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Difference between revisions of "Alternate PCP system configurations"
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[[Category:3.1.7 Progressing cavity pumps]] [[Category:YR]]
[[Category:3.1.7 Progressing cavity pumps]] [[Category:YR]]
Latest revision as of 09:35, 18 January 2016
Several nonstandard Progressing cavity pumping systems have been developed by various companies to improve pumping capacity, performance, and serviceability for certain applications.
Examples of nonstandard PCP systems
These nonstanard PCP systems includes a number of different downhole drive systems that inherently eliminate tubing wear problems and reduce fluid flow losses. Rod-insert PC pump designs are available that preclude the need to pull the tubing string for pump replacement. Charge pumps and fluidizer pumps are currently being used to increase the gas- and solids-handling capabilities of PCP systems. The following sections provide a brief description of the rationale for developing each hybrid system and a description of the basic operating principles of the product where applicable.
Electric downhole drive PCP systems
The use of PC pumps driven by conventional electric submersible pump (ESP) motors was first attempted by a Canadian operator in a heavy oil well in 1966, unfortunately with little success, and then to a much greater extent by Russian operators in the 1970s. However, only within the last decade have these downhole drive (DHD) PCP systems been more fully developed and successfully deployed on a commercial basis. Several major ESP vendors now market motors, gear boxes, and other equipment for DHD PCP systems. As a result, these systems have begun to see wider use. The entire surface unit drive system and rod string required in a conventional PCP system are replaced with a DHD unit that typically consists of:
- An ESP motor (either a 2- or 4-pole design that has synchronous speeds of 3,600 and 1,800 rpm, respectively)
- A gearbox and flex-shaft assembly
- A pump intake unit. Fig. 1 shows a schematic of a generic DHD system
A key feature of the DHD systems is the gearbox/seal/flex-shaft assembly. Although various vendors use different designs and configurations for these components, the overall functions are typically the same:
- To isolate the motor oil from the well fluids
- To provide a speed reduction between the motor and the pump
- To isolate the motor and gearbox from the pump’s eccentric motion
- To support the thrust load generated by the pump
- To provide a path for the produced fluid to flow from the wellbore past the motor (i.e., for cooling) to the pump inlet
The speed reduction is necessary because 2- and 4-pole ESP motors normally rotate at 3,600 and 1,800 rpm, respectively (i.e., synchronous speed at 60 Hz), which is much higher than the ideal operating speed for PC pumps. The eccentric motion of the pump is typically absorbed by a specially designed flex-shaft or knuckle-joint assembly positioned between the pump and the gear box.
DHD systems offer certain advantages in applications in which neither an ESP nor a rod-driven PCP can be used optimally. For example, PC pumps generally perform better than conventional ESPs in viscous-oil, high-sand-cut, or high-GOR applications. In deviated or horizontal wells, the rod strings required in surface-driven PCP systems create potential for severe wear or fatigue problems, particularly if there is a large differential pressure on the pump. In such cases, a DHD system may offer a better overall solution by combining the pumping capabilities of a PC pump with the benefits of a rodless drive system. Eliminating sucker rods also results in lower flow losses, which may allow less expensive, smaller-diameter production tubing to be used. In addition, there are no backspin safety issues because the rotating parts are all run downhole. A DHD system also eliminates the need for a stuffing box at surface, thereby reducing the potential for leaks. Drawbacks of the DHD systems include:
- The additional capital and servicing costs associated with the power cable for the downhole motor
- Some size restrictions
- Additional coordination between the ESP and PCP vendors for equipment design, supply, installation, and service(in most cases)
In practice, these systems are normally used only in higher-rate applications because their use in low-productivity wells generally is not economical.
It is imperative to design a DHD system properly because changing equipment once the system has been installed in a well is costly. Once installed, speed control can be achieved only with a variable-frequency drive. It is important to ensure that the cable and seal systems chosen are compatible with the well fluids to prevent premature system failure. Also, the pump is not normally “sumped” because there must be liquid flow past the motor at all times during operation to ensure that the motor is adequately cooled. Manufacturers recommend a 0.3 m/s [1 ft/s] minimum liquid flow velocity past the motor, but this recommendation is based on high-water-cut ESP system designs in which the flow is turbulent. With viscous oil, it is possible that the flow will be laminar, even at 0.3 m/s [1 ft/s], which may result in insufficient motor cooling and thus increased potential for motor failure. Shrouded systems may be used when seating the pump below the perforations is desirable or when the flow velocity past the motor is expected to be too low for adequate cooling. Note, however, there may be additional flow losses through the shroud that should be taken into consideration. During installation of DHD systems, the susceptibility of the power cable to damage is a concern; thus, particularly in directional- and horizontal-well applications, the use of cable protectors is recommended.
Wireline retrievable DHD PCP systems
Recently, DHD PCP systems have been developed in which the motor, drive assembly (i.e., seals and gearbox) are run into the well on the tubing string, and the pump (both rotor and stator) are run in and latched to the drive system by wireline. This allows relatively fast and inexpensive pump replacement when necessary, which is attractive in regions where rig costs are high or when frequent pump replacement is required. These systems typically require large casing (e.g., typically 177 mm [7 in.]) and tubing string sizes (e.g., 114 mm [4.5 in.] and larger) to accommodate the use of PC pumps with adequate displacement capacities.
Hydraulic DHD PCP systems
There are two types of hydraulic DHD systems for PC pumps that are either commercially available or are under development by different manufacturers. These include:
- A closed-loop hydraulic system with a downhole hydraulic motor driving a PC pump
- A closed- or open-loop fluid-driven PC motor coupled to a PC pump.
Both of these hydraulic drive systems require a surface pump and a fluid handling system to provide power fluid to the downhole hydraulic motor.
In an open-loop system, the power fluid is commingled with the produced fluid for return to surface; in a closed-loop system, a separate flowline is required for the return stream. In the closed-loop systems, hydraulic oil is typically used as the power fluid, whereas water is normally used in open-loop systems. The systems in which a second PC pump is used as a motor to drive the production pump are typically open-loop designs, and the two pumps are sized relative to one another so that the power fluid used to drive the motor pump is produced with the formation fluid back to surface by the production pump. In viscous-fluid applications, this arrangement can provide the advantage of viscosity reduction and lower flow losses.
The major advantages of these systems are the elimination of:
- Backspin hazard
- Stuffing-box leaks
- Wear and failure problems associated with rod strings
- The added complexity of the surface facilities and downhole completion
- Higher workover costs
- Limited production rate capacity
The availability and use of these systems have been quite limited.
Rod insert PCPs
Rod-insert PCP systems are configured the same as the conventional surface-driven systems, with the exception that both the rotor and stator are run on the rod string. This design allows the stator to be pulled without removal of the tubing string. The obvious benefit to this design is savings in service rig time. The major drawback is the limitations imposed by standard tubing-string diameters on the size (i.e., displacement) of the PC pump that can be deployed. Problems with latching and release of the downhole assembly can also be an issue in some cases (e.g., sand buildup above the pump). Note that some of these systems rely on the use of conventional pump hold-down subs designed for beam pump systems.
Tubing driven PCP systems
This type of system, currently at the prototype development stage, is another hybrid of the conventional surface-driven PCP system in which the tubing string is used to drive the downhole pump and to provide a conduit for fluid production to surface. The surface-drive system must support, rotate, and seal the tubing string, and the downhole completion must be modified to include an anchoring system for the stator, a swivel fixture to facilitate rotation of the rotor within the stator, and tubing centralizers to prevent casing wear. They are capable of delivering much higher torque to the pump than the conventional rod-driven systems. The tubing strings should also be equipped with centralizers designed to alleviate casing wear concerns.
Charge pump systems
For many years, Canadian operators have successfully used PCP systems specially configured with two pumps run in series with common rod and tubing strings. These so-called charge pump systems consist of a higher-displacement, low-lift pump run below a lower-displacement, normal-lift pump, as illustrated in Fig. 2. The two pumps are separated by one or more joints of tubing to facilitate the different rotor eccentricities and the “timing” of the two rotor/stator pairs. Charge pumps are used to raise volumetric pumping efficiency in gassy wells by using the larger-volume pump to compress the produced fluid substantially before it enters the second pump (on which the efficiency is based). This can allow increased drawdown under gassy conditions and helps to ensure adequate fluid cooling of the main PC pump, which facilitates longer run life. The drawbacks of charge pump systems include their increased capital cost, increased energy consumption because of the higher mechanical friction of the system, and increased pump length, which makes them more difficult to handle and install. A number of vendors supply these pumps on a special-order basis.
Fluidizer or recirculating pumps are simply a variation of the charge pump configuration. The basic difference between the two systems is that the tubing segment separating the two pumps is perforated in a fluidizer pump configuration. This design allows some of the fluid produced by the larger pump to be recirculated back into the casing annulus while still helping to improve the efficiency of the second pump. Fluidizer pumps are typically used to help prevent sand bridging and settlement as a means to decrease the workover frequency in wells producing sand-laden fluids.
Water reinjection systems
In addition to common use in dewatering coalbed methane wells, PCPs have been used to dewater gas wells. They have also seen use in conjunction with downhole water injection systems and in various configurations of downhole oil/water separation systems. In a gas-well dewatering system with downhole injection, a packer and sealbore assembly are used to isolate the producing zone from the lower water-disposal zone and a bypass sub is run below the PC pump (typically a rod-insert pump design which latches into the bypass sub assembly). The PCP system operates in a normal manner, pumping the water, which separates by gravity from the gas and collects above the packer, into the production tubing above the pump, while the gas flows to surface in the casing/tubing annulus. The water builds up sufficient head in the tubing string to create flow down past the PC pump through the bypass sub into the disposal zone. The PCP downhole oil/water separation systems tend to be more complex in terms of the downhole equipment configuration given the added requirement of performing effective oil/water separation and downhole water reinjection. These systems represent an emerging technology with relatively few field trials completed to date.
As mentioned, despite the large number of installations worldwide, PC pumps and drive systems do not, in general, conform to any industry standards or common specifications. As a result, there is significant variation in the products available from different vendors, which generally precludes interchangeability of equipment components. The nomenclature (e.g., naming conventions, ratings) used in conjunction with both pumps and drive units also varies considerably, which can make it difficult for users to easily compare and select products from different suppliers. Nevertheless, there have been some recent efforts to develop industry standards for PCP systems.
In the late 1990s, the International Organization for Standardization (ISO) commissioned the development of a standard for downhole PC pumping systems. This effort led to the issuance of ISO Standard 15136-1, Part 1: Pumps in 2001, with further work currently being undertaken to develop a Part 2 dealing with drive units. The published standard provides guidelines related to PC pump manufacturing, design, and bench testing; therefore, it is useful from an informational perspective. However, the provisions of the standard tend to be very general, and it does not attempt to preclude individual vendors from continuing to offer a unique line of pump products with different elastomers. Although many provisions are consistent with the current practices of major suppliers of PC pump products, the standard as a whole does not appear to have been widely adopted by the industry at this time, in part because of some of the nomenclature requirements.
In response to a number of drive/sheave failures in the mid- to late-1990s, a group of surface-drive manufacturers in Canada initiated the development of an industry standard for surface drives that encompassed braking systems. The standard provides guidelines for the design, specification, and use of PCP surface-drive units in an effort to support safe operation of this equipment.
- Delpassand, M.S. 1998. High Volume Down-Hole Progressing Cavity Pumps in Viscous Applications with Electric Submersible Motors. Paper 18 presented at the 1998 Gulf Coast Section ESP Workshop, Houston, April.
- Skoczylas, P. and Alhanati, F.J.S. 1998. Flow Regime Effects on Downhole Motor Cooling. Paper presented at the 1998 SPE Gulf Coast Section ESP Workshop, Houston, April.
- Dinkins, W. et al. 2002. Thru-Tubing Conveyed Progressive Cavity Pump ESP Operational Issues: A Short Story. Paper presented at the SPE Electric Submersible Pump Workshop, Houston, May 2002.
- Dunn, L.J., Matthews, C.M., and Brown, D. 1996. Field Experience With Instrumented PC Charge Pump Systems. Paper presented at the 1996 Progressing Cavity Pump Workshop, Tulsa, 19 November.
- Campbell, B. 1992. Recirculation Systems for Heavy Oil Primary Production in the Lindbergh Oil Sands. Paper presented at the 1992 Challenges and Innovations Heavy Oil and Oil Sands Technical Symposium, Lloydminster, Alberta, 11 March.
- Klein, S.T. and Thompson, S. 1992. Field Study: Utilizing a Progressing Cavity Pump for a Closed-Loop Downhole Injection System. Presented at the SPE Annual Technical Conference and Exhibition, Washington, D.C., 4-7 October 1992. SPE-24795-MS. http://dx.doi.org/10.2118/24795-MS.
- Peachey, B.R., Solanki, S., Zahacy, T. et al. 1997. Downhole Oil/Water Separation Moves Into High Gear. Presented at the Annual Technical Meeting, Calgary, Alberta, Jun 8 - 11, 1997 1997. PETSOC-97-91. http://dx.doi.org/10.2118/97-91.
- ISO Standard 15136-1, Downhole Equipment for Petroleum and Natural Gas Industries: Progressing Cavity Pump Systems for Artificial Lift, Part 1: Pumps, first edition. 2001. Geneva, Switzerland: ISO.
- Wagg, B.T. 2002. Development of a Standard for Progressing Cavity Pumping Systems Surface Drives. Presented at the Canadian International Petroleum Conference, Calgary, Alberta, Jun 11 - 13, 2002 2002. PETSOC-2002-091. http://dx.doi.org/10.2118/2002-091.
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