What’s new in artificial lift

Part 2 — Twenty-five innovations for downhole / surface electrical submersible pumping (ESP) equipment / software, and other artificial-lift technology

James F. Lea, Amoco Production Research, Tulsa, Oklahoma*; Herald W. Winkler, Texas Tech University, Lubbock, Texas; and Robert E. Snyder, Editor

*Effective April 1, Chairman Petroleum Engineering Dept., Texas Tech University, Lubbock, Texas

n Part 1, presented last month, 19 new developments covered: six beam pumping; four progressing cavity and hydraulic pumping; four gas and plunger lift; and four other related contributions.

This article introduces 25 new developments from ten companies, with 23 of the products covering downhole / surface equipment and well analysis instrumentation related to electrical submersible pumping (ESP). Two other presentations discuss the technology of drilling wells with multilateral boreholes feeding a vertical, central bore containing an artificial lift system that would not be efficient in a deviated wellbore.

ELECTRICAL SUBMERSIBLE PUMPING

Described here are 23 new products from eight companies. The systems discuss: ten improvements for downhole pumps / motor configurations, downhole separation initiatives and a proposed new ESP consortium; nine innovations for downhole and surface ESP system cables and connectors; and four control, monitoring, and analytical systems.

Fluid recirculation system. Electric Submersible Pumps, Inc., the Wood Group, Oklahoma City, Oklahoma, offers several system innovations including a solution to the problem of locating the pump intake below the well’s perforations, such that cooling fluids do not flow over the motor. As illustrated in Fig. 16, a tube connected to the pump discharge directs part of the pumped fluid back down to the bottom of the motor, from where it circulates back up past the motor and mixes with the formation fluid to the inlet.

This system allows for lower setting depths while ensuring proper motor cooling. It replaces shrouded motors in wells with casing limitations or scaling tendencies.

High-efficiency pumps. Electric Submersible Pumps, Inc., has recently incorporated a new 538-series product line, the TE5500 and the TE7000 pumps. The TE7000 has a recommended operating range of 4,000 to 9,700 bpd at 3,500 rpm, with a BEP flow of 7,300 bpd, 73.5% efficiency and 46 ft of head. The TE5500 has a recommended operating range of 3,500 to 7,300 bpd, with a BEP flow of 5,500 bpd, 71.5% efficiency and 47-ft head. These pumps are available in floater, compression and AR (abrasion resistant) floater, and AR compression-type configuration with various metallurgies and coating technologies. Fig. 17 shows a cross-section of the new pump configuration.

High-efficiency motors. Electric Submersible Pumps, Inc., has released two new high-efficiency motors, the E4 (456) and E5 (550). These motors have new stator and rotor lamination designs, which combine to operate at higher efficiencies and produce more horsepower per length than standard designs, Fig. 18. Ultimately, these new features will assist in lowering operating costs through improved efficiency.

Water well systems. Electric Submersible Pumps, Inc.’s Water and Mining Division now includes several new pumps in its product line for 1999. These range in capacity from 300 gpm (10,290 bpd) to 4,200 gpm (144,060 bpd), with focus on higher efficiencies to reduce power costs. In addition, a new line of stainless steel motors has been added for corrosive and seawater applications in 3,500 and 1,800 rpm.

High volume pumps for 9-5/8-in. casing. REDA, a Schlumberger Company, Bartlesville, Oklahoma, has developed two new pumps for high-flowrate applications. The H28000 has optimum performance at 28,000 bpd at 3,500 rpm. The 5.62-in. OD enables production logging with the pumping unit in place in 9-5/8-in. casing.

The L45000 produces 45,000 bpd at 3,500 rpm. Its 7.25-in. OD allows use of large cable conductors in 9-5/8-in casing, when exceptionally high horsepower is required. Both pumps were developed using computational fluid dynamic models.

Tunable variable speed drives. REDA’s new SPEEDSTAR 2000 line of digital, flux vector pulse width modulated variable speed drives (VSDs) for ESPs offers nearly sinusoidal output voltage and current, and provides an adjustable carrier frequency, Fig. 19. The latter feature along with better output current waveform of these drives can significantly reduce downhole voltage overshoot and resonance, compared to conventional PWM and older-technology six-step, variable-voltage inverter drives.

This reduction decreases destructive voltage stresses on downhole cable and motor insulation, increasing equipment life while also reducing power wasted in harmonic content. The adjustable carrier frequency can, in many cases, negate the need for higher-cost harmonic filters required to protect downhole equipment and cable. The new VSD is a product of joint design and development between REDA and Toshiba International Corp.

Powered coiled tubing. REDA has developed a new model of its REDACoil powered coiled tubing. This second-generation design makes the cable installation much simpler and more reliable, while also easing cable removal from the coiled tubing for repairs and salvage operations. The new system has been installed and is operating reliably in many wells around the world.

Downhole monitoring tool. REDA now offers the Surveyor downhole-monitoring tool. The new tool provides reliable high-resolution pressure and temperature measurements at the pumping unit for an economical price. Signals are transmitted digitally through the power cable using the company’s patented technology, thus reducing completion complexity while assuring data integrity and acquisition.

System resonance modeling / testing. REDA, A. Comeau and Associates, and Toshiba International Corp. have introduced a new system modeling software that has been proven to accurately predict destructive voltage overshoot and resonance in ESP installations. The software uses mathematical simulation to ascertain the natural resonant frequency of the installation and allow the system to be tuned, Fig. 20. By adjusting the VSD carrier frequency or adding harmonic filtration — avoiding the natural frequency or multiples thereof — downhole equipment, cable and electrical connector life can be increased and power waste significantly reduced.

Self-positioning intake. Another new development from REDA is the Gastropod rotating pump intake, a self-orienting bottom-suction intake for gas separation in directionally drilled wells. This intake is particularly useful where free gas is present. This intake features an eccentric weighted outer sleeve that rotates due to its own weight during installation in the well, positioning the inlet ports at the lower side of the casing annulus. Gas, being lighter, bypasses the inlet ports while the heavier liquids enter the pump. The innovative new intake system can be installed below the ESP on a tailpipe connected to a shroud arrangement or integral to the ESP equipment intake. This device has been successfully operated in several Canadian oil wells.

New pump stages. Centrilift, a Baker Hughes Co., Claremore, Oklahoma, has introduced three new pump stages, the DC750, DC950 and WJJ1000. The first two are for the 3.375-in. pump and replace the older DC800 and DC1000. The new stages have improved performance, head and efficiency, over the stages they are replacing. The WJJ1000 is a higher-efficiency design for water and mining applications. It is a trimmable impeller design for flow ranges from 800 to 1,200 gpm at efficiencies to 82%. It is available in nickel-aluminum bronze or nickel gray iron metallurgies.

Abrasion resistant pumps. Centrilift has announced that an additional pump configuration has been added to its Abrasion Resistant Modular (ARM) pump line, the result of the integration of Centrilift and ODI patented technology. The modular configuration provides enhanced downthrust protection for every stage, and enhanced radial protection intermittently along the pump, Fig. 21. This offers another option for flexibility when matching a unit sizing to wellbore conditions and economics.

Polyethylene insulated cable. A new member of Centrilift’s Poly ESP cable family, designated the CPL cable (Centriline poly-lead), stretches the application envelope to environments with temperatures up to 225°F. The specially formulated poly insulation, covered with an extruded lead jacket, Fig. 22, allows this cable to be used in wells with any concentration of H2S. Extensive lab and field tests have proven the cable to be a cost-effective product.

Larger-gauge solid conductor. The many advantages of the solid conductor in ESP cables have now been extended to very large conductor gauges. Centrilift has recently introduced solid conductors up to No. 2/0 AWG, thus providing higher amperage capability in a compact cable profile.

Cable inside coiled tubing. ESPs can now be deployed on coiled tubing without the need for a costly workover rig. A new patent-pending method for supporting power cable inside coiled tubing allows Centrilift to assemble long lengths of ElectroCoil Tubing (ECT) without concerns about cable movement within the tubing string. These unique "welded dimple" anchor supports, Fig. 23, have been proven in extensive field trials in which the cable remains safely in place even after multiple passes through the coiled tubing injector. Instrument and hydraulic lines can also be provided to monitor run conditions, control subsurface safety valves, and allow chemical injection for corrosion or paraffin control.

High volume downhole oil / water separation. Separating and disposing of produced water within the well itself can avoid operating / economic problems. For these reasons, downhole separation has been developed and, although now commercial in onshore wells up to 10,000 bfpd and low oil cuts (<15%), some testing was needed to prove higher flowrates and higher oil concentrations. To this end Baker Hughes recently completed a series of full scale tests as part of a North Sea DOWS JIP at Texaco’s Humble, Texas, test facility.

A two-stage Centrilift separation system using a single-motor, dual-pump drive was tested from 12,000 to 23,000 bpd at inlet oil concentrations ranging from 10 to 50%. The system was tested with regard to installation procedure, mechanical and process design, and functionality (control / separation performance). In all respects, performance exceeded expectations. Provided the surface watercut was maintained above 30%, separated-water quality remained <400 ppm residual oil, often <200 ppm. This was the first fully-shrouded, two-stage single motor system to be tested, and results were extremely encouraging. The next stage in 1999 will be to find an onshore well in which a long-term test can be run to prove the technology’s reliability.

ESP consortium proposal. Shell International EPBV hosted an ESP Workshop in Rijswijk, the Netherlands, in May 1998, which was attended by representatives from several major operating companies and ESP equipment vendors. The purpose of the workshop was to share information on current ESP use and discuss future visions of key players. It was established that there is tremendous growth potential for ESP use, although significant improvements in run life and expanded capabilities are required for this market potential to be realized.

One of the key outcomes was the decision to pursue creation of a consortium in which participant operating companies would share information on ESP system performance. Goals would be to accelerate the learning curve, achieve substantial improvements in system run life and provide effective direction to equipment vendors on development priorities. This would be achieved by developing a better understanding of failure causes in a variety of conditions.

To realize this goal, the attendees agreed that an industry-wide ESP Reliability Information and Failure Tracking System (ESP-RIFTS) would need to be implemented. To start this process, Shell commissioned C-FER Technologies Inc. of Edmonton, Canada, to explore the feasibility of developing such an information system, and assess the logistics of implementing and maintaining it.

Shell sees a huge potential benefit if the proposed system can be used to develop a much more comprehensive understanding of how, why and where ESP systems work well, and how, why and where they fail. They also believe the information system can benefit both operators and vendors in expanding the working envelope of ESP systems to gassier, heavier-oil and hotter wells, in offshore, subsea and extended reach conditions, etc.

A detailed proposal is being prepared for a Joint Industry Project (JIP) to pursue this project. A meeting will be held on either April 26 or 27, 1999, prior to the SPE ESP Workshop in Houston, to finalize the workscope. For further information on this initiative, contact either Francisco Alhanati at C-FER Technologies Inc. (780 450 8989, ext. 253/ f.alhanati@cfertech.com) or Cleon Dunham, Shell International E&P B.V. (31 70 3113 432/ c.l.dunham@siep.shell.com).

Downhole solids-removing separator / injector. C-FER Technologies Inc. and PanCanadian Resources Ltd. of Calgary, Canada, have expanded the application of Downhole Oil / Water Separation (DHOWS) Systems to include reservoirs prone to sand production. The systems utilize a downhole hydrocyclone-based deoiling oil / water separator coupled with pumps (ESP, PCP) to separate the oil / water emulsion which enters the well and re-inject most of the water into a suitable zone within the wellbore. The concentrated oil stream is then pumped to surface.

Initial trials of the DHOWS system in wells that produce solids were largely unsuccessful due to the fact that the solids separated with the water in the hydrocyclone eventually plugged the disposal zone. PanCanadian hired C-FER to develop a solution, since the oil company operates sand-producing reservoirs where application of the technology is considered attractive.

Following an evaluation of several concepts, C-FER developed / tested a modular three-phase separation system which incorporated a desanding separator in front of the deoiling separator to remove sand from the produced fluid emulsion, Fig. 24. The desanded emulsion subsequently flows into the deoiling separator which produces separate disposal water and concentrated oil streams as in the conventional DHOWS systems. The sand slurry and the concentrated oil streams are pressure balanced, commingled and pumped to surface, thereby ensuring that a solids-free water stream is injected.

This led to the design and fabrication of two full-scale, three-phase separation systems, for coupling to PCP and ESP systems, respectively, which were lab tested by C-FER. Based on positive results of the test program, PanCanadian subsequently completed field tests with both systems in wells where previous trials with the original DHOWS system had lasted only a few days due to disposal zone plugging. Both trials have been successful, with the separation systems in operation for several months.

Electrical connection systems. BIW Connector Systems, LLC, Santa Rosa, California, offers a variety of new electrical connection methods for use with ESPs. The following two feed-through connector systems illustrate the product line.

The Captor Feedthru System recently announced by BIW, is a separable electrical connection system approved for installation in Classified Hazardous Zones (Class I Division 1 and Class I Division 2). The system includes a unique, all-metal keying feature in which the surface connector engages with the feed-through at the wellhead, Fig. 25. The metal keying system positively prevents damage which can occur as a result of excessive torque application, or other types of mishandling during installation. The developer has supplied specialized versions of the system for use in coiled-tubing ESP installations. It is available for electrical requirements up to 140 A at 5,000 VAC.

The Trident Feedthru System is now being supplied by BIW. This system utilizes three individual power penetrators, one for each phase conductor, Fig. 26. It features a single, field-installable downhole assembly, three individual feed-throughs, and a separable surface connector. The system is ideal for installations where there is insufficient space to allow for a single feed-through. The new system is available for electrical requirements up to 140 A at 5,000 VAC.

Automatic downhole bypass tool. The Auto Y-Tool from Phoenix Petroleum Services Ltd., Inverurie, Scotland, is a new addition to the company’s ESP By-Pass product range. It consists of a spring-loaded diverter valve which seals off the by-pass tubing, which is inline with the production string, whenever the pump is running, Fig. 27. The tool is automatically closed by the flow produced by the downhole pump when it is started. The diverter, which starts off in the flow path of the pump will hinge over and seal off the by-pass tubing; pressure generated by the pump will keep the diverter closed while the pump is running. The developer says a flowrate of 100 gpm and a minimum pressure of 5 psi at the pump are needed.

When the pump is shut down and the pressure across the diverter has equalized, the spring on the diverter will return to the open position, which will allow well intervention by wireline or coiled tubing if required. The diverter can be locked in the open position by landing a Phoenix Logging Plug into the nipple below, which extends up into the Y-Tool and prevents the diverter from closing. This allows logging to be performed while the pump is running. The new device can save on wireline and CT operations; and the developer says it is suitable for sandy environments.

Spliceless, electric wellhead penetrator. Quick Connectors of Houston, Texas, has developed a low-cost electric wellhead penetrator, primarily for land well application, called the P3000, Fig. 28. It eliminates the cable splice below the tubing hanger normally required for connecting penetrators. It employs a field-installed seal system that will mate with virtually all pump cable designs, flat or round, up to No. 1 AWG conductor size, including leaded cables.

Originally designed to be a safe penetrator that would provide a pressure-rated seal for packoff-type wellheads (such as the Huber or Larkin), this design has evolved to cover the complete range of wellhead types, both API-flanged and "boll weevil" (without bonnet adaptor). It is particularly adaptable to small-casing wells, permitting a concentric completion, requiring only three small ports to be drilled in the hanger (and bonnet adaptor). It can even be used in place of an existing penetrator by employing a reusable crossover adaptor.

All penetrators include an integral surface conduit system that eliminates need for a traditional junction box. Systems are approved by Factory Mutual, and comply with the NEC (National Electric Code) for hazardous areas as defined by API 500 and 14F.

ESP-well analyzer. Case Services, Inc., Houston, Texas, has long provided monitoring and detailed analysis software for rod-pumped wells. Now users of the software can do detailed analysis on ESP wells, Fig. 29, and access production information from around the world with the new csLIFT Web Suite. The system monitors interaction between pump and producing formation, so it is able to detect changes in reservoir performance that will impact pump behavior. For instance, increases or decreases in average reservoir pressure can be detected, and problems with scale or skin damage identified. With the analysis workbench, the user can identify pump wear, predict remaining pump life, and diagnose pump failure causes.

The program also calculates system efficiency and lifting costs. It incorporates a miscible fluid model that accounts for CO₂ solubility in both oil and water. The model provides accurate prediction of fluid properties and fluid behavior within a pump installed in a CO₂ flood that conventional fluid models cannot accurately describe.

The design combines reservoir inflow and pump performance models to predict a common operating point within the well. Users can maximize pump run lives and minimize lift costs by designing installations that operate at the pump’s peak efficiency. In addition, users can vary design parameters simultaneously to identify the most cost-effective pump depth / production rate, and avoid conditions where excessive stress would be placed on the system. And the program can be used to perform "what if" analysis on existing installations to determine the impact of equipment changes.

The supplier’s web products allow access to data from any production site in the world. This read-only tool assures that engineers / managers have current information about the production status. An assortment of views into the data is available and the user can create retrievable screens of the specific data formatted to particular needs.

MISCELLANEOUS

If an operator desires to artificially lift a highly deviated or horizontal well, the options are limited to non-sucker-rod type systems due to hole angle. Or, such systems must be run in the vertical section, above the depth where hole angle increases. Here, two systems for drilling / completing wells with multilateral boreholes drilled from a vertical main bore suitable for artificial lift installation are described.

Drill wells for artificial lift service. Many wells using new drilling technology are deviated horizontal or multilateral wells. These wells can be producing viscous oil, gas with some liquids, or other types of production. They may require artificial lift to begin sooner or later in the well’s life. If a lift system such as beam pumping is set in a curved horizontal well profile, failure rate can be high. It would be much more desirable to set such a lift system in a vertical section of larger-diameter casing and have the pay intersected by laterals off the main vertical portion.

One source of drilling such a well with artificial lift in mind, is Secure Oil Tools, with offices in Calgary, Alberta, Canada. The following information highlights that company’s MLPS (multilateral production systems), which allow for laterals off a larger diameter vertical hole.

The quad completion is shown schematically in Fig. 30. Note, as illustrated by the one upward-slanting lateral, the concept of drilling into pay from below, with net gravity drainage into the main larger vertical hole. The quad lateral allows short-radius drilling up to 125°/30m, which in some cases allows all of the build section to remain in the payzone. The typical system uses 9-5/8-in. as the main casing size with dual opposed 4-3/4-in. holes for the laterals, which can be completed with 2-7/8-in. regular tubing or 3-1/2-in. flush joint. The second set of laterals are spaced less than 2 m above the first.

A pump (beam, PCP, other) can then be sumped in the 9-5/8-in. The system uses pre-milled window sections and orientation slots. After the main casing is run, the window sections are oriented to the desired direction, then a normal cement job is completed; orientation of all other components is then mechanical.

Note that lateral sizes can be larger if windows are staggered rather than opposed. An 8-1/2-in. hole completed with 7-in. liner is possible, if windows are 2 to 3 m apart. The company offers more options for various types of multilateral wells, etc., though only one was highlighted here to stress drilling the well while planning for artificial lift.

Pre-manufactured multilaterals. Another example combination of artificial lift and horizontal well technology shows the application of specially-designed multilaterals. In Bakersfield, California, Bestline Liner Systems, Inc.’s pre-manufactured multilateral junctions were used by Mobil Exploration & Producing U.S. Inc., to drill and equip two dual-stacked, short-radius multilateral horizontal wells in the Tulare formation at Belridge field, Fig. 31. The wells were directionally drilled using MWD for guidance. The laterals were initiated such that the horizontal wells would gravity feed the viscous oil into the short-radius sections of the well.

The 7-in. casing with the pre-manufactured junctions was run in vertical hole and cemented in place. The short-radius laterals were horizontally drilled and then completed with Bestline’s Tight Liner Drill-In equipment and 4-1/2-in. slotted liner. The wells utilize artificial lift by using a beam pump set in the bottom of the 7-in. casing.

The pre-manufactured junctions allow the pay to drain from the short-radius section of the lateral and enter the 7-in. vertical main well where the pump is located. In more-conventional horizontal well completions, the pump and rods are placed in deviated curved sections of the well if low drawdown is to be achieved, but where operation is less efficient due to rod drag. The Bestline system provides a multilateral, short-radius completion into a viscous payzone with the artificial lift system performing as it would in a vertical well.

The authors

James F. Lea is a special research associate in the Production Mechanics Group of Amoco Production Research Co. in Tulsa, Oklahoma. He is a member of SPE and ASME. In March 1999, Mr. Lea retired from Amoco to accept a new position with Texas Tech University.

Herald W. Winkler is former chairman,now professor emeritus and research associate, in the Department of Petroleum Engineering at Texas Tech University in Lubbock, Texas. He is presently working as a consultant in artificial lift, specializing in gas lift.

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