What’s new in artificial lift?
Continuing last month’s “What’s new in artificial lift?” discussion, we report on a dozen items that we hope you find useful.
ESP DEVELOPMENTS
In recent years, ESPs have been the fastest-growing form of artificial lift, partially due to their ability to operate across a broad range of flowrates and depths.
Slimline ESP improves production and system reliability in small-diameter wells. Unconventional resource operators often opt to drill smaller-diameter wells or install heavier wall casing to lower drilling costs, optimize the completion design, increase the collapse pressure, or improve wellbore stability. While all of these factors can have a positive economic and technical impact, the resulting well can pose challenges during the production phase.
Unconventional wells have rapidly declining production rates and high levels of gas and solids entrained in the fluid stream. Smaller wellbores limit artificial lift options that can handle these issues. Thus, operators often sacrifice production and ultimate recovery.
The CENesis slimline ESP system from Baker Hughes overcomes both the limitations of small-diameter wells and the production challenges unique to unconventional plays. The system delivers better production rates and reserves recovery, while improving system reliability for greater uptime and fewer interventions.
With a flow range of 50 bpd to 3,100 bpd, the system allows operators to eliminate costly artificial lift change-outs as production declines. The company also has introduced a gas handling-specific pump (Fig. 1), which greatly increases system capability in high gas/oil ratio (GOR) wells. The system can be encapsulated with the company’s PHASE system for natural separation of the gas to prevent pump-off conditions, and fluid recirculation past the motor to prevent overheating.
In addition to the new pump, the system includes an optimized motor design to improve reliability in smaller casing sizes. The motor magnet-wire insulation has been upgraded to provide 30% greater mechanical and electrical strength. A redesigned motor head reduces the motor’s OD. The angle of the pothead (reduced from 13° to 10°) provides greater protection for the system during installation.
The pump’s 5,800-psi pressure rating allows the system to sit deeper in the well to draw down reservoir pressure and improve ultimate recovery. The pump design also improves system reliability. Wider vane openings in the mixed-flow stage improve natural gas and solids handling through the pump, preventing plugging. Carbide bearings reduce downthrust wear as the production rate decreases. This also minimizes the impact of vibration, when solids are present in the production stream.
Natural gas entrained in the fluid stream is nearly always an issue for unconventional wells. An effective method of separating gas, before it enters the pump, was an important consideration in the new slimline ESP system design. A fit-for-purpose vortex gas separator (a less torturous flow path) not only improves gas separation, but also handles solids more effectively than traditional rotary gas separators.
In a recent well in the Wasatch formation of Utah, using a slimline ESP system enabled an 80% deeper pump setting and an estimated 150% higher production than using a conventional ESP.
Extending ESP run life. Summit ESP has become one of the largest ESP providers in the U.S., largely on the basis of the performance of its ESP systems. Key to the system is an advancing motor technology. Summit’s newest 3.75-in. OD series motor reportedly has the industry’s highest horsepower per unit of length. Short component lengths are critical to installing ESPs in deviated wells.
The temperature rise in these new motors is extremely low, due to high-efficiency windings. As with most systems, run life equates to lower operating temperatures.
Another important feature that improves system run life is the rotor bearing design, which incorporates a novel method of preventing bearing spin. The new Summit motor design can be rated upwards or downwards, as needed, depending on well conditions and economics.
Summit has implemented a holistic approach to production systems to ensure continuous run life improvement. Key points include ESP design, operation, monitoring, optimization, root cause failure analysis, and incorporating lessons learned, Fig. 2. These are all interconnected and represent a progression, or sequence, of the run life extension process. There is a strong focus on any abnormal job that may have a negative impact. These incidents are tracked in an appropriate manner, so that both Summit and operator personnel have visibility on issues. This system drives continuous improvement, and ensures that incidents are not repeated and advanced design changes are implemented.
New developments from Borets. In October 2015, Borets released its AXIOM II variable speed drive (VSD), Fig. 3. This is a universal VSD, ideally suited for operating ESP induction motors, permanent magnet motors (PMM) and high-speed PMMs.
Borets installed the new VSD on what would normally have been conventional ESP wells, using their unique PMM-PCP (progressive cavity pump) system. This new drive and PMM forms the platform for many new technologies, both released and being developed.
In February 2016, Borets released a high-speed wear-resistant/wide-range (WR2) system, which includes a high-speed pump, a PMM and a monitoring package designed for unconventional wells inclusive of frac sand flowback, gassy production and rapid decline rates. The WR2 pump is designed for flowrates of 250 to 1,000 bpd and 560 to 1,900 bpd. Borets’ pump manufacturing process results in a stage with improved surface hardness that delivers greater run life in sand environments. The WR2 system is a complete lifting solution, built in combination with a PMM. The system can achieve maximum production with no workover expense in the early decline stages of a new well.
Borets also launched a SAGD solution, specifically designed for viscous applications requiring steam-assisted gravity drainage and other thermal recovery methods. The SAGD solution features thermally compensated compression pumps and gas handling devices with redesigned abrasion-resistant bearings, as well as best-in-class high-temperature materials rated up to 482°F (250°C), to ensure extended ESP run-life in harsh environments. This design includes a new seal with improved, thrust bearing design, unique metal bellows expansion chambers and plugs. New pothead designs also have been developed to eliminate a common point of failure. The SAGD solution was designed to improve the mean time between failure of ESP systems in challenging applications.
The company’s latest product launch is its newly developed 4.06-in. high-speed PMM, targeting smaller casing size applications. The system incorporates a single-section, 228-hp PMM that can be deployed through 5.5-in. casing. The one-section design reduces installation time and complexity, and allows less drag and bending in deviated wells. According to the manufacturer, the design improves power expenditure by an average 15%.
Protecting ESPs from sand fallback. ESPs commonly suffer from severe erosion and radial wear caused by frac sand and other residual solids. Many ESP manufacturers have technologies that cope with sand passing through the pump. However, when the ESP shuts down from power failure, pump-off, production shutdowns, etc., previously pumped sand can fall back onto the top stages of the ESP. Restarting a sand-plugged pump will cause catastrophic damage.
Multilift Welltec, LLC, has introduced SandGuard, a unique technology that addresses sand fallback. The tool is installed in the tubing string, just above the ESP pump discharge. It will capture fallback sand and segregate it away from the pump. It diverts solids-laden fluid to an inner chamber that, in turn, allows the fluid to drain back through the pump, while capturing sand and solids in the chamber.
When the pump is restarted, these captured sands and solids are expelled from the chamber by the flow action of the pumped fluid and then carried to surface. The system can be cycled endlessly, eliminating potential damage to the pump at every shutdown. SandGuard automatically flushes itself empty after every restart. There are no ports to the annulus.
Special-purpose ESP conveyance system. AccessESP, a provider of rigless ESP conveyance systems, supplies operators with artificial lift solutions designed to greatly reduce intervention costs, minimize lost production, and provide fullbore access to the reservoir.
The company installed the first rigless, ESP conveyance system offshore Nigeria. The AccessESP 190-hp system was deployed through 4.5-in. tubing on conventional 0.125-in. slickline, to a depth of 5,900 ft and took less than 15 hr to install. Additionally, the company performed a successful through-tubing, rigless replacement in January 2015, replacing the 190-hp system with its fourth-generation Access375 250-hp system, which was introduced initially in October 2014.
The Access375 rigless conveyance system incorporates a single-section PMM that is one-fifth the length and weight of a conventional induction motor. This one-piece design eliminates the need for tandem and triple motors, greatly reducing system complexity, resulting in higher reliability and easier installation.
Access375 is built and qualified for challenging, offshore and remote locations. Benefits of this technology include fullbore access to the reservoir; and compatibility with all major ESP providers’ equipment, including variable speed drives (VSDs) and pumps. Additionally, live-well ESP installation and removal using conventional slickline, coiled tubing or a wireline tractor, helps maximize production uptime with reduced costs, time and complexity for ESP intervention.
In August and October 2015, respectively, the first and second commercial installations of the Access375, annular flow, permanent completion, with a 130-hp retrievable assembly, were installed on Alaska’s North Slope. The installations were flawless with no lost time, saving numerous hours of deployment time when compared to traditional ESP systems.
ESP alternative for harsh environments. When an oil and gas well has a high volume of sand, high volumes of gas or heavy oil, an ESP might not be the best alternative. The tortuous flow-path created by the pump stages can facilitate early failure, due to system wear and vibration. Elite Multiphase Solutions, LLC, has released a technical pump solution designed to produce in harsh well environments, where conventional ESP multi-stage centrifugal pumps are plagued by short run lives.
In contrast to conventional ESPs, the company’s V-Pump is a helical axial design that has no tortuous pathways, Fig. 4. The design provides smooth fluid transmission through the pump, eliminating areas of erosion or internal pressure drops that would facilitate the drop-out of solids. The elimination of internal pressure drops minimizes issues common in conventional ESP’s (i.e., scale build-up, metal-to-metal contact, and low-pressure spaces that promote pump plugging during lower flow conditions).
The V-Pump is designed to handle solids, gas and heavy oil, thus improving the run life of the entire ESP assembly. It can produce in a range of 300 bpd to 3,500 bpd of fluid for 5.5-in. casing, and 900 bpd to 6,000 bpd for 7-in. casing and larger. With test data exceeding 50,000 parts per million, it can handle high volumes of sand without any wear and without the need for a sand filter. Additionally, the V-Pump can handle high volumes of gas without the added expense of a gas separator. It has successfully handled heavy oil, up to 13,500 centipoise, with the motor immediately realizing stabile cooling. It has no metal-to-metal contact between the rotor and stator (pump stage). Hence, it can operate in a wide range of wells that experience rapid depletion rates. The design facilitates direct bolting to conventional ESP seal sections or protectors for easy installation.
The V-Pump technology offers an alternative solution for both operators and ESP OEM’s for pumping difficult wells and reducing well interventions.
PCP DEVELOPMENTS
Progessive (or progressing) cavity pump (PCP) systems have emerged gradually as a common form of artificial lift. The two key features that differentiate PCP systems from other forms of artificial lift are the design of the downhole pumps and the associated surface drive systems.
New drive heads for PCPs. PCM has introduced two new drive heads, called PCM Driver, for progessive cavity pumps, Fig. 5. Designed with the latest engineering technology to ensure a long running life, PCM Driver B-50 and B-100 comply with ISO 15136-2-Surface Drive System and Directive Machinery 2006/42/CE requirements. The drive heads were designed for ease of operation and maximum safety.
Both drive heads incorporate an innovative belt guard technology, with a lightweight sliding cover that requires only one operator to open or remove the belt guard. The belt guards are made of a light fiberglass-reinforced composite material that provides strong impact resistance and superior fire inhibition.
All PCP rotating parts are fully protected by the cover to ensure maximum safety to personnel. The hydraulic brake circuit embedded inside the drive head body is well protected against external damage with sensitive parts fully protected.
Besides the built-in safety features, an important advantage is a simplified way to expedite drive head mounting. For faster motor assembly, PCM Driver drive heads are delivered with a lightweight stand that enables quick connection to lifting slings. All drive head models can be flanged and mounted to two sizes of polish rods.
GAS LIFT DEVELOPMENTS
Gas lift involves injecting gas through a well’s tubing-casing annulus. Injected gas aerates the fluid to reduce its density; the formation pressure is then able to lift the fluid column and force it up the wellbore. Depending on the well’s producing characteristics, and the specific characteristics of the gas-lift equipment, gas may be injected continuously or intermittently.
Gas lift system for deepwater applications. Weatherford’s UltraLift deepwater gas lift system combines a new, API V-1 validated gas lift valve with proven components from the company’s DVX line.
The UltraLift RH-2XHP gas lift valve injects gas deeper into the wellbore and maximizes production in deepwater wells with high-pressure injection systems. Featuring dual-edge welded bellows that improve high-pressure reliability, the valve has a total dome-charge capability of 5,000 psi and a maximum operating pressure differential of 10,000 psi.
The RH-2XHP valve incorporates an integral reverse-flow check valve to maximize flow and prevent the erosional effects of long operation and unloading. The check valve has undergone extensive testing, is certified to API 19G2 V-1 standards, and is qualified to the TR2385 Norwegian standard for North Sea operation. It is performance-rated to 10,000 psi differential pressure at 300°F.
Finally, the system uses a DVX side-pocket mandrel (Fig. 6) with dual external valves that help to prevent corrosive well fluids from entering the casing annulus. The mandrel design follows the industry-standard pocket configuration, so that operators may substitute any gas lift valves and latches with a 1-in. or 1.5-in. OD. For additional customization, grooves can be machined onto the side of the mandrel, to accommodate multiple control lines without increasing the mandrel OD.
One of the system’s advantages is the dual-injection-flow design. During normal gas lift operations, well fluids may flow back into the casing annulus, causing erosion. With several independent barriers—the internal check valve in the RH-2HXP valve, the two DVX QS check valves, and the dual external valves attached to the DVX mandrel—the system protects the casing annulus from well fluids, even when the gas lift valve is removed via wireline.
Overall, the system provides operators with a premium gas lift package that offers reliable operation and dual-barrier protection to enhance well integrity. It is well suited for deployment to depths up to 18,000 ft and can be combined with chemical injection systems, control lines and gauges.
POWER, AUTOMATION, CONTROL AND MONITORING
The costs to power artificial lift systems can be significant and can represent the highest cumulative cost of pumping a well. Since production downtime for any reason is very costly, artificial lift power, automation, control and monitoring systems have become increasingly important.
Growing demand for industrial UPS equipment. Power system demands in oil and gas applications are exceedingly diverse, and the requirement for a continuous source of power for critical production applications is often essential. Even more diverse is the range of environments in which the power system equipment needs to be installed and still operate reliably.
Many production installations demand backup power systems that not only provide highly conditioned power and battery backup, but also have been designed to perform in the most demanding environmental conditions. Falcon Electric refers to these systems as wide-temperature industrial Uninterruptible Power Supplies (UPS); or a double-conversion, online UPS on steroids. This type of rugged UPS is designed to operate over a very wide temperature range of –22°F to 149°F. Depending on the demands of the environment, they can be installed stand-alone, or inside NEMA-rated enclosures, Fig. 7. Operating environments may include locations having condensation problems, corrosive gas or elements, conductive particulate matter, or exceedingly harsh conditions like Alaska’s North Slope.
Many processes at a production site (i.e., artificial lift systems) are automated, dependent on process control via a Supervisory Communications Data Acquisition (SCADA) network. Programmable logic controllers (PLCs) and remote terminal units (RTUs) are distributed throughout a production site, adjacent to the specific process. These systems often require online, double-conversion power protection.
Large pumps and motors connected to the site’s power grid often create power sags and transients that adversely affect the operation of the PLCs and RTUs. The industrial UPS, with its online design, continuously regenerates new, clean power demanded by network peripherals, in addition to providing essential battery backup functions. Again, the required wide-temperature industrial UPS is installed in an industrial control panel and subjected to the local temperature extremes. However, the industrial UPS cannot be used in “class-rated” locations having explosive gasses present. For these locations, a higher-level UPS, with the proper certifications and support systems, must be used exclusively.
Middle Eastern oil company adds wireless instruments to wellheads. A major Middle East oil company wanted to add remote monitoring systems to hundreds of wellhead lift stations, to improve operations. Wired and wireless solutions were both considered, with wireless selected, due to lower costs, faster implementation, and reduced HSE risks.
For the first few decades in this field, the company relied on formation pressure to keep production flowing from its wells. But by late 2010, more and more wells required artificial lift systems, with the number of lift units increasing dramatically each year to just over 300.
Manual operation and monitoring of these lift units was tedious, time-consuming, and presented hazards to field personnel. Optimizing production was a challenge, due to insufficient instrumentation, and lags between data collection and subsequent data entry.
Real-time automation was first introduced as a solution in 2012. The company started with a few wells to demonstrate value. A typical wellhead with an artificial lift unit requires the following instrumentation, data gathering and control components:
- Wellhead/flowline/casing pressure and temperature
- H2S and CH4 gas detection
- RTU/PLC for local monitoring and control
- Remote shutdown
- Interface to downhole gauges
- Tank level measurement.
Early implementations indicated that the average time needed to install the necessary wired instrumentation was one to two weeks per lift station, much too long given the hundreds of wells requiring upgrades. There were also operational constraints with wired instrument installation, including required excavation procedures and costs, and HSE risks.
These issues led the company to install Emerson’s WirelessHART instruments and related components. All the instruments at each lift station are connected to an Emerson Wireless Gateway, and the gateway is connected back to the central control room (Fig. 8) via Wi-Fi and WiMAX networks. An Emerson ControlWave Micro Hybrid RTU/PLC is installed at each site to provide local monitoring and control. This unit is also networked back to the central control room via the gateway. This is in contrast to a traditional wired installation, where each instrument requires power wiring, and signal wiring must be run from each instrument to an RTU gateway.
By eliminating most of the required wiring and corresponding infrastructure, installation time was reduced from one week per wellhead to one day for two wells, a ten-fold improvement. Installation costs were cut in half, saving $3,000 per well. HSE risks also were reduced, as much less excavation and wiring work are required in these potentially hazardous areas. Data accuracy is in the range of 99.9%, more than sufficient for the application. Data availability is also high.
Live video monitoring of artificial lift wells. Producers who employ artificial lift recovery systems in remote, unmanned locations must ensure that the video surveillance of these sites is capable of providing a complete view of the operation, while ensuring operational and environmental safety. SPIRIT Global Energy Solutions, a member of the Dover Artificial Lift group of companies, has developed the innovative GENESIS Go Live feature, which is the industry’s first real-time, high-resolution video management system for pump-off control in artificial lift operations.
Designed to be viewed on a computer, laptop, tablet or handheld device, Go Live allows the user to observe anytime, anywhere, the production site’s well dynamics via high-resolution streaming video, night vision, motion detection and pan-tilt-zoom camera functionality. The Go Live application serves the entire life cycle of video management.
Go Live’s real-time capabilities allow the producer to “operate by exception;” meaning that if any activity occurs on sensors, gauges or other field devices, a digital snapshot is taken and sent to the user. This enables a clearer understanding of what activities are taking place at the wellsite and leads to better decision-making, targeted responses and reduced maintenance. Also, environmental risks are mitigated, due to faster transmitted information that allows an immediate response to critical site alarms. The system also allows the user to view many sites simultaneously.
Go Live can be used in conjunction with SPIRIT’s GENESIS Intelligent Asset Manager (Fig. 9), which is the first automated plug-and-play wellsite management system that uses artificial intelligence to deliver maximum performance and optimized production from wells that feature artificial lift operations. The GENESIS Intelligent Asset Manager is a versatile, programmable, high-performance operating platform that is customizable to all unique artificial lift pumping environments, while also able to provide remote, real-time well-monitoring diagnostics and alerts.
Key features of the Intelligent Asset Manager include quick, easy and safe installation and configuration; 3D pump simulation and simple interpretation; real-time diagnostics and equipment loading (including rods, surface and pump dynagraph cards, simultaneous variable-speed drive and pump-off control, fluid-production calculation, safe and accurate laser-position measurement, a searchable 180-day stored operational history, and a web-based, user-friendly interface and menus).
The unit has an operational temperature range from –40°F to 158°F (–40°C to 70°C); a 10-in., full-color touchpad display; 120V, 240V and 480V input-power options; a NEMA 4X-rated sunlight-resistant enclosure; and a complete communications offering.
GE monitoring system. GE Oil & Gas has introduced a new remote monitoring system, Field Vantage. It is a fit-for-purpose solution to help modernize fields operated with or without SCADA capability. The system provides clarity, consistency, and a 360° view of all wells, offering real-time data and information in one format. As an integrated solution, it identifies which wells are up/down, how they are running, and when a failure might occur. New levels of production performance can be achieved with better visibility into the past, present and future of wells and fields.
This user-friendly monitoring system enhances equipment run life through data visualization and alarm management. Production equipment data visualizations are designed in collaboration with operators to ensure usability, simplicity and functionality. Well data are displayed in dials, charts, and customizable graphical screens.
Field Vantage immediately notifies the operator when a well goes down, and production is being lost. The system provides remote well start-up, well stop and operating frequency changes (where VSDs are present). Controller set points also can be adjusted remotely (e.g., over and under load set points), reducing response time and the number of trips to the well site.
Conventional analysis of one well may take one or more engineers hours, or days, to gather information, input data, and produce sensitivity studies. Field Vantage workflows streamline processes so that each engineer can improve his utilization rate to deliver operational improvements.
Field Vantage programmable read types enable real-time measured data (such as VSD power consumption) to be combined with derived analytical data (such as oil production rate) to create meaningful information that can be used to assess the return on resource (power) vs. produced output (oil). In wells where water is being produced with oil, power is “wasted” lifting water. A derived metric in Field Vantage, such as hp/bbl of oil, will help rank wells by return on operational costs.
The detailed pump operating curves in Field Vantage utilize self-validated nodal analysis to derive accurate pump flowrate, enabling the pumps to be operated accurately at the best efficiency point.
Failures in downhole equipment can happen with very short notice and can leave operators with longer-than-desired downtime to get equipment replacements, and the services needed to install them. Field Vantage provides advanced warnings of impending problems much earlier than equipment alarms, providing operators with time needed to plan workover logistics.
Editor’s note: It is with great sadness that we report our long-time friend and editorial contributor, Dr. Herald “Wink” Winkler, passed away as this issue went to press. Wink had contributed to this feature since 1987. He will be greatly missed. See his obituary here. 
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