ARTIFICIAL LIFT

What’s new in artificial lift

Part 1 – Twenty-two new systems for beam, progressing cavity, hydraulic pumping and plunger lift

James F. Lea and Herald W. Winkler, Texas Tech University, Lubbock, Texas; Henry V. Nickens, BP Amoco; and Robert E. Snyder, Editor

resented here are 22 recent developments in four categories of artificial lift technology: Beam pumping (10 items); Progressing-cavity pumping (PCP) (5); Hydraulic pumping (4); Pneumatic lift (2); and Plunger lift (1). Part 2, coming next month, will cover electric submersible pumping and miscellaneous, related, new artificial lift technology.

Still the most popular type of artificial lift, beam pumping comprises a motor-driven surface system lifting sucker rods within the tubing string to operate a downhole reciprocating pump. PCP systems are based on a surface drive rotating a rod string which, in turn, drives a downhole rotor operating in an elastomeric stator. Hydraulic pumping systems include reciprocating surface rod lift systems using a hydraulic fluid-powered piston and downhole hydraulic powered pumps driven by pressurized liquids. Pneumatic pumping involves operation of a surface piston / cylinder system by higher-pressure natural gas supplied from the well annulus or externally compressed gas. And plunger lift, a tubing / rod-less system, uses a plunger inside the casing string to lift a slug of liquid powered by formation gas pressure from the formation.

Beam Pumping

Ten ways to improve beam / sucker-rod pumping – the most widely accepted artificial lift – feature a mechanical unit speed reducer, improved rod couplings / scrapers, a stuffing box improvement, two unique downhole pumps, a reciprocating coiled-tubing system, and four controller / power drive systems.

Jackshaft speed reducer. When well production drops below that intended for an existing beam-lift system, it is difficult to reduce unit speed to match the well’s reduced productivity. A Jackshaft allows the operator to reduce speed of a beam pumping system to as low as one to two spm, Fig. 1.

Fig. 1. Lufkin Jackshaft installed, with protective belt cover removed to allow viewing.

This has a number of desirable effects on the system: 1) it better matches the well’s inflow conditions with downhole production capacity, eliminating constant fluid pounding and incomplete pump fillage; 2) it permits conversion of single-reduction pumping units from slow-speed engines to more manageable electric motor drives; 3) in heavy-oil production, dropping the beam system’s spm can prevent rod-fall problems in viscous crude; 4) the slower, more correct pumping speed extends life of the surface pumping unit, rods, pump, tubing and stuffing box; and 5) motor nameplate hp and energy operational costs are reduced.

Further, the system permits individual tightening of belts for proper tension, reducing overhung motor bearing loads. It mounts on existing high prime or engine rails, allows use of the existing belt guard; and it comes complete with a countershaft belt guard. It also can help fight corrosion that may be accelerated by downtime. The Jackshaft is suitable for 114D up to 640D gearbox reducers.

Coiled tubing pumping system. There is a need to keep producing shallow, marginal wells under depressed market conditions. The availability of improved CT made possible an innovative artificial lift option using coiled tubing.

Coiled Tubing Americas (CTA), in Houston, has developed a beam pumping system that includes downhole and surface equipment, and a unique installation procedure. The system was field tested starting in 1998 by YPF, now Repsol-YPF, in its Southern Region of Argentina. The system replaces conventional sucker rods with coiled tubing, Fig. 2. In the test well, a hollow plunger pump with a retrievable anchor was run inside 2-7/8-in. OD tubing to simulate a slimhole well with 2-7/8-in. "casing." The CT was connected to a surface pump jack through a hollow polished rod which was connected, in turn, to a hose leading to the flowline. (See: Leniek, H., L. Ayestaran and Y. S. Yang, "Coiled tubing replaces sucker rods in beam pump test," Oil & Gas Journal, November 22, 1999, pp. 63–66).

Fig. 2. Hollow polished rod on coiled-tubing pumping system in field test in Southern Region of Argentina.

Lack of downhole connections minimizes rod-wear effect and fishing jobs. Due to the small diameter of the CT, fluids reach surface much faster than with conventional design, which helps reduce paraffin-associated problems. The system was designed to work in wells to 6,000 ft deep and 300 bpd gross production. More testing could prove plans to increase working depth and output.

This artificial-lift pumping system allows the drilling of new wells with small diameters, thus creating a viable artificial-lift method for rod pumps in slimhole wells. The advantages are reduced capital expenses for new wells and lower operating expenses for new or old wells. Field data related to the performance of this artificial-lift system in Argentina is available from CTA and the referenced article.

Pollution-control stuffing box. One serious problem facing operators of sucker rod pumps is environmental pollution caused by oil leakage through worn stuffing box packing. Harbison-Fischer, of Crowley, Texas, manufactures the J-F Pollution Control Stuffing Box to provide a means of stuffing-box-packing leak detection without environmental spillage.

Fig. 3. Cross-section of pollution control stuffing box.

The system is a dual-packing stuffing box with a fluid port between the two sets of packing, Fig. 3. The lower packing provides the operational packing seal for the well. The upper packing is a back-up seal that directs leaking fluid to the side fluid port. When the lower set of packing fails to provide a seal and leakage occurs, the top set of packing goes into action.

The leakage is contained and controlled between the two sets of packing and allowed to flow through the side outlet. Leakage fluid may be piped to a container which may be provided with any number of available devices for detecting fluid – two such devices are a float switch or a pressure switch. When either is actuated, the signal can be used to shut down the pumping unit, sound an alarm or start a small pump to empty the fluid.

This stuffing box is designed for safe, smooth operation. Both packing sets are independently adjustable. An extra-large, 1-in.-NPT, side opening is provided for leakage sensing or collection. The easily accessible lubrication fitting located in the upper packing set is equipped for grease gun lubrication. The unit adapts to any J-F stuffing box and requires no special tools for installation or maintenance.

Swivel and rigid sucker rod couplings. Flexbar, Inc., Midland, Texas, offers its Swivelbar sucker rod coupling that provides a 3-in., off-center deflection, Fig. 4. This transmits the effective mass of the sinkerbars through the longitudinal axis of the string to greatly enhance overall pump efficiency. This deflection also minimizes the "binding effect" of straight-coupled sinkerbars in deviated wells. Mechanical and fluid friction has been a substantial problem in pumping system design throughout the years. The only answer until now has simply been to overcome this resistance by using brute force. The swivel connection offers an alternative method for this situation.

Fig. 4. Swivel-type sucker rod coupling to reduce frictional drag.

In addition to the swiveling couplings, the company’s rigid couplings are specifically engineered to reduce frictional drag factors to maximize downhole pump stroke and enhance overall artificial-lift system capabilities. Both couplings provide standoff clearance which acts as a journal-bearing surface for the lower string. This greatly reduces the friction contact areas between rods, sinkerbars and internal tubing walls.

Thread backoff, a common problem, is virtually eliminated because of the swivel coupling’s ability to rotate a full 360° around its own centerline. The Swivelbar couplings incorporate both 17.4 p.h. stainless and 4620 K-grade steel, which are high in nickel content for optimum corrosion resistance. All couplings are streamlined and tapered to reduce fluid friction and piston effect.

Abrasive-resistant and Multi-phase pumps. Quinn Pumps, Red Deer, Alberta, announces the availability of two new pumps. The Frac Pump is a new design which provides oil producers a sand-resistant-style pump. The pump is stated to be capable of handling a variety of abrasives, such as frac sand, formation sand and fines. The pumping system is a unique configuration of both new materials and an improved design.

The design creates a virtual plunger seal to prevent any particulates from coming in between the plunger assembly and the barrel. This minimizes wear and reduces most pump slippage. This is accomplished by using new processes such as duplex chrome plating and advanced carbide and polymer materials.

Standard features include insert-guided cages, titanium carbide balls / seats and a top check assembly. Current designs also allow for the flexibility of six different plunger and polymer configurations, which can effectively be matched to a variety of well characteristics.

Advantages include: handling of formation / frac sand, improved pump efficiencies, extended pump run life, advanced materials, increased pump inflow and flexibility to match well characteristics.

Quinn also introduces the Multi-phase Pump, designed for both foamy / gaseous fluid – and also viscous fluid – wells. It eliminates the need for the traditional standing valve and cage, which increases allowable inflow to the pump chamber. This virtually eliminates gas locking during the pumping cycle. The pump can also be designed to handle emulsions with sand.

The traveling assembly is located at the top of the plunger, and the positive-seal-ring, standing valve assembly is located above the pump barrel. This assembly is located at the top of the pump, creating a "crater effect" at the pump inlet allowing inflow into the pump during the upstroke. Composite valve-seat materials are used for the standing valve seat, and elastomer wipers and seal rings are installed in the poppet body to create a tight seal against the valve rod. The wipers also help eliminate seizing or hanging up on the valve rod during the stroking cycle.

On the downstroke, the poppet-designed standing valve positively seals the tubing fluid from re-entering the pump barrel. As the plunger continues its downward motion, the traveling valve opens, and fluid enters the upper pump chamber. On the upstroke, the traveling valve closes off the pump chamber from wellbore fluids. The complete fluid is then carried upward, through the now-open standing valve poppet, and on to the tubing. At the top of the stroke, the poppet closes with a liquid-tight seal, and the cycle repeats.

The company claims that the system is effective for foamy / gaseous-fluid wells, and that it: maximizes allowable inflow, eliminates use of a conventional standing valve, handles sandy viscous fluids and eliminates gas locking.

Field-installed sucker rod guides / paraffin scrapers. New guides / scrapers from Oilfield Improvements, Inc., Broken Arrow, Oklahoma, distributed in Canada by Realistic Rod Guides, have the following features:

• Full-circle wiping of tubing ID; no rod rotating required
• High gripping force on rods
• High fluid flowby volume
• Extended life by using larger vanes and bearing surfaces
• Positive wear indication.
• Made of Amodel or Nylon, with glass fill – materials / service applications chart available from manufacturer
• Lubrication "fluid wedge" of "hydroplaning" effect is stated to be excellent for use with positive-cavity displacement pumps.

The guides / scrapers, Fig. 5, can be installed in the field using a manual guide tool and a hydraulic-clamp unit. Placements of guides / scrapers for wear can be determined by observing previous wear locations or use of survey tools to find high-side loads. Approximate recommendations are for four to six guides per rod above the pump to prevent rod buckling and a minimum of six guides per rod where known wear occurs. Placement for paraffin removal in the upper part of the well requires about six per rod.

Fig. 5. Field-installed sucker rod guides and paraffin scrapers. Two components snap on and create friction grip when driven together.

Variable-frequency drives as pump jack controllers. A new vector-controlled, variable-frequency AC drive called 6SE70 MASTER DRIVES from Siemens Energy & Automation, headquartered in Alpharetta, Georgia, has been successfully used to optimize rod pump operation, Fig. 6. Benefits claimed with this technology include energy savings, less downtime for mechanical speed changes and less wear on belts, polish rods and casings. These benefits translate into higher productivity at a reduced cost.

Fig. 6. Vector- controlled, variable- frequency drive to optimize sucker rod- pumping operations.

Some of MASTER DRIVES’ key features for these applications include:

• A DC bus voltage regulator that often eliminates need for resistor braking units; starting torque greater than 200%
• Automatic restart after a power outage; power dip ride-through capability and ability to run during low line conditions
• A clear text display selectively monitors torque, speed, strokes per minute and amps.

Programming is via the keypad or a PC. Also available is communication with an RS485 port, utilizing Siemens USS protocol, as well as option boards for PROFIBUS-DP and other networks. The system has the ability to run existing NEMA design D motors, but the drive can also run less-expensive NEMA B motors and provide enough torque for the application.

Built-in technology in the drive is available to detect the well’s fluid level and continually adjust drive speed to maintain fluid just above pump-off level – all without need for additional sensing equipment.

Field automation software. Theta Enterprises, Brea, California, has developed a new field automation software package called XSPOC. This software package combines the latest technologies in real-time client / server architecture, for Windows NT, with powerful expert beam-pump analysis tools to allow large-scale, automated analysis and monitoring of artificial-lift systems.

The heart of the XSPOC analysis is Theta’s XDIAG diagnostic analysis software. The package is able to automatically collect dynamometer cards from pump-off controllers and analyze them in the middle of the night, so that useful reports are ready and waiting for the user first thing in the morning, Fig. 7. These reports not only include conventional pump-off controller alarm data, but also plain-English descriptions of pumping-system problems. XDIAG uses pattern-recognition and expert technologies to identify conditions and let the user know when input data is incorrect, e.g., load cell calibration drift, incorrect stroke length, etc.

Fig. 7. XSPOC field automation software package screen shot. Click for enlarged view

Dynamometer system. A new T1 dynamometer system from Theta Enterprises has a unique, compact design and uses the most-accurate load and position transducers available, Fig. 8. The load cell is rated for 40,000 lb, and the position transducer can measure stroke lengths up to 350 in. The DYNOSTAR program (a 32-bit Windows software) provides an easy-to-use, user interface for the T1 dynamometer system. This program allows users to organize their measurements by storing them in a single file per well – as well as a history of all measurements made for each well, including valve checks, counterbalance effect, etc.

Fig. 8. T1 dynamometer system

Electrical efficiency tests. The Echometer Company of Wichita Falls, Texas, says measurement of overall electrical efficiency is important in optimizing oil production and minimizing well operating expense. Determining pumping-unit efficiency has been simplified by use of power measurement equipment and improved Windows software for acquiring / analyzing power, acoustic, pressure and mechanical data.

Conventional pumping systems are routinely tested for overall system efficiency. RotaFlex pumping units are now included in the Echometer software database for analysis of overall system efficiency, mechanical balancing, power balancing and minimum electrical power-usage balancing. Proper balancing reduces gearbox loadings and power consumption.

An illustration of gearbox torque on a RotaFlex unit is shown in Fig. 9. Considerable torque oscillation occurs at the beginning of upstrokes and downstrokes. The unit can be balanced such that peak torques on upstroke and downstroke are equal, or it can be balanced for minimum power usage. For minimum power consumption, average upstroke power should be balanced against average downstroke power. The software calculates proper counterweight to be added or removed for peak torque balanced conditions, or for minimum power-consumption conditions.

Fig. 9. RotaFlex unit gearbox torque analysis. Click for enlarged view

Pressure-transient data acquisition / analysis have been improved by use of Windows software and sigma-delta analog to digital electronics. A new-technology, sigma-delta analog to digital converter has better temperature stability. With these, more accurate surface pressure and liquid levels are obtained.

Progressing Cavity Pumping

Five PCP developments include a uniform wall-thickness stator design, high-torque sucker rods, a surface drive, a leak-free stuffing box and a new pump controller.

PCP stator redesign. A more "stable" stator design called uniform elastomer or Even Wall stator technology, is being developed and tested by Weatherford Artificial Lift Systems, Lloydminster, Alberta, Canada. This upgrade to conventional stators is showing promise in improving PCP durability / reliability / flexibility. Currently, there are six pumps undergoing field testing in heavy oil applications, with the longest run time to date of eight months.

The initial pump design being tested produces 60 bpd/100 rpm, with a pressure rating of 1,800 psi. Two other designs for higher-volume applications are scheduled for field tests.

In a conventional PC stator, the elastomer is injected into heavy-walled steel tubing, forming a double internal helix, Fig. 10. For years, this design was considered the only economical way to produce stators. However, heat can build up in the widest portions of the helix, possibly leading to early burnout. The newer, uniform-thickness elastomer stators have numerous advantages, including:

Fig. 10. Uniform elastomer-thickness wall, compared to conventional PCP elastomer design.

• Improved heat dissipation – the elastomer runs cooler, leading to improved mechanical properties and fewer failures due to stress or wear of the stator elastomer minors.
• Uniform elastomer swell – Having a uniform elastomer thickness means the elastomer also swells in a uniform fashion. Properly sizing the rotor for aggressive applications is, therefore, much simpler.
• Wider applicability – Applications that once pushed the envelope for PC pumps may now be within reach. These include wells with higher concentrations of aromatics, CO₂ and H₂S, or higher temperatures.

And the system has a higher pressure rating. Conventional PCPs rely on interference between rotor and stator to create a seal. Uniform-thickness stators are more consistent, providing a better rotor / stator fit with less interference. This enables the pump to handle more pressure, meaning a shorter pump design is possible.

Hi-torque sucker rods for PCPs. Weatherford is currently developing a hi-torque sucker rod for progressing-cavity pumping systems. The new product, called Corod DER 8.5, represents the latest technology enhancement to continuous sucker rods, which are unique to Weatherford Artificial Lift Systems.

The DER 8.5 continuous sucker rod is 1-5/32 in. in diameter and can withstand 1,400 ft-lb of torque and operate in 2-7/8-in. tubing. It provides the capability to produce more fluid from deeper depths without having to increase tubing size. This results in cost savings, since the operator does not have to incur additional capital spending for larger tubing. The added-size feature of the sucker rod also enhances wear characteristics of continuous sucker rods in crooked, deviated and horizontal wells. Judging from current field test results, it is expected that DER 8.5 will be available for use in early 2000.

Surface-drive head / hydraulic power skid. The new progressing cavity pump-surface-drive head and hydraulic power skid system from R&M Energy Systems, Houston, was engineered and developed for use in conjunction with Moyno Down-Hole Pumps for artificial-lift applications in oil/gas recovery, Fig. 11. As part of the Ultra-Drive family of surface drives, the DHH system includes a low-profile, surface-mounted drive head and an accompanying electric motor or gas-driven engine and hydraulic power skid for unlimited, variable-speed control with automatic backspin braking.

Fig. 11. Surface-drive head for downhole PCP. Accompanying motor or engine and hydraulic power / control skid are not shown.

The system’s low-profile design is more desirable than bulky, conventional-style pumping units. It is also optimally suited for remote, non-electrified areas due to its ability to utilize a gas-driven engine powered by natural gas produced at the wellhead. It also features easy field installation, simplified maintenance and an improved stuffing box to prevent leaks.

The surface-drive head includes the following specifications:

• Hollow shaft
• 1,250 ft-lb maximum rod torque
• 65 hp maximum power
• Flanged or pin wellhead connection
• 1-1/4-in. polished rod size.

Further, the system operates on a 500-rpm maximum polished rod speed, depending on the hydraulic pump / motor, and can handle a 33,000-lb maximum axial load.

Leak-free stuffing box. R&M Energy Systems has also developed a new stuffing box for use on progressing-cavity pump drive heads, Fig. 12. The Ultra-Drive Enviro-Stuffing Box can be used with all Moyno surface drives, as well as other drive-head brands. The system incorporates special "memory" type braided rope packing that provides an excellent seal while never losing its original shape. The unit requires lower maintenance than other types of environmental seal units and is easy to install and service.

Fig. 12. Leak-free stuffing box for Moyno or other drive heads features braided rope packing and external environmental leak catch chamber.

The Ultra-Drive box has an external environmental catch chamber, should the packing begin to leak. This chamber can either re-direct the leaked well fluid to a safe location or provide 100% containment. The sealing unit is completely detachable, allowing wellhead pressure to be maintained while the mechanical portion of the top drive is removed for servicing. An optional Anti-Pollution Stuffing Box Adapter (APA) leak-detection and switching device is also available for maximum safety against costly stuffing box spills.

Pump controller. Users of csPCP can maximize run life of pumps and minimize lift costs by closely monitoring performance of the pump and adjusting parameters that the controller uses. Offered by Case Services, Inc. of Houston, the system provides users with an easy-to-use interface that displays pump curves and trends such as rpm, surface tubing pressure, gross liquid rate, surface temperature and tubing pressure, Fig. 13. With that information, and electrical usage history, the user can accurately assess a problem in the PCP and even predict future problems.

Fig. 13. PCP controller interface displays pump curves and trends such as rpm, tubing pressure, liquid rate. Click for enlarged view

The user is provided with current status of the well(s), including customizable alarms, fault history, torque and speed. The module is part of the csLIFT suite, so it is integrated with existing features of the suite, such as well-test information and alarm callouts.

Hydraulic Pumping

Advances described for this category include: an improved, computerized long-stroke unit and control; a tubing rotator for a below-the-surface, long-stroke system; a tubing drain sleeve for a downhole hydraulic pump; and an improved seal for the surface high-pressure, power-fluid unit.

Hydraulic, long-stroke pumping system. DynaPump, Inc. of Northridge, California, has introduced an automated, long-stroke, computerized surface pumping system that has solved basic problems associated with artificial hydraulic lift systems – such as heat, power consumption and reliability. Those solutions allow for a design that offers a very long stroke in every pump model and a wide range of flow capacity within those models. Where these advantages are applicable, this lifting system can increase production and lower production costs.

The pumping system consists of two main components, pumping and power units, Fig. 14. (See: Rosman, A. and M. Nofal, "Computer controlled pump unit cuts power, increases output," World Oil, November 1996, pp. 53–56). The pumping unit stands over the tree and comprises a gas reservoir, a hydraulic cylinder and a pulley system. The power unit drives the pumping unit and consists of a computer control system with radio modem, solid-state electronics, motor controllers and hydraulic pumps. The unit comes in seven different models, with the largest having a maximum rod-load capacity of 80,000 lb and a 360-in. stroke. The power unit comes in different hp models up to 200 hp, and is matched to the pumping unit depending on dynamics of each well.

Fig. 14. Hydraulic, long-stroke pumping system comprises two main components, hydraulic piston pumping unit over tree and computer- controlled power unit. Pulley system doubles piston movement for up to 360-in. stroke.

This pumping system is designed for longevity, reliability and ease of maintenance with the use of solid-state electronics. Other advantages include: low acquisition costs, light weight / portability, easy / fast installation, automatic diagnosis of well operations / pump operations, automatic flow control, long stroke, differential speed up and down, less installed-power requirements, less power consumption and remote computer control. Some of these pump systems have exceeded the world record for total flow for hydraulic pumping systems and are capable of producing in excess of 10,000 bpd.

Ultra-long-stroke, rod-pumping improvements. Rod pumping successfully in space-restricted areas (such as offshore platforms) has traditionally been very difficult; and pumping in deviated wells has been expensive due to severe-wear conditions. With the help of RPS Canada, Hydraulic Rod Pumps, Int’l., (HRPI), Foothills Ranch, California, has installed a tubing rotator on the world’s only low-profile, ultra-long-stroke, sucker rod-pumping unit. The proprietary design of this pumping unit (in use since 1987) allows installation of sucker rod pumps in height- and space-restricted locations, such as offshore platforms, town lots and multi-well cellars.

The tubing rotator was added to complement the ultra-long, 336-in. stroke length – this combination can extend tubing / rod life. In addition to tubing rotation, the rods are rotated by tubing string rotation-induced torque. This is achieved by allowing the integral polished rod to rotate freely inside the hydraulic cylinder, as the hydraulic fluid that lifts the piston also acts as a thrust bearing.

The current installation, however, does not ensure that the rods are being rotated, as it only allows the rods to rotate if tubing-induced torque friction is present. To improve on this design, a free-sliding linear guide is being developed, and will be available for future installations, to ensure rod-string rotation at the same speed as the tubing.

The low-profile, long-stroke cylinder design is submerged inside the tubing string to eliminate the vertical profile. To make room for the "subsurface" cylinder, tubing is hung at the surface with a single casing joint, which is sized to allow ample clearance for the cylinder inside the tubing string. The bottom of the casing joint is attached to the top of the existing tubing string with a casing-by-tubing crossover.

The rod string is then installed, and the cylinder is hung from the top cylinder head via an API-type flange, while the entire cylinder body is submerged below the flange inside the tubing string (casing joint). The cylinder assembly includes an integral polished rod, a high-pressure stuffing box and internal flow passages for produced fluid outlets, so no other equipment is required.

Since the cylinder is larger in diameter than a rod string, standard tubing rotators are not compatible with low-profile cylinder design. RPS Canada was approached by HRPI and Stocker Resources (Los Angeles) to design a large-diameter tubing rotator that would adapt to the HRPI subsurface-cylinder wellhead design. The first such rotator went into service in June 1999, and has operated troublefree.

Tubing drain for hydraulic pump. Hydraulic tubing drains have been used for many years as a method of communicating between tubing and annulus. Weatherford Artificial Lift, Houston, recently adapted the drain sleeve to a hydraulic artificial-lift, bottomhole assembly (BHA), resulting in an enhanced downhole tool and process that saves time and money.

The S Drain BHA sleeve is available on equipment for 2-3/8 and 2-7/8-in. tubing. The sleeve has been adapted to BHAs for both jet and hydraulic reciprocating pumps. It is a simple design, that is easy to install and operate. It can be shifted with hydraulic surface equipment normally installed at hydraulic-lift locations. It has a slim design for maximum annulus flow area. And the BHA has large fluid-discharge ports to reduce turbulence and fluid erosion.

Currently, when a new well which is expected to free flow initially is completed, a packer is set and tubing is run. The well is perforated and allowed to free flow for as long as it will. After the well stops flowing, the tubing is pulled and an artificial-lift system is selected and run. This sequence requires the tubing to be run twice. A BHA with blanking tool could be run in Step 1, however this limits access through the completion when work below the packer is required.

If an S Drain BHA is used in a new well that is expected to free flow initially, a packer is set and tubing with BHA is run, Fig. 15A. With the drain in the closed position, tools can be run through the BHA, and the well can be perforated. Once the well stops flowing, the standing valve is dropped and pressure is applied to the tubing string, causing the pins to shear and the drain sleeve to shift, opening the tubing string to the annulus. The hydraulic pump is then circulated into the BHA, and pumping begins, Fig. 15B.

Fig. 15. Tubing drain for hydraulic pumping system. S Drain assembly can be run in new well, A. When artificial lift is needed, drain sleeve is opened and hydraulic pump is run, B.

This installation technique does not require the tubing to be pulled nor any type of wireline operation to shift the sleeve. All additional operations are done with fluid flow and pressure. The savings, therefore, are in cost of pulling the tubing and increased production due to equipment availability.

Multiplex-pump plunger seal. Weatherford Artificial Lift Systems, Houston, is introducing a multiplex-pump seal improvement for high-pressure, positive-displacement pumps used in the surface hydraulic power fluid unit for downhole hydraulic pumping systems.

Most packing systems used today have one primary seal that is exposed to the product being pumped and separates the product from the atmosphere. When the seal leaks, the product can go on the ground or into the air; the Hydro-Balanced Packing System is designed to control the product with a barrier fluid that is pre-chosen.

The technology can best be described as having a primary seal that is exposed to a barrier fluid and a pressure transmitter that is used as a secondary seal to separate product from barrier fluid. When the primary seal leaks, an environmentally friendly barrier fluid is the only thing exposed to the atmosphere. Fig. 16 shows a pump plunger stuffing box with the transmitter / piston, barrier fluid and the primary seal arrangement.

Fig. 16. Pump plunger stuffing box with transmitter / piston barrier fluid and primary seal arrangement

Pneumatic Lift

Two field-proven systems that utilize natural gas supplied either from the well annulus itself, or compressed gas from a local unit or a multiwell system, are described here. Both systems utilize a vertical surface cylinder and piston-lift concept.

Pneumatic pumping system. The McCoy Pneumatic Rod Pumping System (MPRPS) offered by Permian Production Equip., Inc., Midland, Texas, lifts the rod string and strokes the downhole pump by utilizing natural gas energy available in the field, Fig. 17. The MPRPS is operated with pressurized gas from a source such as a compressor discharge line, trunk line, another well or perhaps from the well to be lifted itself.

The unit incorporates a piston in a cylinder. The piston rod acts as the polished rod of the well and passes through the stuffing box where it connects to the well’s rod string. It operates solely by gas pressure and does not require any type of external energy such as a motor.

The system takes supply gas through a pneumatic motor valve into the chamber under the piston. When pressure under the piston exceeds weight of rods and fluid, the piston travels up the cylinder bore. At the top of the stroke, pressure under the piston passes through a sensing port and shifts the pneumatic motor valve to the exhaust position.

Fig. 17. McCoy Pneumatic Rod Pumping System uses natural gas energy available in the field. Piston rod acts as polished rod, going directly through stuffing box to sucker rod string.

The weight of the rods forces the piston back to the start position, where pressure holding the pneumatic motor valve in the exhaust position is relieved. This action allows the spring-loaded valves to shift back to the supply line, which starts a new stroke. The weight of the rods forces used gas into the well’s flowline, which returns it to the production facility along with the well’s production.

Pneumatic pump jack. Maranatha Industries, Farmington, New Mexico, has designed a pneumatic pump jack, called Pneulift, as a niche product to address certain environmental concerns and lower operating costs in artificial-lift situations, Fig. 18. The unit is available in stroke lengths from 40 to 78 in. and is intended for use to a maximum depth of about 8,000 ft. Stroke speed and length are easily field adjusted to accommodate specific fluid-removal requirements on a well-by-well basis.

Fig. 18. Pneulift pneumatic pump jack, available in 40 to 78-in. stroke for pumping to 8,000 ft, operates on well annular gas or compressed gas.

Pneumatic pump units are designed to operate in a constantly pressured environment, with power being applied on both up- and downstroke. By maintaining a state of pressure equilibrium, dynamometer tests show extremely well-balanced rod string harmonics, virtually unaffected by stroke speed or length. The unit operates free of any external energy source and provides quiet lift operations. Since no motor is required, fuel use is eliminated, and all gas used is exhausted into the sales line. There are no atmospheric emissions. The cylinders are powered by annular gas, wellsite compression or a centralized compression site. By varying stroke length and speed, the unit is capable of lifting up to 150 bpd.

Operating pressures required to power the unit depend on well depth, downhole pump size and sales line pressure. Typical operating pressures are in the range of 25 to 175 psi. A solar-powered, telemetry-compatible automation package is currently under development to allow intermittent operation and address pump-off situations in low-rate wells.

Plunger Lift

In this concept, the artificial lift operates without tubing or sucker rods, relying on the up and down travel of a plunger sized to fit within the well’s casing. A slug of liquid flows through the plunger when it is at the bottom of the well. Pressure above the plunger is then relieved, and formation gas pressure drives the piston upward with its load of liquid. One innovation in this category is described here.

Casing plunger system. Multi Products Co. in Millersburg, Ohio, has developed an artificial lift system that operates in the well with no tubing to save the added cost of that tubing and additional lift equipment. Other casing-type plungers have been marketed. One drawback to these systems includes the dynamics of a large device flowing upward in a wellbore with high-pressure gas sealed below it.

Regulation of the upward-flow velocity with such a device has always been a concern. The reduced gas volume rate required to displace the tool safely to surface limits the gas sales. A solution to this problem was developed by Multi Products with the use of a metallic sensing device and an electronic controller, designed as the JetStar Fail Safe Controls system, Fig. 19. The sensor cannot be deceived by noise or stray signals. This prevents the large-ported valve from opening prematurely and damaging surface equipment.

Fig. 19. Surface control for JetStar casing plunger artificial-lift system that controls plunger speed at surface lubricator location. Click for enlarged view

Upward plunger velocity is controlled by reduced orifice size in the outlet line from the lubricator to the flowline. Arrival of the casing plunger into the lubricator signals the controller that the lower, large-ported valve is now safe to open. This change of size in the flow orifice to the flowline can account for several-hundred-thousand cubic feet of increased gas sales. The resultant production not only creates a profitable scenario in gas volume, it also gives the well a system that can produce to "plug-and-abandon" status.

The plunger is released after a set time period based on well deliverability. The plunger must contact the bottomhole stop set in the casing before the internal bypass in the plunger closes. After the bypass closes, the plunger returns to the surface, with velocity controlled by the smaller orifice in the lubricator outlet.

The authors

James F. Lea, Professor, Chairman of Petroleum Engineering, Texas Tech University, Lubbock, holds BS/MS degrees in ME from the University of Arkansas, and a PhD in ME from Southern Methodist University. He worked for Sun Oil Co. as a research engineer from 1970 to 1975; from 1975 to 1978, he taught engineering at the University of Arkansas; and from 1979 to 1999, he was leader of optimization and artificial lift at Amoco EPTG. He assumed his present position in 1999. Mr. Lea is a registered professional engineer in Texas; he has authored / co-authored several patents, as well as publications on artificial lift.

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.

Henry V. Nickens graduated from Louisiana State University (BS, physics), University of Southern Mississippi (MS, mathematics), Carnegie Institute of Technology (MS, nuclear engineering) and Louisiana State University (PhD, fluid mechanics). Dr. Nickens has worked as a nuclear engineer for Westinghouse Electric Naval Reactor Division and joined Amoco in 1981, where he has researched well control, drilling fluid hydraulics, artificial lift, optimization and software development. He is currently with BP Amoco in Houston on the Integrated Asset Modeling team.

	Part 2