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Abstract Implementing a new configuration for the drive head for progressive cavity pumps can solve many operational problems and lower operational costs.Capable of handleing high sand loads keeps the pumps on and reduces downtime.Simplicity of design makes them easier and cheaper to build and maintain.Simple design of inline motor to a gear reducer coupled to the polish rod eliminates the problems and dangers associated with conventional belt and pulley configurations.When coupled with a power inverter the drive head speed can be reduced to 50% of capacity, allowing for quick pump saving adjustments. Introduction Progressive cavity pumps (PCP) are now used throughout the oilfield for lifting viscous and sediment laden fuids.The original drive head configuration was a belt and pulley system to rotate the rods and pump in the well.Fluid enters the pump and the rotation of the rotor in the stator sends the fluid to the surface.Changing downhole hole conditions can change the torque necessary to turn the rotor.When this happens, drive belts burn on the pulleys and the system fails.In Parrylands Field the producing Forest Formation is unconsolidated and periodically gives up slugs of sand.The sand slugs increase friction in the pump and increase the necessary torque to turn the pump.Utilization of a direct drive system can meet the demand of the increased torque from a sand slug, pumping it to the surface and preventing failure. PCP Oilfield use Progressive cavity pump key components are the rotor and stator. The rotor is an external helix machined from high-strength steel. The stator is an internal helix molded of tough, abrasion-resistant elastomer, permanently bonded within a steel tube. The stator always has one more helix than the rotor to facilitate the progressing cavity pumping action. As the rotor turns within the stator, cavities are formed which progress from the suction to the discharge end of the pump, conveying the process fluid. The continuous seal line between the rotor and the stator helices keeps the fluid moving steadily at a fixed flow rate proportional to the pump's rotational speed. Initial pump design was for clean fluids.As needed, variations in stator materials, soft to hard, low temperature to high temperatiure, and close fit to loose fit of the rotor in the stator have been developed to handle various materials.Field experience has shown that the pump is capable of moving fluid with up to 50% sand with a soft nitril elastomer stator.With slugs of sand, the torque on the pump and drive motor can increase 50% as measured by the static amp load.Normal motor load is less than 3 amps with 50% sand laden fluid it can exceed 6 amps. Investigation and Analysis The conventional drive system is configured with a 1725 rpm electric motor, pulleys and belts to reduce the speed at the drive string to 100 rpm for the downhole PCP.Increased torque conditions downhole are immediately transferred to the surface pulleys and belts.If the belts are not set right they slip and break. The main challenges faced were keeping belts on the pulleys of the drive head system so that the unit(s) operated on a continuous basis.Further, reservoir conditions required us to frequently vary the speed of the drive head in response to fluid level dynamics which proved difficult. Initial work on these challenges began with the analysis of the weakest link; the belts and pulleys in the drive head assembly that rotate the rod string to actuate a progressive cavity pump (PCP).
- North America > United States (0.47)
- Europe > Norway > Norwegian Sea (0.24)
Abstract The progressing cavity (PC) pump is well established as the pump of choice for handling abrasive solids. PC pump design can be optimized to achieve the best wear performance available for a given size. The wear optimization of the PC pumps is achieved through geometric design for minimum internal fluid velocities and by selecting proper materials of construction. Wear causes PC pump failure by gradually reducing the volumetric efficiency and increasing pump slippage. This paper focuses on the parameters that influence pump wear, describes wear mechanisms, reviews design techniques for wear optimization, and presents field data to support some of the claims. Background Pump Design Parameters. Figure 1 shows the cross section of a progressing cavity pump. Definitions: Ps Stator Pitch D Rotor/Stator Minor Diameter Ecc Rotor Eccentricity A progressing cavity pump consists of a helical steel rotor which turns within a stationary tube with a helical elastomeric lining (stator). As the rotor turns inside the stator, fluid moves through the pump from cavity to cavity. As one cavity diminishes, the opposing cavity increases at exactly the same rate which results in a pulsationless positive displacement flow through the pump. The cavities are separated from each other by a series of seal lines which are created between the rotor and stator. The pressure capability of a pump is a function of the number of times the progressing seal lines are repeated. PC pump manufacturers rate the pressure capability of a pump as a function of the number of pump stages. Although somewhat arbitrary, each stage is between one to one and a half of a stator pitch length and is capable of handling 100 psi differential. If cavity pressure increases beyond the seal limits, the seal lines will open, and fluid will "slip" from one cavity to the other at a very high speed. The PC pump slippage is generally a function of pressure differential across the pump and it changes depending on the compression fit of the rotor and stator. Flow Rate. Pump flow rate is a function of design parameters such as stator pitch (Ps), rotor diameter (D), and pump eccentricity (Ecc). Equation 1, defines this function: Q = K*Ps*4*Ecc*D*N where: Q flow rate N number of revolutions per unit time K conversion factor Equation 1. Fluid Velocity. Nominally, for each rotation of the rotor, fluid will move one pitch length of the stator. Therefore, fluid nominal velocity in the axial direction of the pump is defined by Equation 2: Equation 2. Assumes that the fluid particles travel along a Vfluid= C*Ps * N Where: Vfluid nominal fluid velocity N = number of revolutions per unit time C = conversion factor Equation 2. P. 547^
Abstract Recent changes, upgrades and development in artificial lift equipment have expanded the considerations for selection of pumping method. This paper covers sucker rod pumping, continuous gas-lift, intermittent gas-lift, electric submersible pumping, hydraulic reciprocating pumping, hydraulic jet systems, plunger lift, progressing cavity pumping, and additional miscellaneous pumping methods. Changes in well conditions and equipment capabilities demand timely reviews of the original lift method decision to determine if it is still thebest choice. Often the selection of the lift method is based on operating personnel/decision tree should be a long term economic analysis. This paper will consider how new advances in individual methods have changed their cost effectiveness and provided solutions to unique problems. There is not a single lift system that is the most economic system for all wells. In order to access the practically and the economics of various methods of artificial lift, the first step is to generate an IPR (Inflow Performance Relationship) curve or a PI (Productivity Index). Then a profile of expected and desired production versus time should be determined. Figures 1 & 2. With the above information, potential artificial lift methods can be introduced, including expected run lives and cost considerations for the most obvious methods. Detailed cost estimates of the well operating cost are then reported and compared to the numbers used in the economic evaluation of the field. The economics of low rate wells and high rate wells need to be adjusted to account for the economics of the project.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Well performance, inflow performance (1.00)
- Production and Well Operations > Artificial Lift Systems > Progressing cavity pumps (1.00)
- Production and Well Operations > Artificial Lift Systems > Hydraulic and jet pumps (1.00)
- (3 more...)
Abstract With operating costs playing a larger and larger role in the economics of producing a well, optimizing equipment selection by means of an efficient artificial lift system is critical in reducing operating costs for a given field. Six wells in Carter County, Oklahoma, utilizing three different methods of artificial lift were looked at to compare overall system efficiencies between each method. Progressing cavity, reciprocating, and electric submersible pumps were compared on a per barrel of fluid produced basis and the electrical power usage converted to kw-hr/hr. MEASUREMENT PROCEDURE Each of the six wells looked at for this study had been operating for some time and therefore had stabilized operating conditions. Production data was taken using existing test facilities and average producing fluid levels were used. No gas production was present. Table 1.0 gives the well parameters for Wells A through F and Figure 1.0 shows the general configuration of the pump systems. Electrical power usage was measured utilizing an AC Motor/Load Surveyor. Table 2.0 shows the measured power parameters for each well. EFFICIENCY CALCULATIONS Each of the methods of artificial lift will be looked at separately and their respective efficiencies calculated. In each case, the prime movers were electric motors so by definition, the efficiency is arrived at by dividing the useful system output, Ho, (shown in Eqn. 1.0), by the input motor horsepower, Hip, and then multiplying by 100. The input horsepower, Hip, will be taken as the average kilowatts input, KW, divided by 0.746. Since the overall water cut for the field is 98%, and the wells are relatively shallow, the losses from the surface to the pump were negligible. For this reason the efficiencies at the surface, , and at the pump discharge,, are the same. It is important to note that when comparing different methods of artificial lift according to their efficiencies, it is a good practice to use the same efficiency formula. P. 389^
- North America > United States > Oklahoma > Oklahoma County (0.36)
- North America > United States > Oklahoma > Carter County (0.25)
Abstract Results of a field test study proved that progressive Cavity (PC) pumping systems provide greater mechanical efficiency and less electrical usage than beam and electrical submersible pumping (esp) systems in mature waterflood producing wells. These systems were evaluated in Permian Basin wells ranging from 3800 feet to 5000 feet in depth and production rates ranging from 500 barrels per day to 1000 barrel per day. Operating facilities were used to monitor production, fluid shots were used to monitor fluid levels, and inline mechanical kw-hr meters were used to measure electrical usages before and after PC pump system installations. Mechanical efficiencies were calculated based upon this data. Production tests indicate that total well productivity was increased and an incremental oil increase was realized where PC pumping systems replaced beam lift systems previously thought to be optimum. Increased water production due to waterflooding has necessitated lift revisions and beam pump optimization. When a beam lift system has reached maximum potential, a larger lift system becomes necessary. Esp systems provide increased lift capability, but at a much lower efficiency. The criteria used for selecting the test wells was maximized beam lift and economically marginal esp producing systems. The purpose for the field test was to determine if PC pumping systems were an economic alternative to lift these high WOR wells when compared to beam and esp systems. A field test study was began in 1991 to evaluate mechanical and electrical efficiencies of PC pumping systems in the environment stated above. A comparative analysis to beam and esp lift systems was then performed. This paper presents the results of that analysis and confirms that PC pumping systems are the most cost effective artificial lift systems in mature Permian Basin waterflood producing wells. Introduction The maturing of a water flood creates constant changes which affect artificial lift design. Most often, the volume lifted must be increased while the percent of oil in the produced fluid decreases. This increase in expense and decrease in return on capital places many producing wells in a marginally economic position. The need to lift greater volumes of fluid more efficiently propagated the exploration of artificial lift alternatives that are more economically attractive. A project was established to evaluate the performance of Progressive Cavity pumping systems as an alternative lift mechanism in high volume (500-1000 bbls. per day) beam pumped wells and low volume (800-1000 bbls. per day) esp produced wells ranging in depths of 3800 feet to 5000 feet. P. 123^
- North America > United States > Texas (0.92)
- North America > United States > New Mexico (0.82)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.31)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (23 more...)
Abstract The progressing cavity (PC) pump has been used as fluid transfer pump for many years. From various industrial applications to surface transfer of oilfield fluids. Within the last several years the progressing cavity pump has been widely used as a progressing cavity pump has been widely used as a method of artificial lift for the oil and gas industry. The use of progressing cavity pumps as a means of artificial lift has numerous advantages over other artificial lift methods. Through years of research and development in progressing cavity pump design, the production and lift capabilities are expanding to cover a wide range of applications. With various elastomeric materials available, a wide range of well fluids can be handled efficiently using the progressing cavity pump. The ability to pump abrasive fluids lends itself well to many of the viscous sand laden crudes found throughout the world. With present lift capabilities from 4000 feet and capacities to 1000 BFPD, the progressing cavity pump is ever expanding and becoming a viable alternative for wells utilizing artificial lift. Introduction The most common progressing cavity design is one of a single helical rotor rotating eccentrically inside a double threaded helical elastomeric stator of twice the pitch length. The number of seal lines determines the pressure capabilities of the pump is one of the determining factors of the slip experienced within the pump. Fluid viscosity and the compression fit between the rotor and stator are the two other determining factors for slippage. Theoretical displacement at zero psi is directly proportional to the cross-sectional diameter of the proportional to the cross-sectional diameter of the rotor, the rotor's eccentricity, the pitch length of the stator helix, and the pump's rotational speed. The stator's elastomeric gear lends itself well to use in a wide range of applications. A single particular pump size can easily be adjusted to handle particular pump size can easily be adjusted to handle varying production rates. With present lift capabilities from 4000 feet (1219 m) and capacities to 1000 BFPD (159 m3/day), the areas for progressing cavity pump usage is ever expanding. Compared to other methods of artificial lift in similar applications, the progressing cavity pump is normally the more efficient means of artificial lift. The low initial investment, ease of installation and minimal maintenance are other advantages the progressing cavity pump has over other methods. progressing cavity pump has over other methods. PROGRESSING CAVITY PRINCIPLE PROGRESSING CAVITY PRINCIPLE The progressing cavity pump consists of a single helical gear (rotor) which rotates inside a double helical elastomeric gear (stator) of the same minor diameter and twice the pitch length. See Figure 1. As the rotor rotates eccentrically within the stator, a series of sealed cavities form 180 degrees apart which progress from the suction to the discharge ends of the pump. As one cavity diminishes, another is created at the same rate resulting in a constant non-pulsating flow. The total cross-sectional area of the cavities remains the same regardless of the position of the rotor in the stator as shown in position of the rotor in the stator as shown in Figure 2. The progressing cavity pump overcomes pressure because it has a complete seal line between pressure because it has a complete seal line between the rotor and stator for each cavity. The pressure capabilities in the pump are based on the number of stages and the number of times the seal lines are repeated. Normally a stage is designed and manufactured to be 1.1 to 1.5 times the pitch length of the stator. The reason for this is to insure a proper seal between the rotor and stator to achieve proper seal between the rotor and stator to achieve the desired psi/stage rating in order to sustain a desirable operating life. Figure 3 shows this relationship between the rotor and stator pitch lengths. P. 429
Abstract In selecting production equipment for a given well, the highest efficiency and the lowest required horsepower is the ideal situation. The progressing cavity pumping system is more efficient and requires less horsepower than the plunger pumping system at 150 BPD and 500 BPD from 2000 feet and 4000 feet respectively. Introduction The design of the most common progressing cavity pump is one that consists of 1) a single helical gear turning eccentrically inside a 2) double helical elastomeric gear of the same minor diameter. Figure I shows this relationship. The single helical gear is called a rotor and is normally made of tool steel and is chrome plated. The double helical gear is called a stator and is made up of an elastomeric gear permanently bonded inside a steel tube. The stator is normally connected to the bottom of the production tubing with the rotor connected to the bottom of the rod string and suspended completely within the stator. As the rotor is rotated within the stator, a series of cavities are formed which progress from the suction to the discharge of the pump. The cavity cross-sectional area depends on the rotor diameter and eccentricity. Figure 2 shows the relationship of the cavity diameter and eccentricity. The pitch of the stator is what determines the velocity of the fluid through the pump. For every rotation of the rotor, the fluid moves on pitch length of the stator. The following expression yields the velocity. Since the cross-sectional area of the cavities remain the same, independent of the rotor position, the volume remains constant resulting in a nonpulsating flow. Flow through the pump is along a path which is the shortest distance between the suction and the discharge of each stage resulting in low velocity and shear for a given displacement. The total displacement is a function of the speed at which the rotor is rotated within the stator. The flow formula Q=AV can now be used substituting the known values. A series of seal lines are formed by a compression fit between the rotor and the stator elastomer. The number of seal lines dictates the pressure capabilities of the pump. In order to insure that there is a complete seal line, one stage of the stator consists of 1.5 pitches, twice that of the rotor. The design of the conventional pumping system consists of four essential elements:a working barrel, a plunger, a standing valve, and a traveling valve. The system operates under a reciprocating motion transferring the hydraulic loads between the standing valve and the traveling valve. On the down stroke the traveling valve is open and is filling the barrel placing the load on the standing valve and tubing string. On the up stroke, the traveling valve is closed and the standing valve is open allowing fluid to enter the pump transferring the load to the rod string. Both pumping systems consist of a positive displacement pump of virtually equal pump efficiencies. Due to the difference in surface equipment efficiencies, the progressing cavity system will be shown to be more efficient. P. 87^