What’s new in artificial lift

Part 2—More developments in sucker rod pumps, gas lift and an innovative cable pump.  

James F. Lea, PL Tech LLC; and Herald W. Winkler, Texas Tech University 

Continuing our annual artificial lift roundup, this part features more advances in sucker rod pumps, including a small, low-profile unit and a very high-strength sucker rod. A sucker rod service unit is also featured, as one can only go so long between the necessary rod servicing jobs. A rodless, cable-operated pump is also described.

Also featured are new progressive cavity pump designs and a new elastomer for PCPs, as well as a new high-temperature series of PCPs; an RF device that claims to remove scale, even barium sulfate; a downhole gas separator; and seven advances in gas lift, both as an oil producing method and as a gas well deliquification method.

SUCKER ROD PUMPS

Three innovations in sucker rod pumps and services, and a rodless, cable-operated pump that functions much like a sucker-rod pump, but without the rod, follow.

Linear rod pumps. Franksville, Wisconsin-based Unico Inc. has added 44-in.- and 56-in.-stroke-length pumping units to its lineup of Linear Rod Pumps (LRPs). The new units have a lifting capacity of 20,000 lb, nearly twice that of the original 32-in.-stroke model. The LRP lift system is a small, lightweight, easy-to-install linear pumping unit that mounts directly to the wellhead, Fig. 1. It takes advantage of the motor reversing and servo-positioning capabilities of a flux vector variable-speed drive to directly control the sucker rod using a simple rack-and-pinion mechanism. The sucker rod is suspended at the top of the rack by a conventional rod clamp and passes through the center of the pumping unit into the wellhead. The rack is lubricated with a fully contained oil bath. Several gearbox and motor options are available to accommodate a broad range of production requirements.

Fig. 1. Unico’s LRP linear rod pump.

The LRP design supports both casing and tubing mounting options, and the unit can be transported in the back of a pickup truck. Unico says the compact size of the system will lead to cost savings on site preparation, transportation logistics and equipment installation. Quiet and unobtrusive, the low-profile pump is advantageous for environmentally sensitive installations. Since its only exposed moving part is the polished rod, the LRP system is significantly safer than a traditional walking-beam apparatus.

Integral to the LRP system is an AC drive for motion control and well automation. Fully automatic, the drive provides surface and downhole dynamometer generation, inferred production calculation, pump fill control, soft landing to prevent fluid pound, power evaluation, pump intake pressure estimate, fluid level control and more. An optimizer mode continuously modulates pumping speed to match well inflow as determined by downhole load data. Unico provides interface to head-end software, a well report generator, and pressure and temperature sensors with alarms. The system supports multiple serial communication protocols.

LRP units have been successfully installed on more than 100 oil and gas applications in the United States, Canada and Venezuela, at pumping depths ranging from 1,000 to 7,000 ft.

High-load sucker rod. Upco Inc., based in Claremore, Oklahoma, has developed a new Super D sucker rod, Fig. 2. Beam lift with heavy loads can be troublesome when moving corrosive fluids or when operating in deviated wells due to fatigue failures initiated from corrosion pits. Sucker rod materials that will tolerate higher tensile loads are less ductile (more brittle, harder) than materials that will only tolerate lighter loads. A general rule of thumb is to use the most ductile (softest) rod that can carry the load when pumping in a corrosive environment.

Fig. 2. Upco’s new Super D steel sucker rods have high load-carrying capacity but low notch sensitivity, and are suitable for use with high loads in corrosive environments.

This rule is based on the concept of notch sensitivity—the reduction in fatigue strength caused by a notch (pit). Materials with higher hardness values (such as high-strength rods) have high notch sensitivity, thus allowing a minute pit to cause the rod to fail from corrosion fatigue in a relatively short period of time. On the other hand, materials with lower hardness values (such as KD-grade rods) can better tolerate large corrosion pits over a longer period of time. These materials have low notch sensitivity, which equates to greater toughness.

There is a significant gap in relative toughness of high-strength and various D-grade rods. In many instances better results have been obtained by overloading the D rods rather than suffer the loss of toughness inherent with the high-strength rods.

The new steel rod has a load-carrying capacity nearly equal to high-strength rods, but much lower notch sensitivity. The new rod bridges the significant gap between the KD and HS rods and can be used to avoid the risk of overloading a KD sucker rod or using a failure-prone HS rod in corrosive and deviated environments.

For more than a year, 13 of these rod strings have been used in the Permian Basin by six different companies. Pumping cycles range from 2.8 to 4.7 million in well depths from 6,450 ft to 11,150 ft; the average depth is greater than 9,000 ft. Production ranges from 40 to 256 bpd. The existing wells were experiencing unacceptable performance with high-strength, D-grade or mixed fiberglass-steel rod strings. Each of the operating companies has experienced marked improvement in rod string performance.

Continuous sucker rod service. Weatherford International has two innovative technologies to service continuous sucker rods.

The service system offered by Weatherford’s continuous sucker rod “Corod team” is known as a Flushby. It is a compact truck-mounted well servicing system equipped with a well servicing triplex pump, a large fluid-carrying tank and a mast with drawworks (typically 50,000−65,000 lb pulling capacity). The highly mobile service system is designed to quickly diagnose well problems, complete the service work, and quickly get the well online.

The truck/system is fully equipped (including rod tongs and BOP) and virtually self-sufficient to perform many kinds of service work, such as killing, circulating or flushing sanded wells; servicing sucker rods including pump changes and fishing parted rods; changing broken polished rods; repairing stuffing box packing; changing out PCP drives; and working with Weatherford’s Mobile Gripper to perform all continuous sucker-rod service work. The gripper tool was designed specifically to work with any hoisting service equipment to pull or run in continuous sucker rod, Fig. 3. It’s an efficient method to quickly get a well up and running and an industry first.

Fig. 3. Weatherford’s Mobile Gripper.

The new tool was developed with input from major producers. The efficient prototype was built with virtually no major changes required after field trials. Commercial operation began with deployment into North and South America and the introduction of new models capable of various pull capacities. Additional new models are in the design stage. The entire system can be rigged in or out in less than 30 min. and runs continuous sucker rod in or out of the well at speeds exceeding 100 ft per min.

Weatherford also offers an innovative industry first, the Flushby Injector, which is similarly to the Flushby but also has a permanently mounted continuous sucker -rod injector that can be used when required or stowed away when it is not.

Cable pump. Vann Pumping Systems Inc. of Tyler, Texas, offers a new cable-operated pumping system as a cost-effective method for pumping mature oil wells and dewatering gas wells. Cable pumping is an alternative to the conventional rod and pump jack method, substituting cable for the rods to convey the up-and downstroke of the downhole pump. An electronically and hydraulically operated system replaces the pumping unit. The primary objective of cable pumping is to reduce lifting maintenance and workover costs.

The tower pumping unit is a computerized hydraulic lifting system that can be installed on any well that uses a downhole reciprocating pump, Fig. 4. The size of the unit and the length of stroke can vary with the depth of the well. Longer strokes are possible as compared to many conventional pumping systems. Strokes per minute can be regulated to match production coming into the well.

Fig. 4. Vann’s cable-operated pumping system employs a computerized hydraulic lifting system and does not require a workover unit.

Using a cable-operated pump should reduce overall total lifting cost. No workover unit is needed to run or retrieve the downhole pump. The system can be pulled by a special cable truck for any necessary repairs. The equipment is designed to operate safely with no exposed moving parts on the surface equipment. The pumping system is environmentally friendly because of the much smaller footprint and clean wellsite.

The Vann pumping system has been under development and testing for about six years, including three years of field tests in Texas, New Mexico and Mexico.

PROGRESSIVE CAVITY PUMPS

Three innovations in PCPs follow, including a new elstomer.

Pumping heavy oil with a PCP. In the past, traditional PCP geometries have shown limitations when handling extremely viscous fluids and high sand cuts. Pressure losses at the pump intake and within the pump have been determined as factors impairing the filling of the first cavity of the pump, thereby reducing pumping efficiency and potentially resulting in shorter run life. Weatherford has developed a series of pump geometries for heavy oil, called Fat-boy. These pump models feature an increased pump cavity cross-sectional area, a more aggressive rotor pitch angle and a decreased pitch length, resulting in a higher volumetric efficiency due to increased cavity fillup and improved movement of heavy oil, sand and large particles like pyrite or debris. It also reduces viscous frictional torque.

Figure 5 shows a comparison between a conventional Model 7 (7 m³/d/100 rpm) and a Fat-boy Model 8 (8 m³/d/100 rpm). Using these pumps in CHOPS (Cold Heavy Oil Production with Sand) wells in Canada has allowed the reduction of 35–85% in the number of loads per year.

Fig. 5. On the left is a conventional PCP applicable for most oils and water. Right is the new Fat-boy pump with a similar displacement, but with shorter pitch and larger diameter. Combined with a larger intake area, fluid moves with lower friction velocitys to help deal with increased from heavy oils, especially with sand.

Progressing cavity pump elastomer. A new elastomer developed by Weatherford for PCP pumps, called Hi-Per, improves operations in applications with higher levels of aromatics and gases. PCP use has been limited in lighter oil wells with high gas content due to elastomer swelling and explosive decompression. The new elastomer is specifically designed to operate effectively in these types of applications.

In lab testing with fluids containing high levels of aromatics, the new elastomer significantly outperformed conventional nitriles. Testing with gas under explosive decompression conditions confirmed that the swelling and severe blistering seen in conventional elastomers was absent, Table 1. Field tests in about 40 wells with a variety of aggressive conditions have shown lower torques and extended run times compared to previous history. The new elastomer can be placed in most Weatherford PCPs.

High-temperature PCP line. Moyno HTD is a series of high-temperature PCPs. The HTD300 and the HTD650 are models that are designed to operate in the 300°F and 650°F range, respectively. The elastomer is retained in the tube, mechanically removing the need for a bonding agent within the design, Fig. 6. The Moyno HTD300 is not restricted by bonding agent temperature limits and offers new and improved elastomer compounds with improved chemical resistance and tensile/mechanical properties. The Moyno HTD300 does not have to be removed from a well when steam injection is required to stimulate production.

The Moyno utilizes metal stator technology allowing the pump to operate in temperatures up to 650°F. The Moyno HTD650 design does not contain any elastomer and utilizes closely controlled rotor/stator clearances for successful operation. The Moyno HTD650 is ideally suited for SAGD and cyclic steam applications.

RF SCALE INHIBITION

Weatherford International introduced a Radio Frequency (RF) device called ClearWELL that clamps to the surface of a well, Fig. 7. The company says that it treats the entire wellbore and annulus for scale and paraffin. Unlike chemicals, it does not inhibit formation but causes crystallization to occur in suspension rather than on the walls of the pipe. Any scale that forms is carried away with the produced fluids. To date, the system has been used successfully with all forms of artificial lift. It controls most scales including the most common scales such as calcium carbonate and barium sulfate.

Fig. 6. Schematic of the Moyno HTD high-temperature PCP.

Fig. 7. Scale- and paraffin-inhibiting RF device shown on a rod pump well.

The system is particularly effective with ESPs because the signal can be delivered on the power cable to the motor and pump which are at the heart of the scale problem. It has also been shown to keep plunger lifts and reciprocating rods from sticking and free of scale or paraffin.

DOWNHOLE GAS SEPARATOR

Wood Group-ESP has developed a new line of high-capacity, high-efficiency gas separators. In applications with high Gas-Oil Ratios (GORs) and low bottomhole pressures, the well fluid may contain significant amounts of free gas, which can be detrimental to pump performance. In these applications, a gas separator, designed to separate free gas from the well fluid before it enters the pump, replaces the intake section.

In these high-gas fraction well environments, typical industry practice specifies the use of tandem-rotary or vortex-type separators. In this configuration, a flow bottleneck can occur at the tandem connection between separators. The new Multi-stage Abrasion Resistant Gas Separator (MAGS) eliminates this bottleneck by incorporating multiple separating chambers within a single housing. The number and length of separation chambers was optimized through a rigorous in-house testing program. The new separators (Fig. 8) have rated capacities of 8,000 bpd (400 series) and 16,000 bpd (538 series) and have been proven effective up to 95% free gas percentages. Successful field testing has been underway since Oct. 2007 in several oilfield and gas-well dewatering applications.

Fig. 8. The new MAGS gas separator, designed to separate free gas before it enters the pump, has been undergoing field testing for the past two years.

A smarter plunger. Knowledge of the conditions in the well allows the operator to make the best production decisions. Obtaining accurate downhole pressure and temperature data is essential to understanding what is happening in the wellbore and reservoir. Only with this knowledge can the proper modifications and adjustments be confidently—and successfully—made.

Production Control Services (PCS) developed the PCS Smart Plunger to address this need. The new plungers are data-logging tools that work with plunger-lift technology. Equipped with a memory pressure gauge, it is dropped downhole like a traditional plunger. Normal cyclic operation of the well returns the plunger to the surface. When the plunger is retrieved, the sensor/logger is removed and connected to a computer. The time vs. pressure and temperature data is transmitted and displayed for the well operator.

The new data-logging plungers (Fig. 9) record travel velocities both up and down the hole, variances and points of contact with liquids, and temperature changes to gas and liquid. This data can be used to minimize downtime based on bottomhole build-up information.

Fig. 9. New line of memory data-logging plungers.

Anomalies encountered in the pressure and temperature scales are recorded inside the plunger-encased data logger at a rate of up to one sample per second. The new plungers enable wells to be logged for over eight days of continuous plunger travel. It can work in conditions of up to 300°F and 10,000 psi, and with the multi-sample rate option configured, samples can be obtained in 15 different rates. For example, a test procedure may require samples every 10 sec. for 1 hr, followed by every minute for 30 days, depending on the requirements and need.

While the data provided by the new plunger has proved to be an invaluable tool in the evaluation and optimization of wells with plunger lift, its usefulness has not been limited to that market. A stationary version has been developed that can deliver a data logger downhole, then later retrieve it using special delivery and pickup plungers. Wireline units are no longer required to run flowing bottomhole surveys. The new plunger equipment can perform the same function at a fraction of the cost with minimal human intervention or equipment.

The new plunger can perform additional valuable diagnostic tests, including:

• Pressure surveys: a staple test, providing reservoir engineers with critical data for reservoir analysis
• Leak detection: tubing leaks have been discovered within feet of the tubular hole with a special temperature-only data logger that samples at three times per second
• Plunger lift performance: successfully used to troubleshoot wells where the plunger is sporadic or not running properly
• Surface four-point isochronal test: IPR curves can be established by changing backpressure on a flowing well
• Drawdown testing: a stationary data logger is delivered to multiple field points at the well to ratify field compression usage and effects
• Skin damage analysis.

Other potential applications include acid jobs, re-fracs and other workover situations.

GAS LIFT

Three companies have recently announced new gas lift technologies.

The Enhanced Annular Velocity (EAV) method of gas lift uses tubing and gas-lift valves above a packer, and a selectively sized injection string with internally mounted gas-lift valves below. Injected gas flows into the casing annulus through a crossover flow adapter at the packer and into the injection string below. When the deepest point of injection is obtained, the gas exits the injection string, mixes with the produced gas and fluids and flows up the annular area. The fluid and gas flows through the crossover flow adapter and into the production tubing to the surface, Fig. 10. Success of this system is dependent on the proper sizing of the tubing and injection string, ensuring adequate flow velocity can be maintained through the entire length of the well.

Fig. 10. Injection gas flows from the tubing annulus and into the the casing annulus via a crossover, and is injected into the produced liquids which are then gas-lifted up the tubing.

Annular gas lift. Marathon Oil Corp. and partners have developed a new, below-packer, annular gas-lift deliquification method for gas wells, Fig. 11. The Annular Enhanced Velocity (AEV) system uses wireline retrievable equipment in wells with completion intervals that are several thousand feet long.

Fig. 11. Marathon’s annular gas lift system includes mandrels and valves run below the packer and a proprietary crossover assembly.

This gas-lift system is unique in that standard annular flow side-pocket mandrels and wireline-retrievable gas lift valves are run below the packer. Wireline access to the wellbore below the packer is maintained by using a proprietary crossover assembly, which is designed to minimize flow restrictions and reduce undesirable backpressure on the producing formation. Since wireline access is maintained, memory gauges can be run below the packer to obtain pressure and temperature data.

In addition, the cross-sectional flow area of the annulus can be reduced to increase the flow velocity and enhance the deliquification potential of the system by running larger tubulars below the packer.

Systems are available in the US and Canada to run in 4½-in. and larger casing sizes, through Production Control Services (PCS), headquartered in Frederick, Colorado.

Packerless dead string. This application can be used to prevent liquid loading in wells with long perforated intervals or horizontal laterals to ensure stable production and the lowest possible flowing BHP. The installation consists of production tubing and gas lift valves above a slotted crossover flow sub and a dead string below. With a properly sized dead string, the produced fluid and gas will flow with adequate velocity in the annular area through the slotted sub and into the production tubing. A traditional gas-lift operation then occurs and delivers all liquids and gas to the surface, Fig. 12.

Fig. 12. A properly sized dead string causes produced fluid and gas to flow with adequate velocity in the annular area. Fluids enter through a slotted sub into the production tubing.

Dip tube assembly. This method of deep lift utilizes a crossover flow adapter and a unique mini-wellbore below the packer. This assembly facilitates the deepest point of gas injection without applying additional backpressure on the formation. A typical installation might have 2 3⁄8-in. tubing above the packer, a crossover flow adapter with 2 7⁄8-in. tail pipe below the packer, and a 1-in. internal injection string inside the tail pipe, Fig. 13. Compressed gas travels through the casing annulus, through the crossover flow adapter and into the 1-in. injection string. The gas then exits a gas lift valve and mixes with the produced fluid and gas in the 2 7⁄8-in. x 1-in. annulus. The fluid and gas flow up through the crossover flow adapter into the 2 3⁄8-in. production tubing and to the surface. Able to accommodate most wellbore characteristics, the Dip Tube Assembly is an efficient means of lowering the flowing bottomhole pressure beyond what is capable with conventional gas lift methods.

Fig. 13. Injection gas travels down the tubing annulus and crosses over into a narrow ID string in the long tail pipe, where it is injected at the end. Gas-lifted fluids cross over at the packer into the tubing.

Pressure-actuated chamber technology (PACT). Nojak Pumping Solutions, based in Alexandria, Indiana (formerly called Airlift Services), has developed its new Nojak Pumping System. The system uses gas pressure to lift fluid through a series of fluid chambers deployed directly into the well casing, and is designed for shallow wells (<3,000 ft) that typically produce less than 100 bpd of liquids. It can be used for lifting oil or for deliquifying gas wells and has been installed in 19 wells to date. The system consists of two main components: pressure-actuated chambers and a surface control system.

The downhole pumping system consists of a series of pressure-actuated chambers connected by line assemblies. The chambers are spaced at about 250-ft intervals in the well. The fluid chambers are connected together and supported by the poly tubing line assemblies. For additional support, a stainless steel cable is connected to each fluid chamber. The control system includes a compressor and a microprocessor-controlled valve system to direct fluid flow through the chambers. Compressed gas on the surface is used to apply pressure to the chambers to lift fluid from one chamber to the next.

The operation of the pump chamber employs check balls and a float to direct fluid flow. After the fluid chamber is filled with fluid, gas pressure is applied from the compressor on the surface. The pressure that is applied to the fluid causes a check ball at the bottom of the chamber to seat. The fluid is then directed to flow past another check ball and through a product line inside the chamber. When the fluid reaches the top of the chamber it flows through the line assembly to the next higher fluid chamber. The float is placed inside the chamber and floats up and down with the fluid level. When the fluid reaches the bottom of the chamber the float seals the flow and does not allow the gas to enter into the fluid product flow. During the fill portion of the cycle the float will contact another seal when the fluid reaches the top of the chamber. The float seal keeps the fluid from entering the gas lines, Fig. 14.

Fig. 14. Liquids are lifted across several chambers, each of which comprises a floating piston in a gas-displacement chamber which feeds a traveling/check ball arrangement that pushes liquids to the next level. One gas line goes to even-numbered lifts, the other to odd-numbered.

All of the fluid chambers operate using the same principle. After each chamber is filled with fluid, the compressed gas from the surface forces the fluid to the next higher chamber. The continuous pumping system operation functions by applying gas pressure to alternate chambers. As the gas pressure is increased in the even chambers, the fluid is forced to the odd chambers. Subsequently, when the gas pressure is increased in the odd chambers, the fluid flows to the even chambers. With each full pressure cycle a chamber volume of fluid is delivered to the surface.

The control system for the pump is on the surface. This control system includes the compressor and a microprocessor-controlled valve bank. The function of the valves is to connect alternating chambers to a pressure source or an exhaust source. The microprocessor has the ability to vary the pressure cycle times and also function as an on/off timer. The system can be set to operate at long cycle times for low fluid output or run for just a couple of hours a day.

The PACT system is an improvement over conventional methods because it has no steel rods or tubing and requires no pulling unit to install; requires no reservoir energy to operate the pump and pump components are not damaged by pumping dry; and operates at low pressure (150 psi) with no moving parts on surface.

High-pressure gas lift. Schlumberger’s XLift high-pressure gas-lift system has been available since 2005 and has a field-proven record for reliability in deepwater and subsea artificial lift. It is included here because XLift systems have recently undergone some extreme high-volume, liquid unloading verification testing that increases the capability for more rapid well unloading.

The system includes a fit-for-purpose injection-pressure operated (IPO) gas-lift valve and a high-performance orifice valve that are both designed to be loaded in a system-specific side pocket gas-lift mandrel. This unique mandrel design allows for a variety of customized cable bypass options to complement complex completion design without compromising the required wellbore geometry. The valves and mandrels also include many performance tested design features that allow for an extended operating envelope for the injection pressure operated valve, an optimized and stable injection gas flow path and a robust, reliable, positive-sealing, metal-to-metal check valve system that ensures tubing to annulus pressure integrity during all phases of operation.

The system has significantly improved reliability and efficiency compared to existing traditional gas-lift systems. These improvements and ongoing reliability testing ensure that the system will operate trouble-free in deep water and subsea, high-pressure, gas-lift applications.  

DISCLAIMER

The authors thank the featured companies for providing information for this article. The authors are not responsible for claims made by the manufacturers and vendors about their products capabilities.

THE AUTHOR
	James F. Lea teaches industry courses in artificial lift and production for Petroskills. He holds BS and MS degrees in mechanical engineering from the University of Arkansas and a PhD in mechanical engineering from Southern Methodist University. He worked for Sun Oil Co. as a research engineer from 1970 to 1975, taught at the University of Arkansas from 1975 to 1978; was team leader of production optimization and artificial lift at Amoco EPTG from 1979 to 1999 and was chairman of Texas Tech University’s petroleum engineering department from 1999 to 2006.
	Herald W. Winkler is former chairman of and now a professor emeritus and research associate in TexasTech University’s petroleum engineering department in Lubbock, Texas. He works as a consultant in artificial lift, specializing in gas lift.