efficiency and are well-suited to heavy oils with high solids content. PCPs are rarely used offshore see poster, Table 2 due to low production rates and the necessity of a workover unit to pull the pump for repairs.
Some common advantages of PCPs are:. These pumps are multiphase units and can either be subsea or topsides. Topsides units do not technically help lift the fluids to the surface, but do reduce the back pressure on the reservoir. These units are therefore termed "pressure boosting" as opposed to being strictly identified as artificial lift systems. To date, only helico-axial and twin-screw multiphase pumps have been used offshore, with only helico-axial pumps having been deployed subsea.
Twin-screw pumps displace fluid through counter-rotating screws, moving a constant volume of fluid through the pump. Helico-axial pumps move fluid by first rotating the fluid at high revolutions per minute RPM with helico-axial impellers. The fluid is then passed through a diffuser which converts the high speed, high kinetic energy fluid to a high pressure fluid. Some common advantages of seabed pumps are:. Rod pumps consist of a surface pumping unit connected to a sucker rod pump downhole by a series of sucker rods.
The reciprocating action of the topsides unit moves a traveling valve on the downhole pump to move fluid to the surface. Rod pumping is almost exclusively limited to onshore applications comprising the vast majority of all land applications , but has occasionally been used on fixed structures in shallow water see poster, Table 2. Some common advantages of rod pumps are:. Julie E.
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She has 21 years experience, the last 13 years having been spent working in a lead position in the oil and gas, refining and gas production industries. Areas of expertise include flow assurance, process design and optimization, especially gas liquids extraction, and debottlenecking. Home Field Development Artificial lift and pressure boosting options for production enhancement Selection guide for eight major systems. One artificial lift technology, plunger lift, in which a free-traveling plunger is allowed to intermittently carry production to the surface, is not included in the survey since it is used only in low producing rate wells, typically Gas lift Gas lift is an artificial lift method in which pressurized gas is injected into the production fluid to lower the density of the combined fluids.
Gas lift. Click here to enlarge image The mandrels may be attached to the outside of the tubing string conventional or located inside the tubing string wireline retrievable. The disadvantages are: Compression cost may be high and compressor must be reliable Fair operating efficiency, but poor for intermittent gas lift. Electric submersible pump The electric submersible pump ESP is a multi-stage, centrifugal downhole pump driven by a downhole electric motor. Electric submersible pump. Click here to enlarge image ESPs are often used offshore since they require limited equipment topsides as most of the necessary equipment is downhole.
ESP disadvantages include: Narrow production rate range for a specific application Requires highly reliable electric power system Poor solids handling Poor gas handling without inlet gas separators. Hydraulic jet pump Hydraulic jet pumps HJP operate by pumping high pressure power fluid oil or water through a nozzle where it is converted to high velocity and low pressure.
Hydraulic jet pump. Click here to enlarge image The combined stream then passes through a diffuser that converts the fluids back to low velocity and high pressure. Some common advantages of HJP's are listed below: Little pump maintenance required Good operating production rate, depth, temperature flexibility Can be circulated hydraulically topsides "free" pump Good corrosion, solids, gas handling ability. The disadvantage to the HJP is: Poor efficiency.
Hydraulic piston pump The hydraulic piston pump HPP operates in much the same way as the jet pump except that the power fluid actuates a reciprocating piston pump downhole, as opp-osed to a jet pump see previous image for HJP.
The selection process should include a vision of the present as well as the future development of the field, without disregarding past experiences. It should also consider multidisciplinary efforts, mainly in the fields that are subjected to sustained, continuous development. This process definitely begins with the planning of drilling and termination, and the development strategy of the wells in question Clegg et al. For instance, when a well is designed diameter and route , many aspects should be shared beforehand with those who will play a direct role in selecting an artificial lift system, because it can limit the type of systems that can be used or the maximum extraction capacity there of, and therefore affect the development of the reservoir.
In addition, the reservoir department should provide information on the production forecast based on the implementation of a secondary recovery project or other development plan. The minimum technical competencies required by those who will participate directly in selection, design and analysis include:.
Performance analysis of the reservoir and surrounding areas PI - Productivity Index and formation damage are parameters that affect flow performance in reservoirs. During the selection and design process, one of the most important factors to be taken into consideration is a system's capacity to transfer power from the unit itself to the pump.
Therefore, casing diameter becomes one of the most important border conditions because it restricts not only tubing diameter, but also other elements such as sucker rods or centrifugal pump shafts. Dealing with the unpredictability of the failure of the elements of ALS that exceed said mechanical limit is an everyday task for Production Engineering Departments. Although some of the recommended procedures in this area are mentioned throughout this paper, it can be said that failure analysis and subsurface equipment testing following extraction are fundamental when it comes to making decisions regarding new designs or repairs.
In addition, if the analysis of the root cause of said failures concludes that the mechanical limit of the ALS has been reached, a change in production strategy is required. The following is an example of how the mechanical limit of an ALS can condition the development of an oil field, where oil production is the result of water injection as a secondary recovery method:. The project considers a gradual increase in water injection volumes in accordance with oil production decline normal situation in Sec.
The increase in water injection triggers an increase in total fluid per well and, therefore, in the power transmitted from the motor to the pump, which can cause the sucker rods mechanical or progressive cavity pumping or the centrifugal pump shafts to exceed maximum capacity. This situation can lead to the reconsideration of a restriction in the water injection volume or other distribution, because the optimum development of these projects is associated with the right balance between Injection and Production.
The analysis requires the proper logging of operating variables, in which their quality is fundamental in order to make the right decisions. These variables include:. The measurement of the volume produced by the different phases oil, water and gas is fundamental when it comes to evaluating not only well potential but also the performance of the production system itself. The first question we have to ask ourselves is "What do we need? Monitoring dynamic fluid level associated with the reservoir's dynamic pressure should be a part of essential monitoring routines.
They can be acquired by down hole sensors measuring suction pressure or at the surface using manual echo-sounders. Due to the importance of these measurements, along with production volume to determine reservoir potential volume vs. The following are examples of variable monitoring in different artificial lift systems: Figure 3 , 4 and 5.
After extracting Subsurface elements used in ALS from the well, inspection should be a part of the work routines at the companies using the different systems. These processes not only allow you to evaluate the performance of the equipment extracted, but also enable more in-depth failure analysis and the reuse of subsoil elements if they are within certain parameters.
The Technology of Artificial Lift Methods - Volume 4 (Kermit E. Brown)
As regards the reuse of materials, this does not mean elements deficient in quality are going to be installed in the well, because you have to bear in mind that one of our objectives is to maximize the life cycle of production wells. Proper classification of materials based on the traceability of their history will help us save a great deal on production costs. The following is a description of examples associated with inspection and the performance analysis of subsoil equipment extracted from the well of the main ALS:.
Visual and dimensional rotor inspection. Chrome plating of those that lose only the external cover. Performance testing in test bench, logging of the volume, power and torque required for different pressures and RPM. Identification of deformation cycles accumulated by stator elastomer before testing as criteria for acceptance and disposal Hirschfeldt, Figure 6 and 7. Disassembly of pumps for dimensional control, eliminate scaling or plugging due to heavy crude during the different stages and subsequent reuse of the elements.
Motor testing and repair: Drying of winding, condition of bearings, dielectric state of winding, etc. As regards ALS management, both failure analysis and statistical monitoring and logging are important when it comes to providing feedback for the decisionmaking circuit. It is a well-known fact that a recurring failure in a key ALS element not only causes production losses, but also gives rise to costs associated with pulling services to replace elements of the installed system.
All the above translates into the reliability of the equipment that many times is not only associated with installing expensive equipment, but also knowing about previous experiences based on the historic log of failures and their respective root cause analyses. The use of performance indicators is important when it comes to making decisions or monitoring the evolution of a field as regards failures in ALS elements. Classic indicators include:. This indicator can be logged month by month and it allows you to forecast the number of failures wells will have on average in one year.
For instance, if we have a population of production wells and, in one month, we have 5 interventions with pulling equipment due to failures in the wells, we have:. This means each well would fail 0,6 times per year, or that the life cycle of a well is approximately 1,6 years. This simple indicator can be applied to monitor failures per well, per field, per type of ALS, per system element rods, pump, tubing, etc.
This is an everyday situation in most oil fields in the world and the following are several possible scenarios:. As this demand increases, the system is inefficient at times from the energy standpoint as well as due to the lack of gas compression capacity high costs, maintenance, gas shortage, etc. Due to the decrease in the gas: liquid ratio increase in liquid column density , depending on the liquid volume to be extracted, it may be possible to migrate to an intermittent BN system, plunger lift, mechanical pumping, or perhaps an electric centrifugal pumping system ESP depending on production potential.
Where depending on reservoir pressure and petro physical parameters, the decline can take place over several years' time between 5 and 10 years , or even less, such as the case of reservoirs with very low permeability with sudden declines over the first 6 months of development:. The ESP installation is the first choice due to the mechanical pumping limitations for the assumed conditions of depth and volume. As well production begins to decline decrease in the potential fluid volume , the mechanical pumping system may be the alternative to cover a wide range of volumes during the remaining productive life.
During its history of decline previous case , a well can end its productive life cycle with a mechanical pumping system with a low production rate and smalldiameter pumps. When water injection starts in an adjacent secondary recovery project, productivity associated with the increase in reservoir pressure will rise, so depending on the mechanical limit and flexibility of the current system, changing over to other systems such as progressive cavity PCP or electric centrifugal pumping ECP is a step to be taken into consideration.
Based on the productive history of the oil fields, and as its power is modified, different ALS can be used to adapt to their requirements. Figure 10 illustrates the productive history of a well and the possible ALS changes throughout the life thereof. Progressive Cavity Pumping PCP : The flexibility of this system makes changes in extraction rate fast and simple, as the output of fluid from the reservoir increases. Since new perforations are opened at a deeper level to expand the secondary recovery project, the ECP system allows the extraction of these volumes at said depths, perhaps exceeding the mechanical limit of the sucker rods of a PCP system.
As we have gone over throughout this article, comprehensive ALS management in an oil field is associated with different stages that involve stakeholders, including people, sectors and companies. The different management models depend on the ALS experience of operating companies and their professionals. The following are two possible scenarios that represent cases existing in the Latin American region.
They can be in condition to evaluate and select the products offered on the market as well as the service companies associated with said products Figure Depending on the size of these companies, many time acquisition takes place by alliance between operators and services , which also include maintenance, inspection, monitoring and engineering services, among others. The Production Engineers of the operating companies also play an active role in testing equipment, evaluating performance and analyzing failures, at either their own laboratories or those of the service companies.
Design, selection and installation are almost entirely delegated in the companies that supply these products, with practically minimal participation of the oil field operators in this stage Figure As regards the acquisition of the equipment related to each ALS, it is often based on framework agreements or alliances where the service companies design, provide and operate the ALS in which the equipment for each well is leased in many cases. This method would be a good start during the learning curve of operators, because it is important to depend on the experience of service companies in this regard.
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But in many cases, the practically full delegation of ALS management disregards the responsibilities of those who should be carrying out the process, such as the areas of Production Engineering or Development, because not only is optimum reservoir development at stake, but also the costs associated with the development of the fields costs of materials, services, power, etc. Another possible disadvantage of these models is that they are usually static and Production Engineers find that the only options to choose an ALS are delimited by a framework agreement.
This situation may prevent people from choosing alternatives that actually match the needs of the well or field to be developed. In order to increase the involvement of operators in this management process Case A , you should start out with comprehensive training for the professionals related to the activity to get to know the types of ALS, their principles of operation, mechanical limits and maintenance requirements, among other important aspects.