Oil & Gas News
Friday, 20 March 2009
PCP Systems - Installation & Optimisation
By Sandy Williams, ALP (Artificial Lift Performance), & J F Lea, PLTech LLC
A PCP system is made up of three principal components:
Figure 1 - Typical PCP System Configuration
Figure 2 - PCP Installation, hydraulic drive
Figure 3 - One manufacturer's rate/head chart
PCPs are particularly well suited to pumping the following types of fluid:
Since the PCP is a positive displacement pump its performance is not affected by pressure across the pump. However, with increasing pump differential the seal between the individual cavities is not adequate and slippage of the pumped fluid takes place resulting in a drop in pump efficiency. Pump efficiency is a function of the interference fit between the rotor and stator and the viscosity of the fluid pumped.
Figure 4 - Pump curve for a PCP rated for 170 bfpd per 100 rpm and a maximum head of 4000 ft H2O. Note: drop in efficiency with increasing head, increasing HP and increasing head
Figure 4 shows a pump curve for a PCP. Head is plotted on the x-axis and flowrate is plotted on the y-axis (note this is the opposite of an ESP pump curve); flowrate only increases with increasing RPM. With increasing pump head the flow rate is initially constant until slippage starts to occur in the pump; pump flowrate then drops with increasing head.
PCP pressure limitation is a function of:
Total power system efficiency is usually higher for PCPs than other forms of artificial lift system, as demonstrated by the following table:
The pump consists of two helices, one inside the other, which constitutes a helical gear:
The geometry of the assembly is such that it constitutes a series of identical, separate cavities. When the rotor is rotated inside the stator these cavities move axially from one end of the stator to the other, from suction to discharge, creating the pumping action.
Pumps are described by the ratio of lobes created by the rotor and stator geometry. The most typical pump for oil production is a pump with a 1:2 geometry is referred to as a single lobe pump and creates geometry as follows:
At any cross-section the number of cavities is equal to the number of lobes on the stator i.e. for a 1:2 geometry there are 2 cavities 180O apart. Cavities are one stator pitch in length. One cavity starts where the other ends. The pitch of the rotor is one-half that of the stator.
In addition to single lobe pumps some manufacturers have designs for multilobe systems, where additional lobes are added to the rotor and stator.
Pump dimensions are identified using the following terminology:
At any cross section of the pump the area of fluid is equal to:
And the volume of fluid per cavity is equal to:
Taking into account units the theoretical pump displacement (single lobe pump) can be determined from:
PD = pump displacement (bbl/day/rpm)
The same equation is applicable for calculating flowrate using metric units if the constant is changed to 5.7E-6. The flowrate calculated will be in m3/day/rpm.
and total flow is calculated as:
Q = flowrate (bbl/day)
RPM = Pump rotational speed (RPM)
The calculated Q will differ from actual production rates at surface due to:
Volumetric efficiencies of 70 – 80% are typical.
PCP manufacturers do not usually publish figures on the pump eccentricity, diameter of the rotor and stator pitch and so it is difficult to manually calculate pump rates. Instead manufacturers provide a pump curve and a value for displacement (bbl/day/rpm) and maximum pressure differential rating in terms of head or psi for a specific rotor elastomer.
Historically, PCP manufactures have not used the same convention for naming of pumps although most pump names have numbers in the name that provide an indication of pump displacement and maximum differential pressure in either metric or imperial units e.g.
Moyno 50-N-340 - maximum head of 5000 ft displacement of 340 bbl/day/100rpm,.
PCM 15-TP-1200 - displacement of 15 m3/day at 500 rpm with zero head, maximum head of 1200 m.
In order to know what each pump name meant it was necessary to know the manufacturer and their designation of pump type. Not, only was their nomenclature different but so were their graphs of pump performance.
Through ISO 15136 manufacturers are moving to use one standard terminology which will simplify the understanding of pump types. Under this standard the following terminology will be used for stators:
vvv = nominal capacity per rpm expressed in units of cubic metres per 100 rpm
hhhh = nominal head rating (metres of water)
eee = the elastomer code
and for rotors:
vvv = nominal capacity per rpm expressed in units of cubic metres per 100 rpm
hhhh = nominal head rating (metres of water)
rrr = the rotor size code
The pump stator consists of a metal housing with the elastomer stator bonded to the wall of the housing. The length of the housing may vary depending on the number of stages required to support the pressure differential across the pump. A rule of thumb is that a pressure differential of 65 psi/stage is acceptable.
Correct elastomer selection is the key to pump operation and longevity. When installed in the well, the elastomer will most likely swell use to temperature and well bore fluid effects. Being able to know the degree of swelling, will then allow selection of an appropriately sized rotor. In some operating areas where elastomer swelling is an issue, the rotor will be changed with time to a smaller rotor.
It is strongly recommended that elastomers are tested using well fluids to allow selection of the most appropriate elastomer type for the well conditions.
The following provides a list of some of the aspects that need to be taken into account in specification of the elastomer:
The correctly specified elastomer needs to be able to seal against the rotor but also needs to have the following properties to a greater or lesser degree depending upon the application:
Prior to a PCP being applied in a given operating area it is useful to perform tests to determine the suitability of a given elastomer in the wellbore fluids - particularly swelling of the elastomer. Trial and error are often used to set the pump in a test environment and allow the elastomer to swell in field operation, adjusted to finally an acceptable value.
Suitability of elastomers to a given application is summarised by the following table:
The rotor is normally 4140/4150 Carbon steel chrome plated with a coating. The purpose of the coating is to increase lubricity of the rod in the stator, resist corrosion and resist wear from solids. The coating is typically chrome but this may change with well conditions. In acidic conditions (< style="font-weight: bold;">Rod String
The function of the rod is to:
In design of a rod system the following issues need to be considered:
Axial loads on the rod are due to the rod weight, the weight of the rotor and a piston force due to the differential pressure across collars and centralisers.
Torque loads are a function of the pump differential pressure, efficiency of the pump, the pump internal friction, and a resistive torque of the fluid between the rod/couplings and tubing.
The total torque can be expressed as:
Tpumpfriction is the torque required to overcome the fit between the stator and rotor and allow the pump to turn. The value is typically 65-100 ft.lbs and is known form experience rather than a direct calculation. In the case of a swollen elastomer this value be much higher
Tpumphydraulic is due to the work that the pump does and is calculated from:
Q = flowrate (bbl/day)
dP = Pump differential pressure (psi)
Tresistive is the torque required to overcome friction of the rod string rotating in the produced fluid and is calculated from:
In order to perform this calculation properly it should be performed using the total length of rod section, total length of couplings and total length of centralisers installed and the Tresistive for each added to give the total
The downhole torque required to turn the pump is quoted by some manufacturers in terms of HP. The following equation can be used to covert between torque and Hp for a given RPM
HP = Horsepower
T = Torque ft-lbs
The axial forces in the rod can be calculated from
Rod Effective Stress
The combined loading of torque and axial load on the rod string can be accounted for using Von Mises stress equation. Calculation the torque and axial loads are best performed using software although there are a number of equations and tables that can be used to estimate the forces and calculate the effective stress on the rod. In order to ensure a safety factor an effective stress of less that 70-80% of maximum is used.
Normal sucker pump rods can be used to power the PCP but a number of companies now make Drive rods specifically for a PCP application. The following picture compares a 1" drive rod (upper) with a 1" sucker rod (lower)
Drive rods have the following advantages:
Regardless of the type of rod used the coupling should have higher stress capacity than the body of the rods and yet when rod failures are sustained, they are typically in the coupling rather than the body of the rod. In order to avoid failures of the coupling it is critical to ensure correct make-up of the coupling. The key steps to successful make-up are:
Continuous rod is available (co-rod) which is like coiled tubing only solid. Co- rod only requires a coupling at the top and the bottom of the rod string and so is more suited to deviated wells, causes less tubing wear and eliminates the potential for coupling failures.
Consideration must also be given to the fact that the top of the rotor is moving eccentrically, as such the connection and first 30ft of rod above the rotor needs to be designed to accommodate such movement. It is recommended that a full sized sucker rod be used at exit but at least a pony rod no shorter than 8'. Also do not swage down to a smaller flow passage for 4' (from Weatherford).
In directional wells centralisers are often used to centralise the rod string and prevent rod and tubing wear. Spacing of centralisers is based on the profile of the wellbore.
The drive system is normally comprised of a drive head, speed reducer and a power source. The function of the drive system is to:
Various drivehead configurations are available that allow the drivehead to be vertically or horizontally. Typical HP is in the range of 10 - 100 HP.
Speed reducers are available that facilitate either fixed speed or variable speed drives. Variable speed drives allow for more well inflow uncertainty.
Prime movers can be electric motors, hydraulic motors or internal combustion engines. Electric motors are more efficient but require the wellsite to have electricity, although solar power can be used in some applications.
The required power output of the prime mover can be calculated from:
The basic procedure for pump design is as follows:
Operation, Monitoring and Diagnosis
A typical monitoring system will include torque and RPM sensors to measure the mechanical system response. The majority of PCPs are applied in low cost operating areas and an operator is often reluctant to spend additional capital on equipment for monitoring of the PCP system.
Advanced monitoring systems will include a downhole sensor to measure pump intake and discharge pressures, pump discharge temperature and vibration. A controller can then be used in conjunction with a variable speed drive and remote diagnostic software to optimise well production within the system limits of rpm, torque and pump depth relative to fluid level.
The following table provides a summary of the measurements that can be taken:
The efficiency is the ratio of the power to lift fluids from approximately the fluid level in the casing divided by the input power to the system.
One simple monitoring process can be the pump efficiency. The formula is:
The simple formula showing what the production is as a % of the no-slip production is a method of estimating if the pump is too tight or too loose. If the efficiency is over 90% field experience should be monitored to see if pump is too tight to restart or breaks in the pump or rods occur. If the n is lower than -80% then experience may show the pump is set too loose in the shop and after the pump elastomer swells in field operation. It is one way to try to monitor performance without additional instrumentation.
The following graph (figure 5) shows a plot of pump operating parameters acquired during a PCP start-up.
Figure 5 - Typical data during PCP start-up
It can be observed that as pump RPM increases torque, discharge pressure and discharge temperature increase significantly. Conventional wisdom would say higher RPM means higher flow which means greater frictional pressure drop in the tubing resulting in an increased discharged pressure (discharge temperature increases as a result of increased heating in the PCP). However, consideration of the wellhead pressure trend shows that a large proportion of the pressure increase at the pump discharge is due to the increased wellhead pressure (due to increased pressure drop in the horizontal surface pipeline or pressure drop across the surface choke). This plot indicates the importance of considering the hydraulic parameters (pressure) as well as the mechanical measurements (torque and RPM) to understand the response of the system.
Through the use of measured downhole parameters it is possible to determine:
Common operational problems that can be diagnosed using a combination of surface data and measured downhole parameters are:
The key to production optimisation is to reduce the bottomhole pressure (Pwf), create more drawdown (Pr - Pwf ) and allow the well to flow at a higher rate. Increasing the RPM for a PCP results in reduction of Pwf.
Traditional analysis methods have used 'Echometers' to infer the fluid level. A more advanced method is to use a downhole pressure sensor and measure the actual pressure. A direct measurement of the pump intake pressure is the most accurate method to determine whether there is an opportunity to produce at higher rates by drawing down the Pwf further (note it is also necessary to monitor casing pressure in conjunction with intake pressure).
Another system used with good success is to use the OGI system with a flow measuring system in the flowline (good for water, perhaps not for heavy viscous oil) and when rates drop, a VSD is signalled to slow the unit. A complete system of control algorithms are available with the system. No downhole sensors are needed.
A downhole pressure sensor can be used to monitor well pressure when the well is shut in (build-up) and provide an indication of reservoir pressure but downhole sensors are more prone to fail.
Automation provides the best means of optimising production whilst preventing equipment failure. The technology exists to automate the PCP system as follows:
As an alternative to powering the PCP using a rod string and drivehead it is also possible to use a downhole (ESP) motor to power the PCP.
In order to drive the PCP using a downhole motor it is necessary to use a gear reducer (9:1 or 11.5:1) to run the PCP at an acceptable speed (100 to 500 RPM).
This type of system has the following advantages over conventionally deployed PCPs:
Some of these systems are designed such that the PC Pump can be moved and reinstalled using wireline or coil tubing while leaving the motor in the hole.15:34