ARTIFICIAL LIFT

What’s new in artificial lift

Part 1 – Nineteen innovations for beam, progressing cavity and hydraulic pumping, plus gas lift, plunger lift and related technologies

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

his article presents 19 recent developments in six categories of artificial lift technology: Beam pumping (6 items); Progressing cavity pumping (PCP) (2); Hydraulic pumping (2); Gas lift (2); Plunger lift (3); and Miscellaneous (4). Part 2 will cover advances in electrical submersible pumping.

The new products described and illustrated here are about evenly split between mechanical equipment and monitoring / control and management software and sensing systems. The nine new equipment items include a new beam pumping unit, field electricity generators and new sucker rods, ranging down to smaller pumping system components, valves and gauges. The major theme prevailing throughout the 10 new management / control systems is optimization of the well / reservoir system to get maximum productivity at minimum cost.

Beam Pumping

Six ways to improve field operations with beam-pumped (formerly termed sucker rod-pumped) wells include a folding pump unit, a hydraulic rod-length control cylinder, new fiberglass rods and three well analyzing / optimizing systems.

New beam pumping unit. Lufkin Industries, Inc., Lufkin, Texas, introduced its new beam / sucker rod-pumping unit at the Permian Basin Oil Show in October 1998, Fig. 1. The Model PL-640D-305-144 unit features a 640,000-in. lb gear reducer, a 30,500-lb structure and a 144-in. stroke. The unit is designed to operate under a 12-ft high, center-pivot sprinkler system for applications in which longer stroke lengths are needed. It is capable of folding to a minimum height of just less than 144 in. above ground level to allow the sprinkler system to travel over the installation; the unit then stands up again to continue pumping.

This type of unit should also find application in some international environments to which the unit can be shipped fully assembled. This minimizes equipment and need for trained personnel during installation, which may alleviate problems in remote locations.

The patent-pending unit rises and lowers via a unique knee joint in the rear Samson post leg that is powered by a self-contained hydraulic system. The hydraulic power unit may be supplied with the unit, or it can be fitted with quick disconnect fittings that will allow use of a single truck-mounted, hydraulic power system to service several pumping units. Major parts of the new system are made up of proven standard components that have stood the test of time. A complete line of unit sizes is planned to fit most beam-pumped well conditions.

Hydraulic cylinder adjusts / monitors rods. Solar Injection Systems, Inc., Midland, Texas, offers the Beniah Cylinder, a hydraulic cylinder used to raise and lower a well’s rod string without stopping the pumping unit, Fig. 2. The system, invented / patented by Cliff Mann, can raise or lower the string as little as 1/8 in. or as much as 14 in. The device is installed between the carrier bar and the polished rod clamp. A hydraulic hose line connected to the cylinder runs down the Sampson post to a 1/4-in. tee. Connected into the tee is a needle valve, quick connect fitting and a pressure gauge and / or chart recorder.

To lower the rods, the needle valve is opened and hydraulic oil is slowly drained out of the cylinder, effectively lengthening the string, allowing it to lower. To raise the rods, a hydraulic hand pump is connected into the quick-connect fitting and the string is raised to its desired location.

The pressure gauge and / or chart recorder allows the operator to monitor hydraulic pressure within the cylinder and thus detect critical information about the well. For example, the cylinder can detect proper pump loading, gas lock, paraffin buildup downhole, rod part, high annulus fluid level and fluid pound.

When the pump is loading properly, there is a uniform sweep on the pressure gauge and / or chart recorder. With gas lock, the hydraulic pressure decreases in width and uniformity. As paraffin builds up, the sweep increases over a period of time on the gauge and / or chart recorder. And when a well is pounding fluid and a chart recorder is hooked up, needle movement increases violently.

Fiberglass sucker rod. Fiberflex, Inc., Midland, Texas, has introduced the FLEX2000, non-API series fiberglass sucker rod. The new rods are available in 1-in. and 1.25-in. diameters and do not require the addition of couplings. They are manufactured with an API-rod-thread pin connection on one end and a box connection on the opposing end.

This innovative joint design reduces costs and minimizes installation time. Incorporating high quality standards and 20 years of manufacturing experience to reduce operating costs, the manufacturer believes the new rods are a proper option for applications in wells with intermediate fiberglass rod loading (80% and lower). There have been no compromises in material or manufacturing specs relative to standard API-series rods. Both the 1-in. and 1.25-in. rods are full API diameters.

Rod-pump controller for marginal wells. From experience, producers know that cycling a rod-pumped well with a time clock is not efficient. Because reservoirs are dynamic, time clocks cannot accurately and consistently account for these changing conditions. Nabla, now Lufkin Automation, Houston, with the recent merger of Delta-X Corp., has developed a low-cost rod-pump controller for these marginal wells, Fig. 3.

This controller, the Optimizer, detects pump-off by monitoring motor power derived from motor speed. When motor power declines below a predetermined limit, or reference power, the controller turns the pumping unit off. The unit will remain off for the preset downtime. When the unit restarts, calculated motor power is compared to reference power and a run / stop decision is made. Thus, the controller ensures that each well is producing only when the pump is filling, resulting in the elimination of fluid pound and reduction in electricity usage.

This controller requires no traditional position transducer or expensive load cell, and it defaults to a predefined percentage timer in the unlikely event of sensor malfunction. Recorded data includes SPM and last-72-hr run history. Affordable and simple to operate, the controller provides an economical means to monitor changes in mechanical efficiencies and reservoir conditions.

Integrated test / analyze system. Echometer Company in Wichita Falls, Texas, has introduced a more-powerful version of its popular Well Analyzer system for beam-pumping wells, an integrated system for testing and analyzing well performance, Fig. 4. The system is capable of performing liquid-level, dynamometer, motor-power and pressure transient tests and analyses. State-of-the-art, analog-to-digital converters use Sigma-Delta modulation to greatly improve quality of the acquired signals.

The new hardware is supported by "TWM," a 32-bit Windows program which integrates the data acquisition and analysis into a single, user-friendly package. TWM features Oilfield, SI and custom data units, improved file management, more flexible data acquisition and expanded analytic capabilities.

Communications software package. Insight Automation, Inc., Broomfield, Colorado, offers an NT-based multi-protocol, multi-tasking, enhanced SCADA communications software package, Energy Management Systems/4 (EMS/4), Fig. 5.

The system supports leading field automation devices used in the industry, including Applied Automation, Inc. TotalFlow, Fisher ROC, Kimray, Automation Associates, Delta-X, Baker CAC, Nabla, Tri-Ener-Tech, Allen Bradley, Modicon and standard modbus devices. Unique in design, it is a SCADA communication software program that can communicate to all of these protocols together through a single radio or other communication system without having to do anything special. In a multiple communication system, it will communicate simultaneously across each port.

The package provides a Protocol Interface for each protocol, and uses "reference RTUs" allowing users to create one database per RTU configuration and reference all similar added devices to that database. This allows large-field SCADA systems to be created in a short period of time.

Included with EMS/4 is a dynamometer upload, display, analysis and configuration program that brings in dynamometer card data for each supported pump-off controller. WinGraph allows users to collect card data from the POCs , display that data, display configuration and setup data, program the controllers and export all card data to Nabla and Theta dynamometer well analysis software. The package has a DDE Server that allows any data for any supported device to be used with Wonderware Factory Suite, Intellution FIX or any other DDE-compliant program.

Progressing Cavity Pumping

Two new developments for progressing cavity pumping (PCP) include: a remote self-adjusting analyzer and controller, and a downhole monitor that senses stator temperature rise when the pump runs dry.

Self-adjusting analyzer / controller. The most valuable information about an operating oil or gas well is the dynamic pumping fluid level, which shows the relationship between pumping rate and well productivity, thus providing actual performance data. InterRep, of Tulsa, Oklahoma, a manufacturer of PCP drive systems, has developed and tested a Progressive Cavity Pump Optimization System, called PCPOS (patent pending), that continuously analyzes analog input values from several components at the surface to determine operating fluid level, Fig. 6. One major component is a load-measuring device integral to the surface drive system; no downhole sensors and / or wires are required. Analyses of the input values by the program provide optimum pump operation criteria related to the dynamics of the producing well.

The system is designed to operate the PCP system with limited human interface. Real-time analog input data, such as rod string weight, tubing and casing pressures, pump rotor speed, and operating amperage, are transmitted to a remote control unit (RCU) that provides communication between the surface drive system and the new program. The program’s integral artificial intelligence or expert system continuously analyzes the analog input data. Operating fluid level can be determined with proven acceptable accuracy.

The expert system, through the RCU, controls the surface drive by adjusting rotor speed according to desired well operating parameters. Using real-time measurements, the system can monitor operating conditions and make adjustments as frequently as desired. In addition, remote monitoring and control can be achieved through application of compatible remote transmission systems. The new technology has been field-tested and is now being applied in multiple, heavy-oil wells in Venezuela.

PCP stator temperature monitor. PCP International, Inc., of West Monroe, Louisiana, has developed the patent-pending Thermal Sensing Unit (TSU) accessory, suitable for use on all brands and models of PCPs. The system provides a universal solution that positively protects against dry-running damage, the most common cause of failure in PCPs.

A remote-transmitting device (RTD) installed in the pump stator continually monitors temperature between rotor and stator in real time. A temperature signal is sent to surface by the tubular encased conductor (TEC) and is compared with the adjustable temperature setting on the TSU control. An alternative method allows the user to link the system with some types of pressure gauges that send an intermittent signal for pressure and temperature to surface, Fig. 7.

If the pump runs dry, temperature rises due to increased friction between rotor and stator. Once the set point is reached, the TSU control unit stops the pump drive and activates an alarm signal, preventing stator damage by dry running. TSU operation is independent of pipe condition or kind of pump installation. It safely operates with fluids and solids that tend to coat and clog other devices.

Hydraulic Pumping

One company has developed two new systems for improving downhole hydraulic pump performance. An equalizing valve relieves tubing-reservoir pressure differential to allow pulling of coiled tubing from a jet-pump-lift system. And a traveling valve with dump-flood action helps fill the barrel of a downhole hydraulic reciprocating pump.

Equalizing valve for CT jet pump. Weatherford Artificial Lift Systems, headquartered in Houston, has developed the Equalizer Valve (patent applied for) to minimize forces required to pull coiled tubing (CT) out of any fluid-sealing device used to isolate the annulus — formed by CT and production tubing — from the formation fluid. Typical fluid seal completions include use of API mechanical or cup-type holddowns with an API-type seat nipple or the Landing Spear (patent applied for) recently developed by Weatherford.

Typically, a pump is required to lift fluids from low-pressure formations — the CT jet pump is one type used. Power fluid (oil or water) is pumped down the CT string to the pump, where it imparts momentum and transfers energy to the produced fluid. Power fluid and produced fluids are mixed in the pump throat and discharged into the annular space between CT and production tubing, and returned up the annulus as "return" fluid.

The return fluids are at a relatively high pressure compared to the suction pressure of the incoming produced fluids, and large forces are required to break the fluid seal isolating return and produced fluids. The pressure forces cause high tensile loads when attempting to retrieve the CT, particularly in deep installations and horizontal wells. These loads can exceed the yield strength of the CT material.

The new valve allows removal of the pump BHA and CT by providing a flow path for the return / power fluid to drain into, and equalize pressure with, the produced fluids, Fig. 8. It can be installed in any hydraulic jet pump installation or any other completion technique that will maintain some compressive load to resist tubing movement that would tend to pull and shift the valve. To open the valve, a CT rig operator must displace the CT upward 8-1/4 in. at the valve to expose ports located in the valve. Once differential fluid pressures are reduced or eliminated, minimal force is required to pull the CT away from the fluid seal location, assuming there is no mechanical lock or hold-down device restricting movement.

Dump flood traveling valve. Weatherford Artificial Lift Systems, Inc. has developed the dump flood traveling valve for the Type F hydraulic reciprocating pump product line. The valve allows produced fluid and power fluid at discharge pressure to be introduced into the pump barrel at the end of the pump’s suction stroke. The dump flood action improves volumetric efficiency of a hydraulic pump by increasing volumetric sweep efficiency. Significantly less gas volume at high pressure remains at the end of the discharge stroke to expand on the upstroke due to introduction of liquid that displaces the gas.

The valve allows for continuous runs at low volumetric efficiencies (10 to 20%) vs. the previous threshold of 40% for hydraulic reciprocating pumps. Significant run-time improvements have been noted. A similar product, the flood poppet, has been developed for the Model 220, V-25, and VFR pumps to introduce fluid continuously at high pressure into the pump barrel. Current application areas include Powell, Wyoming, where Type F pumps operating from 9,000 to 9,500 ft produce 20 to 80 bopd with volumetric efficiencies of 12 to 20% at about 42 SPM. Run times increased from 30 to 45 days to typical ranges of 1 to 2 years.

Gas Lift

Featured here are online production optimization products used to control field gas-lift operations on Norwegian North Sea platforms. Also described and illustrated is a system that combines gas lift with an ESP; an installation is being tested in a field in Colombia.

Field production optimization. ABB Industri in Oslo, Norway, is developing new products for online production optimization and control. The systems have been applied to field developments in the Norwegian North Sea, Fig. 9. Two products of this development are: 1) an online production network optimizer that calculates optimal operating points for oil fields comprising gas-lifted and naturally producing wells connected to a gathering pipe network, and 2) an automatic well controller that stabilizes each gas-lifted well in the field.

Online optimization. Based on user-defined optimization criteria (normally cost, or production rate), the system calculates, online, optimal gas injection rates for each gas-lifted well, and optimal wellhead pressure for each naturally producing well, given a large number of constraints (global or local) for the network. The optimization system will also consider the interaction between all wells in the network. Gas compressors and pressure drop in the lift-gas distribution network will be included in the optimization.

The new field-optimization strategy is closely interlinked with the DCS or SCADA system, allowing for continual parameter updating. In addition, online operation enables frequent reoptimization, even for shorter time periods, like during workovers, well testing and maintenance. The field optimizer is based on common multi-phase flow models for inflow, tubing, flowlines and chokes, combined with new convergence acceleration techniques, leading to extremely fast response times.

An example network optimization calculation has been performed for a network with 13 wells, a total 44 km of flowlines and 30 nodes within some 20 sec. By implementing faster algorithms, calculation time for the same problem is expected to take 5 to 10 sec in the final version — calculation time should be nearly proportional to the size of the problem.

The automatic controller reduces the problem of unstable production from gas-lifted wells caused by casing heading. It is well known that unstable gas-lift production may lead to periods of reduced, or even no, liquid production, followed by large peaks of liquid and gas which result in: 1) average oil production several times less than expected, and / or 2) oil and gas production less than the system’s design capacity for peak production.

The controller stabilizes the production through manipulation of the production and the gas-injection chokes. Field measurements such as wellhead pressure and annulus pressure are inputs to the controller. The new controller will go through extensive site tests on unstable wells.

Simultaneous gas / ESP lift. Traditionally, gas lift and electric submersible pumps (ESPs) have been viewed as competing forms of artificial lift. Recently, however, gas lift and ESP have been simultaneously combined by Reda and HOCOL, S.A. in a pilot test in HOCOL’s Balcon field in Colombia, Fig. 10. The objective of the initial five-well pilot test was to double field production by using ESPs to augment existing gas-lift capabilities available in the field. The installations represent the first known simultaneous gas lift / electric submersible pumping installations in the world. Early results promise success.

Plunger Lift

One company has three new developments related to the technology of artificially lifting liquids with gas-driven plungers in the tubing string. These products include: a new series of memory-intensive controllers, a bypass plunger for high liquid volumes, and a new software package for analyzing plunger performance.

Memory-intensive controller. Multi Products Co., of Millersburg, Ohio, has developed a series of memory-intensive controllers for oil and gas production using the time-proven Max series of controllers. The new CENTAUR series includes a list of features topped by the ability of the controllers to never lose their memory for operator settings, even if the battery is removed and no power is available. The developer refers to this as the "MaxGard" feature.

The addition of a non-erasable log of 140 cycles is also included in the list of new features. This log is downloaded to a notebook and can be worked into Microsoft Excel with the small software package available. This log contains plunger run time, as well as the time that each of the valves is open — to the second — as well as the plunger count. Total flow time and date and time-of-day are included; the unit is Y2K compatible.

The New Max 1, Max 3, AutoMax, and TiMax are going to make well line-out a far easier task, and provide the operator with a true picture of what happened and when it occurred. The series is available in TiMax and Max 1 units, and also in other units.

Bypass plunger. Multi Products Co. has released a new bypass plunger for wells with high liquid volume, Fig. 11. Development and testing of the plunger over the past six years has led to the current design. The Quick Travel (QT) plunger has good lift / fall-back characteristics and can deliver many more cycles per day. It can feasibly operate wells at up to 300 bopd by reducing time needed to get the plunger to the bottom of the well for beginning the next cycle.

The plunger is available in sizes for 2-3/8- and 2-7/8-in. tubing. The design assures that the plunger will not be easily susceptible to damage or destruction during well operation. The system has only two parts and no pads, springs or threaded components to come apart. While the plunger has not changed greatly in its exterior appearance, addition of the bypass and the shift valve has made it a positive force in wells that cycle.

Software for well testing. Multi Products Co. has introduced a software package for MS Excel called WellTest that will take information from a well and provide the operator with number of cycles per day and the amount of liquids it will produce with Multi Products’ plunger lift systems. The package includes the program on disk and one of the best designs in its Windows layout for the computer; it is "point and click" and very user friendly.

Information provided includes: travel time per cycle, plunger fall time based on plunger type, number of cycles per day, gas required per cycle, liquid per cycle, and production scenarios for various schemes. The package requires Windows and MicroSoft Excel to operate efficiently. The fields are clear and colorful and the text is large.

Miscellaneous

Described here are four innovations from three companies to help field operations: a temperature / pressure gauge to fit in gas-lift, side-pocket mandrels; supplemental electricity generation for isolated or marginal field operations; and two systems for optimizing gas well liquid removal and oil well artificial lift.

Gas-lift, side-pocket mandrel gauge. Spartek International, Midland, Texas, marketer for Spartek Systems, Sylvan Lake, Alberta, has introduced side-pocket, gas-lift mandrel temperature / pressure gauges in 1- and 1-1-2-in. OD, Fig. 12. The gauges use the same sealing surfaces and latches as conventional gas-lift valves, and they can be set and recovered using standard tooling.

The gauges provide a non-intrusive environment, enabling well fluids or gas to flow unimpeded. The tubing string remains full open to allow passage of other tools. The gauges have been designed to withstand the usual shocks induced during setting and retrieving. Housings are made of Inconel 718 to withstand corrosive fluids during production or stimulation. Temperature and pressure capabilities are 300°F (150°C) and 15,000 psi.

They have a memory storage capacity >250,000 data sets (time, temperature, pressure), representing more than 300 hr of recording at 3 sec/sample. Data is recovered using the standard Spartek Interface Box. A portable PC connected to the box via the serial port is all that is required. Some applications are: measuring pump discharge pressure in ESP installations and static and flowing BHPs in gas-lift wells, frac monitoring; well stimulation monitoring; production testing; long-term monitoring of flowing wells; etc.

Gas-fueled generators supply field electricity. Global Power Systems, LLC, located in Bossier City, Louisiana, has introduced its patented, field-proven In-Gen Induction Generator System featuring updated, fuel-efficient Caterpillar gas engines, Fig. 13. The systems can also be packaged with other prime movers to use low-quality fuel gas (up to 2% H₂S); and they can be packaged with diesel engines where gas is not available. The prime mover powers an induction generator through a proven, patented control process that automatically matches voltage / frequency of the power provided by the local electric utility.¹ The entire installation is on the operator’s side of the lease electric meter and requires no lengthy regulatory approvals.

The system requires excitation from the power grid for power reference; if the utility goes down, so does the In-Gen system. Power cannot be generated back into the utility grid during power outages or line repairs for safety reasons.

Further, the system can be used in remote areas where utility power is not available since it can be excited by a synchronous or "stand-alone" generator. This eliminates system complexity in multiple-generator scenarios since complicated phase-matching or phase-locking switchgear is not required. In some areas of the U.S. and the world, utilities will buy excess power. The new systems can be designed to sell excess electrical power to the utility for even greater savings.

Thus, the system is a way to "market" low-quality or stranded gas reserves via electricity sales. Recent changes to the electric utility industry have created an opportunity for production operators to take greater control of field operating electric costs. Electricity typically becomes an increasingly larger lifting cost component in maturing fields, where an opportunity to utilize field resources to reduce cost is especially significant.

Automated, optimized gas production. Kenonic Controls, Calgary, Alberta, Canada, has developed a turnkey control strategy called MaxGas that increases production and remotely unloads liquids from gas wells. The system utilizes switching valve technology that alternates production between casing and tubing strings. Basic system components include: automated valves (on tubing / casing strings), pressure transmitters to monitor tubing and casing static pressures, a software module that monitors pressures and calculates valve switching setpoints (based on the well’s specific testing), an RTU communicating to SCADA host or stand-alone local controller, a power source and optional Expert System technology to optimize field production.

Tangible benefits can be remarkable. Early applications resulted in sustainable gas production increases of 10 to 50% by using casing (versus tubing) flow and providing automatic liquid unloading. It also decreases operating and maintenance costs. And completion costs can be minimized through use of smaller-diameter continuous tubing strings and elimination of downhole equipment.

The systems are custom-tailored to each specific application and provide trouble-free well automation. They are particularly effective in remote well locations, as operations and routine maintenance are greatly reduced, and well status and production information can be transmitted to a centralized data management facility. Fig. 14 shows a typical remote application.

Production management software. Kenonic Controls has introduced its MaxOil system, a revolutionary product that facilitates real-time well optimization for a variety of artificial lift mechanisms, including ESPs, PCPs and gas-lift wells. The system is a production management software tool that integrates operating experience, empirical relationships, and specific oil properties with Expert Systems technology and artificial intelligence to present real-time visualization of well performance to operations personnel. It takes data from various sources and combines events with well-specific engineering analysis to provide recommendations for optimizing well performance.

The new software tool provides oil producers diagnostic information and solutions necessary to correct non-flowing conditions which lead to production loss and equipment damage. It also acts as a virtual operator / production manager to monitor and diagnose well problems, deduce potential root causes of these problems and suggest corrective action in realtime. The systems are particularly effective in remote well locations where communication and access is difficult. Fig. 15 demonstrates the appearance of the interface in a centralized field application.

Literature Cited

¹ Frazier, L., "In-field generator opens opportunity," The American Oil & Gas Reporter, December 1998, pp. 72–75.

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.

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.

Copyright © 1999 World Oil
Copyright © 1999 Gulf Publishing Company