Sucker rod pumping, progressing cavity pumping, automation/control. Twenty-four innovations for improved field operations – What’s New in Artificial Lift, part 1

James F. Lea

The overall subject of artificially lifting producing oil wells, vs. relying on the wells’ abilities to flow, is covered in this article and a second part to appear next month. This article covers sucker rod pumping and progressing cavity pumping (PCP), plus several advances in remote control and automation of pumping systems. Part 2 will introduce innovations in electrical submersible pumping (ESP).

In the major category of sucker rod pumping, 15 recently applied tools/techniques include: 1) six devices for improving horse head to wellhead operations such as safety, maintenance and load measurement; 2) four new devices for the downhole pump system itself; 3) two systems for monitoring/controlling speed and power; 4) an improved annular gas separaton scheme; 5) an annular production logging method; and 6) a new coiled rod/tubing service unit.

Five PCP improvements include: two offerings for wireline retrievable pumps above submersible electric motors; two wellhead designs for running/handling PCPs and ESPs; and software for controlling an ESPCP. For automation/control, four industry systems for pumping well monitoring and control are featured. Essentially universal systems, they offer options for controlling rod and PCP systems, as well as plunger lift.


Fifteen ways to improve field operations are shown here. Innovations described and illustrated include surface devices from bridle dynamometers to new wellheads and stuffing boxes/BOPs. Downhole equipment ranges from sand washing devices and valve operators to a new double acting pump, gas/oil separation above a packer, and a tubing-actuated stuck-pump remover. Other technologies include an annular production logging technique from China; a new coiled rod/tubing service unit from Canada; and three well/field remote control/monitoring systems.

Pumping unit shock absorber. Various shock absorbers for beam pumping systems have been made available in the past for operation, both in surface equipment and various downhole locations, in the beam pumping system. In a recently introduced innovation, D.C.I. Oil Well Pumping Unit Shock Absorbers, Rusk, Texas, uses elastomeric disks inside a steel canister mounted between the polished rod clamp and the carrier bar, Fig. 1.

Case histories indicate that installation of the system known as the DCI Shock can: 1) increase production because: flexing of the unit is said to increase stroke length; a higher spm can be achieved because of load reduction due to the absorbers; and a smoother stroke allows better pump fillage; 2) reduce PRHP and KW requirements; and 3) reduce bearing loads, gear loads and rod stress by decreasing maximum PRL and increasing minimum PRL.

The manufacturer indicates that the unit is easy to install and has a long life. Fourteen models are available for all makes/models of pumping units.

Gas separation concept. Gas separation for beam pumping installations has included: setting the pump below the perforations (where possible), using various types of “poor-boy” systems, a decentralized modification of the poor-boy system, a packer type of gas separator and other methods. The packer type separator system is known to provide good separation, but most operators do not like seating (and un-seating) packers, as trash and sand can accumulate on top of the packer, complicating its retrieval.

Stren Co., Houston, has developed a packer-type annular gas separator called the Maximizer Series 4300, Fig. 2. The system uses an inflatable packer that will allow the operator to easily unseat the packer by simply unseating the pump. This allows pressure to be released from the elastomeric packer element, fluids can then wash over the top of the packer to remove any trash accumulations. When the pump is seated and pumping is commenced, as the tubing fills, that fluid is ported into the packer and pressures up the element to seal the packer.

Separation occurs in the tubing-casing annulus because production is directed through the packer, through a cross-over into a riser tube about 100-ft long and up the annulus. The tube discharges into the open annulus and produced fluid falls back down to fill the liquid reservoir from which the pump draws, with its intake located just above the packer. Rising gas bubbles in the large annular space are not carried downward through the slower-moving liquid. Thus they can break out and be produced as free gas through the annulus.

Sand washing tool extends plunger/barrel life. Kajon Oil Tools of Houston, has introduced its patent pending Sandbuster as an inexpensive solution for rod pumping problems caused by sand, scale and iron sulfide in production fluids. The unique design prevents sand or solids from being forced between the plunger and the working barrel, Fig. 3.

The top assembly is attached to the top of the plunger below the cage. On the downstroke, production fluid passes through the assembly where flow is slightly restricted by the cone-shaped inside, forcing fluid through radial holes on top of the wiper. The flushing action causes any accumulated sand to be carried upstream with the produced fluid. Radial holes on each side of the wiper equalize pressure on both sides of the wiper, which prevents sand or solids from being forced between the plunger and the barrel. The bottom assembly replaces the seat plug; its venturi shape causes trapped sand or solids to be pulled into the main stream of produced fluid on the downstroke, and thus flushed from the plunger-barrel contact area.

The device is made of stainless steel and is available in all API sizes. Wipers are available in an elastoplastic material with high tear strength/abrasion resistance up to 250 [degrees] F; a material is available for higher temperatures. Split wipers are used on insert pumps; a mandrel applies the wiper for tubing pumps.

Floating chamber compensates PR misalignment. The Cherny Floating Chamber (CFC) is designed to fit between the pumping tee and the existing stuffing box currently used by an operator, Fig. 4. Manufactured to suit all rod and wellhead connection sizes, it automatically compensates for any angular polished rod misalignment within the designed parameters. The CFC clearly monitors alignment and indicates when adjustment is required. Stuffing box wear can be reduced by maintaining proper PR alignment. The unit is supplied by Cherny & Sons Pty. Ltd., Maddington, Western Australia.

Polished rod with two pin sizes. For more than forty years, polished rods have remained essentially the same. Now, stimulated by oil company and oilfield supply store desires to reduce costs and inventories, and always have polished rods when needed, a simple idea was developed by Hasco Manufacturing Co. of Sapulpa, Oklahoma.

The Twin Pin Polished Rod features a different API thread on each end, Fig. 5. This feature, combined with a color code system to help identify inventory at-a-glance, has changed the conventional way of thinking about PRs and allowed the industry to save time, labor, confusion, costs and warehouse space.

Hydraulically actuated valve opener. Dartt Valve Co., Spring, Texas, offers a special metal insert which – in its location directly below, and within a housing connected to the traveling valve – is exposed to fluid movements as the pump plunger travels up and down. The solid insert features two “hydraulic amplifiers” that contact the wall of the housing and are moved upward within the housing on the downstroke by hydraulic pressure, into enlarged passageways in the housing wall that then allow fluid bypass, Fig. 6. In the same motion, the angled upper tip of the insert is driven upward to contact and physically unseat the traveling valve ball. This action thus helps open the valve and prevent gas locking.

The second feature of the insert is that on the upstroke, it is moved downward within the housing past the fluid bypasses such that each of the two enlarged diameters sealingly contact the housing wall. This creates multiple secondary seals to backup the traveling valve should it be lodged open by sand. The Dartt valve is installed in the bottom of the conventional double female traveling valve cage by removing the plug that retains the ball and seat, i.e., the unit replaces that plug and is tightened in the same manner as cages.

Variable speed drives. Magna Speed Drives from Stromag, Inc., Roanoke, Texas, provide speed reduction for progressing cavity pump (PCP) or beam pump motors. For PCP applications:

* Motor current is monitored for pump shaft torque control

* Soft start is available for adjustable acceleration

* Digital readout of pump speed is available

* Maximum and minimum speeds are adjustable, and

* Automatic backspin control is available.

For beam pump applications, it is claimed that: rod fall rate can be controlled in heavy oil or horizontal wells; rod stacking can be prevented in deep wells with fiberglass rods; and pumpdown control can be applied without stopping the unit. Further, polished rod loads and motor amps can be monitored and controlled, and a soft start is possible in cases in which the motor is started with no load.

The VSD uses the eddy current principle. Motor speed is not affected, but the unit acts more like a “magnetic clutch,” transmitting the desired motor speed. Motors from 2 to 200 hp can be controlled. For an application, rpm (present and desired), shaft size and installation hp must be supplied.

Rod speed/load monitor. OSCO, Inc., Oklahoma City, Oklahoma, offers VFDs (Variable Frequency Drives) for beam pumping installations. The system varies the speed of a standard, three-phase, electric motor and monitors the load. Process parameters that have always been fixed can be adjusted for maximum benefit. One application is a slow downstroke to allow rod fall and a faster upstroke to increase production.

Another application is for beam pumping wells which are adversely affected by constant starting and stopping due to pump-off. If pump-off controllers (POCs) or timers are being used, the VFD can be interfaced in the control system so that off time becomes time at low speed and top speed may be increased or decreased. This allows much more precise control of fluid level which can result in reduced sand production, lower average bottomhole pressures and increased production.

Additional advantages include conversion of single-phase power supply to three-phase, and elimination of onrush currents to the motor, i.e., simple implementation of remote control and no need for a power factor correction. Other applications for the VFD are PCP and ESP installations.

Pump unseating device. A method to provide for positively unseating a stuck pump patented by Harbison-Fischer, Crowley, Texas, features a slide mechanism that allows the weight of the tubing to push the hold-down of the pump out of the seating nipple. It is run immediately below the seating nipple and above the tubing perforated nipple. The sliding mechanism will push the hold-down of the pump out of the seating nipple when partial weight of the tubing is applied. The hold-down will clear the seating nipple several inches, allowing hydrostatic pressure in the tubing to equalize with the bottomhole fluid level.

To activate the unseating device, the tubing must be lowered to the bottom of the well. After reaching bottom, set-down weight equal to weight of the sucker rod string in air is first applied. Additional weight necessary to unseat the pump will vary according to individual conditions, but 10,000 to 20,000 pounds is typically used, the developer says. When the stuck pump unseats, the fluid level in the tubing will equalize with the fluid level in the casing/tubing annulus.

Principal reported features/advantages include: it can be used with any API insert pump; it prevents stripping jobs; it is environmentally protective compared to losing fluids on the rig floor; and it enhances safety. The system allows more confident use of lighter rods; it is an advantage when used with fiberglass rods; and it can reduce rig cost. In another application, it can be used to unseat the pump for downhole treating, hot oiling, etc., thus avoiding pulling on the pump.

Annulus production logging in rod pumped wells. Jianghan Oil Production Technology Research Institute, Xinagyang, Quangjiang City, Hubei Province, P.R.C., has developed an annulus production logging technology for rod-pumped wells. In application of the method, a logging tool is run and pulled through the annulus between the casing and the tubing.

The logging technique requires lifting devices, a rotational decentralized wellhead and a production logging tubing string. The rotary decentralized wellhead is critical for the annulus logging technique by forcing the production tubing string against the casing to allow passage of the logging tools.

The surface instrument system consists of secondary instruments, a multi-channel acquisition unit and a computer. It uses new electronic technology and advanced logging software modular programing techniques. The system can simultaneously carry out the in-situ testing of six parameters and features high operating speed, data-processing capability and high reliability.

Innovative bridle dynamometer. The Quick Draw dynamometer manufactured by D-Jax Corp. in Midland, Texas, is designed to measure change in tension on the bridle of the beam unit’s horse head while a well is pumping, Fig. 7 It can be installed quickly without having to clamp-off the polished rod, and will draw a card that closely duplicates those drawn by dynamometers with load cells or strain gauges. A qualitative instrument, it is safer to use, the supplier claims, than quantitative dynamometers, because it does not require “standing the well off” for installation.

The innovations in the new dynamometer make it more user friendly and versatile. The gears can be shifted from short to long stroke without having to change out the string pulley. The new slip clutch eliminates internal gear damage if the instrument is in a short-stroke position but run on a long-stroke well by mistake. The preloading adjustment nut makes it possible to draw a more representative API card on deep wells with a small-bore pump. The paper spool is now held in-place magnetically rather than by a button release used on the previous models.

Dual action pumping system. Dresser Oil Tools in Houston, has introduced an engineered solution for gravity separation of oil and water in a rod-pumped well. This Dual Action Pumping System (DAPS) produces oil and water from the annulus on the upstroke, while injecting water on the downstroke, using gravity segregation. This unique downhole oil-water separation system lifts 18 to 30% of the total fluid in the well-bore, while simultaneously injecting most of the water through a packer for disposal. Some benefits of this system include increased oil production through greater withdrawal from the formation, reduced water handling costs, reduced energy consumption and lower cap ital investment on equipment.

The pumping system requires one rod string, one tubing string and a packer to separate production and injection perforations, Fig. 8. Injection pressure is generated by rod and fluid weight. A unique rod design program is utilized to prevent rod compression. Results of the first 12 installations saw average oil rates increase to 29 bopd from 21 bopd, and average water rates decrease to 105 bwpd from 401 bwpd, with 445 bwpd injected into the lower perforations.

This pumping system was developed through a joint effort between Dresser Oil Tools and Texaco EPTD, with preliminary tests confirmed by Talisman Energy Inc., Chevron Production and Rocky Mountain Oil field Testing Center. The system was described in paper SPE 38790, “Dual injection and lifting system: Rod pumps,” presented at the 1997 SPE Annual Technical Conference, San Antonio, Texas, Oct. 5-8, 1997.

Oil reservoir gland for polished rod. Flow Control Equipment, Inc. (FCE), a unit of Robbins & Meyers, Inc., located in Borger, Texas, and Edmonton, Alberta, Canada, has developed a new high performance oil reservoir gland called the HP-ORG that improves packing performance by insuring lubrication and cooling of the polished rod moving through the stuffing box, Fig. 9. Oil consumption and maintenance are significantly reduced, compared to the conventional oil reservoir gland (ORG).

Felt wicks in the unit extend periods between service without sacrificing lubrication quality. Both new and original systems are compatible with FCE’s Anti-Pollution Adapter (APA). The new gland is optional on all new or existing Hercules Classic stuffing boxes. A modified version is available for Hercules inverted cone stuffing boxes. The new ductile iron stuffing boxes are available in 1-in. through 1 3/4-in. sizes.

Stuffing box for improved pollution control. FCE now offers a new system, the Pollution Control Stuffing Box (PCSB), Fig. 10. In addition to the two independently adjustable cone packing chambers in the Hercules double packed stuffing box (DPSB), the new system has a third packing chamber. This high performance lubricating upper gland (HPLUG) has eight chevron packing rings for added insurance against accidental spills.

The upper chamber serves as a depot for lubrication injected through a grease fitting on the side. When the upper chamber is connected to a Hercules Anti-Pollution Adapter (APA), any leakage through the primary stuffing box packing will be forced into the adapter rather than escaping into the environment. The APA contains a weight sensor that triggers an alarm if stuffing box leakage is detected, and will shut down the pumping unit.

The pollution control adapter (PCA) located at the base of the unit includes a flapper valve that automatically closes if the polished rod breaks. Stuffing box packing in the PCSB can be changed under pressure. The bottom connection can be tailored to customer specs. And the system can be equipped to conform to NACE MR-01-75, and operate at -50 [degrees] F temperatures. Further, the top HPLUG and lower PCA can be retrofitted in the field to existing Hercules DPSBs.

Coiled rod/coiled tubing servicing unit. Couplingless rod is gaining wider popularity due to an increase in the number of directional and horizontal pumping well completions. Lower well operating costs have been achieved using coiled rod in deviated or progressing cavity pump (PCP) wells due to lower tubing wear because of the absence of couplings, and almost total elimination of rod coupling failures.

C-Tech, a PWI (Palynchuk Widney Inc.,) Company in Calgary, Canada, has developed a unique and highly versatile, patented injector head, the Lazarus Mark V Unit, capable of running and pulling all shapes and sizes of coiled rod. The coiled rod injector head is lighter and less complex than any existing systems now available. The 4,600-lb (2,090 kg) injector head is capable of pulling up to 68,000 lb (30,250 daN) and is currently undergoing final testing prior to field deployment. Minor modifications to the head can provide even larger pulling force-to-weight ratios.

Other configurations can be provided to meet a variety of field conditions, such as a combined workover/coiled rod rig. The versatility of the injector lies in the ability to pull and run not only coiled rod, but also coiled tubing and jointed rod and tubulars. Coiled tubing reeling development is already in the advanced design stage. It can be changed from rod to tubing or vice versa by unit operators in the field. The versatility of C-Tech’s injector head allows for a total reeling system, ultimately lowering costs of setup, transportation and personnel for a wide variety of well maintenance equipment.


For the growing use of PCPs, five new ideas that have been applied include two suppliers’ approaches to a wireline retrievable PCP operated by an ESP type motor; and two wellheads for handling both PCPs and ESPs. New software for an ESPCP installation is introduced.

Wireline retrievable PC pump. Reda, a Camco International Co., Bartlesville, Oklahoma, has developed a downhole electric motor driven progressing cavity pump (ESPCP) wireline retrievable system, which allows the PCP to be pulled and rerun with use of a slickline unit, Fig. 11. The electric submersible motor, protector, gearbox, intake and cable are installed on the production tubing as in a typical Reda ESPCP installation. The PCP rotor and stator are attached to a standard X-lock and may be pulled in a single operation using standard slickline pulling and running tools.

System design also allows pump size and geometry to be changed without affecting downhole equipment. A lubricator may be used for well control, eliminating need to kill the well and risk formation damage. This system allows pumps to be changed quickly with minimal equipment by an experienced slickline operator.

Through-tubing conveyed electrical submersible PCP. Centrilift, a Baker-Hughes Co., Claremore, Oklahoma, has developed an electric submersible PCP through-tubing conveyed (ESPCPTTC) wireline or coiled tubing deployed system, Fig. 12. This new technology was designed for installation and removal of a PCP using wireline or coiled tubing.

The procedure eliminates need of a workover rig for pump changeouts; basically it was designed to reduce the high cost of workovers. Three methods are used to pack off the assembly, which isolates the low- and high-pressure areas: 1) tubing packoff with a tubing stop; 2) X-lock V-packing with X-nipple; and 3) sealbore V-packing with tubing stop.

The system uses standard ESPCP technology in conjunction with standard PCP equipment and can be deployed in 3 1/2-in. and larger tubing. The assembly has capacities up to 100 hp and can produce up to 500 bfpd in 3 1/2-in. tubing. Development work is currently underway to increase production inside 3 1/2-in. tubing using multi-lobe PCP technology. In 4 1/2-in. and larger tubing, the production capabilities are increased.

ESPCP application software. The Centrilift AutographPC application software for ESP equipment, which was introduced in fall 1995, has recently been updated from version 2.51 to 3.1. The changes and additions include: program conversion to Windows 95; capability to design electric submersible progressing cavity pump (ESPCP) systems; and capability to size equipment for downhole oil-water separation, HydroSep applications.

The system allows for user-entered pump curves. Any section of the casing/tubing string can be selected as annular or tubular flow; and there is internet access directly from the program. Another change involves additions to the hypertext help information.

Integral flow tee and BOP for PCPs. Flow Control Equipment Inc. (FCE), a unit of Robbins & Meyers, Inc., located in Borger, Texas, and Edmonton, Alberta, Canada, has developed the Hercules integral flow tee and BOP for improving PCP operations, Fig. 13. The one-piece design results in a shorter overall height than separate components and provides maximum stability for PCP driveheads.

The standard model has 3-in.-ID and a 2,000-psi WP. It has a 3,000-psi, 3 1/2-in. API top flange, 3-in. LP side outlets, and either a 3 1/8-in., 2,000-psi or 7 1/18-in., 2,000-psi bottom flange. However, bottom, top and side outlet connections can be tailored to individual specs. A 3,000-psi WP model is available with 4 1/16-in. maximum ID for production rates to 2,500 bpd. Materials for hazardous environment NACE and low-temperature applications are also available.

Wellheads for ESP and PCP installations. FCE offers a wellhead for an electrical submersible pump (ESP) installation that can be used to replace a PCP conventional rotary drive unit wellhead for a PCP driven by an ESP motor. In both PCP and ESP applications, the FCE Hercules wellhead is ideal for use with either low pressure (250-psi) bolted pack-off glands and slips, or high-pressure (2,000-psi) penetrators and mandrels to provide a seal around the electrical conductors at the surface, Fig. 14.

Because of its simplicity, the low-pressure HHS bolted packing gland is a favorite in locations where spare parts and service are hard to obtain. The low-pressure packing gland is split and eliminates need to splice the electrical cable following pump/tubing installation. As a result, short circuits are less likely to occur. All Hercules submersible wellheads are full open and feature convenient wrap-around, heat-treated slips for lower pressures or heavy duty mandrels with electrical penetrators for higher pressures. The low-pressure design is also finding increasing use with downhole electrical heaters.

Available mandrels and electrical penetrators can be installed in high-pressure HHS wellheads to seal against pressures up to 2,000 psi. Other Hercules submersible wellheads using mandrels and electrical penetrators can be equipped for 3,000 psi WP. The bottom connection, threaded or flanged, on any of these submersible wellheads is optional and can be tailored to requirements. Adapter flanges are available to make the top connection, threaded or flanged, compatible with any API BOP. Wellheads are available for [H.sub.2]S and C[O.sub.2] service, as are penetrator systems conforming to NEMA Class 1, Division 2, electrical codes.


Four suppliers describe their comprehensive systems for gathering field data on pumping systems and comparing that with designed system parameters and production goals. Provisions for automatic control, shut-down and alarms, and data transmission to supervisory offices are typically provided.

Flexible wellhead automation. Automation Associates L.L.C., Midland, Texas, has produced a “universal” wellhead manager featuring its general purpose microprocessor-based Model 2 Remote Terminal Unit (RTU), Fig. 15. The system will help producers standardize different control needs with one piece of equipment designed to reduce inventory, repair costs and problems of connecting different types of controllers to a central monitoring system.

The company has designed the hardware platform to perform a wide variety of control and telemetry functions without modifying wellhead hardware. One control device is designed for pump-off control, plunger lift control, generic RTU, gas flow measurement, injection control (either water or C[O.sub.2]), pressure/flow control, and gas-lift control with the same hardware. All that is required to change application is to replace one computer chip.

This system provides control functions at the wellhead; and control parameters can be done either locally or remotely with a telemetry link. It contains eight analog inputs, which also function as status indicators or accumulators. This gives flexibility for a wide variety of applications.

Plunger lift automation. Ferguson Beauregard, Tyler, Texas, offers the Auto-Cycle Plus production automation system. Each controller contains the FB Auto-Cycle method of plunger lift control. Self-adjustment of time and pressure settings for plunger cycles keying on plunger velocity is used to operate plunger lift wells. The system allows remote control of motor valves and chokes, and monitors tanks and pits for high-level alarms. It can even control allocations to avoid FERC 636 penalties.

Several other advantages are reported. Data is calculated in a PC; analog data from the well site controller [ILLUSTRATION FOR FIGURE 16 OMITTED] is retained in its raw format. The data can be re-integrated or recalculated at any time. The system is compatible with desktop or laptop PCs, and makes use of Windows, including Excel and Lotus 1-2-3 spread sheets. And field maps, well facility schematics and trend profile screens can be developed and displayed.

Multipurpose controller. Delta-X Corp., based in Houston, has introduced a new multipurpose controller (MPC) with several applications. The unit is a dual-microprocessor-based, single-board controller that has multiple RS 232/485 ports, graphical LCD with keypad option, onboard modem and expandable I/O. This one system has the capability to meet many requirements of oilfield automation. Current applications available include DGU (Data Gathering Unit), RPC (Rod Pump Control) and PCP control.

The DGU allows the operator to setup I/O for measuring analog, digital and pulse sensors. Local logic is provided and unit-of-measures are shown for levels, rates, pressures and temperatures. The DGU can be used at well sites, satellites, batteries, etc.

The RPC uses the company’s patented single set point control and automatic downtime feature. This can be combined with a beam transducer, the built-in auto zero circuit in the MPC, or a load cell. Also included are 60-day plots, time stamped events, live and stored dynamometer cards, plus IPA (calculates production for each 24-hr period). There are optional packages for maintenance, alarm, safety, and 2-speed for gas engine and VSD control.

For PCP applications [ILLUSTRATION FOR FIGURE 17 OMITTED], the controller protects the drive system and rod string from excessive torque while maintaining optimum fluid level. In addition to pump control, the unit calculates, stores and transmits production data, operational parameters, alarms and historical data. The controller measures production and motor power consumption, and outputs to the VSD a signal to control motor speed. This adjusts speed according to production available and operator-set torque levels.

SCADA-plus system for artificial lift. Case Services, Inc. in Houston, combines total field operation, detailed analysis such as downhole cards, well testing and production performance in one integrated suite called csLIFT, Fig. 18. The software provides monitoring, control and analysis in one tool set. It supports any size field with any number of wells and any number of different controller types.

The csLIFT system:

* Is architected specifically for oil and gas fields

* Supports beam pumping, injection, ESP, gas wells and facilities

* Provides automatic and semiautomatic well testing, and

* Its integrated downhole analysis calculates pumping efficiency, mechanical stress, etc.

Further, the system is designed for: 1) communicating with different devices and protocols over a single frequency; 2) providing instant information from across the entire field; and 3) supporting a variety of POCs, RTUs and PLCs. It has built in alarming, trending and reporting capabilities. The server software uses the Windows NT operating system; and client software uses Windows, Windows 95, or Windows NT operating system.

Applications are based on a Windows NT client/server architecture, and are written in C++. The system allows the operator to monitor and control an oil and gas field from a computer. It is no longer necessary too have a person visit every well in the field to look for problems. Instead, those employees can be solving problems and getting wells and facilities up and running optimally as soon as possible.

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 1998 Gulf Publishing Co.

COPYRIGHT 2000 Gale Group

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