Part II —Advances in subsea boosting, HT pumps and shale gas dewatering.
James F. Lea, PL Tech LLC; and Herald W. Winkler, Texas Tech University
In Part I published in the March 2010 issue, we covered recent developments in gas well dewatering, coiled tubing conveyance, hydraulic pumps and surface units. Part II presents advances in ESPs, PCPs, beam or rod pump systems and gaslift technology. First mentioned among these developments is the first installation of a subsea horizontal ESP boosting system that will take place by mid-2010 to support production in ultra-deep waters of the Gulf of Mexico. At the other end of the North American continent, new high-temperature PCP and ESP systems have been developed for Canada’s oil sands SAGD and CSS applications.
Advances in artificial lift monitoring include a web-accessible system that adds expert analysis to beam system status data. A new multiphase flowmeter is available that uses variable-speed drive and downhole sensor data and performs neural network computing to infer a real-time flowrate.
New gas lift offerings include a high-pressure gas lift valve and a system to add gas lift to the perforations of a gas well for dewatering. We also present a new plunger lift dewatering technique being used in high-pressure Haynesville shale wells.
Beam or rod pump system developments include a new rod pump, that provides deeper, heavier pumping with a dynamometer to monitor and change the production rate; a motor control panel that has an integrated rod pump controller, and a brush sand seal for bottom hold-down rod pumps. A “green” beam system compressor is available to minimize noise and greenhouse gas emissions.
SUBSEA ESP HORIZONTAL BOOSTING
Later this year, Baker Hughes Centrilift XP ESP systems will be installed in the first subsea horizontal ESP booster system in the ultra-deep waters of Gulf of Mexico, Fig. 1. Two ESPs will be used to maximize the needed pressure within the minimum length and weight footprint.
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Fig. 1. Baker Hughes has introduced the first subsea horizontal booster system for ultra-deep waters.
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The horizontal boosting system is a modular, self-contained ESP cartridge, consisting of a horizontal, open-framed structure to contain the two ESP systems, production tubing, electrical penetrator connections and fluid connections to tie into the subsea flowlines. Subsea power to the ESP system will be wet-mated using a remote-operated vehicle. The production tubing linking the two ESP systems is looped back and forth within the cartridge framework. The pumps are hydraulically in series, but not mechanically connected to each other. Rather than lying end-to-end, the ESPs are connected by hairpin turns in the production tubing. The side-by-side pump layout reduced pump cartridge length from 200 ft to about 90 ft.
The ESP systems include 17-stage mixed flow pumps for flowrates up to 20,000 bpd. The motor on the first ESP system in series will be monitored by a Baker Hughes Sureflo Harvest sensor pod. The pod will gather pump data such as intake pressure, intake temperature, motor winding temperature and vibration. The second ESP system in series will be identical to the first system with the exception that the second system will have two sensors, one at the bottom of the motor and one at the pump discharge. The bottom sensor acquires the same data set as the sensor pod in the first ESP, while the second sensor measures discharge pressure and temperature.
HIGH-TEMPERATURE DOWNHOLE PUMPS
R&M Energy and Baker Hughes have both introduced downhole pumps with high-temperature ratings for oil sands SAGD and CSS applications.
Moyno HTD-series PCP pumps. R&M Energy Systems has launched a new line of downhole pumps for high-temperature well conditions that had previously prevented operators from using downhole progressing cavity pumps (PCPs), Fig. 2. The Moyno HTD350 pump employs an elastomeric stator that is mechanically secured to the stator tube for greater temperature and chemical resistance. A patented design secures the elastomer without using any bonding agent, eliminating the risk of adhesive failure when operating in high-temperature well conditions. The pumps are capable of steam injection applications without having to remove the stator from the well. Three different models are available for 4,000-ft, 5,400-ft and 6,000-ft lift at 100 rpm. The HTD660 pump features proprietary metal-to-metal rotor/stator technology that eliminates the elastomeric stator altogether, allowing the PCP to handle downhole temperatures to 660°F. As a result, the pump can handle hot oil encountered during SAGD and CSS thermal recovery methods. The pump is capable of 2,200-ft lift at 100 rpm to produce up to 1,300 bfd.
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Fig. 2. The Moyno PCP has high-temperature rating for SAGD and CSS applications.
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Centrilift XP ESP. Baker Hughes will begin SAGD field trials later this quarter of the first Centrilift XP ESP designed to operate up to 482°F. Currently, most SAGD operators maintain bottomhole temperatures of less than 392°F due to ESP equipment limitations. To upgrade an ESP system from high to extreme temperature ranges, Baker Hughes minimized elastomers, maximized the bearing temperature range, increased motor oil thermal and mechanical growth allowances and enhanced the system’s electrical integrity.
For every 50°F increase in the operating temperature, the insulation life is halved. Therefore, the electrical insulation rating had to be increased. This ESP system was tested successfully in a hot loop capable of handling fluid temperatures up to 572°F in a horizontal orientation to mimic horizontal SAGD production wells.
WEB-BASED STATUS AND ANALYSIS
Web-based remote access to wells has filled the need for operators to receive the basic status of their wells. Weatherford’s Lift Advisor service has augmented this status information with artificial lift analysis to help the operator staff become more proactive. The service supplies operators with hourly web-based well status, detailed weekly and monthly reports and evaluation from an experienced analyst with recommendations for well operation improvements, Fig. 3. The service includes controller tuning, which is performed when first deployed. The wells are remotely tuned so that optimal rod pump settings are achieved for pump-off set points, inferred production, base runtime and idle time.
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Fig. 3. Weatherford’s web-based Lift Advisor service adds expert analysis to artificial lift well status data.
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Reports include current well status reports that display current alarms, along with yesterday and today’s runtimes, number of cycles and inferred production results. This information is updated every hour and can be accessed via the Internet. Each morning, the “well snapshot report” gives a quick snapshot of how the well is performing. This report includes surface and downhole dynamometer cards, current rod pump controller (RPC) set points, cycle times and the last seven days of runtime compared to normal operation. The Monthly Report contains the runtime, the number of cycles and inferred production for each individual day of the previous month. This allows trending, manipulating and archiving of the monthly data. For rod pumping, this includes downhole cards, current surface and downhole components, current operating parameters and an economic analysis of energy usage. As another option, a well analyst can be assigned to specific wells.
GAS LIFT VALVE WITH SAFETY SEAL
Schlumberger has improved the safety performance of its XLift high-pressure gaslift system with the development of a family of valves qualified to serve as a safe pressure barrier, Fig. 4. The valves have passed Statoil’s Requirements to Well Completions Equipment tests. With a choice of four different application-specific valves, the XLift system delivers high-volume injected gas to lift oil while providing a safer pressure barrier between the cased-hole annulus and production tubing. The system also employs a reverse flow check valve that reduces the risk of hydrocarbon migration to the wellbore annulus and works in harmony with the production packer and the subsurface safety valve to form a primary well control barrier. The XLift system can also maintain a safety seal during well shut-in periods. The system’s flow check has a working pressure of 10,000 psi and a 350°F temperature rating. The gas lift system can be deployed in a side pocket mandrel during the initial completion stages of a well or by slickline.
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Fig. 4. The Schlumberger gas lift valve is capable of acting as a safety barrier.
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MULTIPHASE FLOWMETER
Despite the advantages real-time flow measurements can bring to a field produced via ESP systems, multiphase flowmeters are rare. The available flowmeters are expensive, often more than $100,000, so operators typically rotate a multiphase flowmeter among a group of wells or an entire field, which limits effective data collection. Some turbine flowmeters can have up to 0.1% precision, but these flowmeters do not work well with a mix of liquid and free gas.
Baker Hughes has introduced an affordable Centrilift Neuraflow multiphase flowmeter, which uses downhole sensing technology and neural network capabilities to compute a real-time flowrate. The device takes input from a variable-speed drive and downhole/surface sensors, including pump intake pressure, pump discharge pressure, tubing pressure, and drive frequency, to infer a flowrate based on known reservoir and fluid properties. The multiphase flowmeter has demonstrated accuracies better than 90% when properly calibrated.
GAS WELL DEWATERING ADVANCES
Dewatering technologies are available, one to dewater gas wells with long perforated intervals at low bottomhole pressure and news of the use of existing equipment in a new environment to handle high-pressure gas common to the Haynesville shale wells.
Dewatering long perforated intervals. Altec has developed a Gas Optimization (Go) system to reduce fluid buildup in wells with long perforated intervals, low bottomhole pressure, or low production capability. The system utilizes the energy of the well to remove fluid buildup in a manner that is free from surface control, Fig. 5. Carrier subs with internally loaded pressure regulation are regularly spaced below the production packer, along the tail pipe portion of the production tubing string and along the perforated intervals of the well.
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Fig. 5. The Altec Go system reduces fluid buildup in long perforated intervals.
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During production, both formation gas and liquid will eventually build below the packer, in the annulus between the tail pipe and the production casing. As this trapped gas and liquid accumulates, the gas will rise above the liquid, slowly building pressure before pushing its way down toward the pressure regulator contained inside the carrier sub. The carrier sub allows direct communication between the trapped gas pressure and the internal pressure regulator. As the gas passes into the pressure regulator, the regulator will then direct the gas into the production tubing string, causing the production fluids inside the tubing to lighten, the tubing pressure at depth to decrease, and thereby easing gas flow in the well. This will, in turn, initiate the process of removing liquid buildup beneath the packer and across the perforated zones of a well. Depending upon the length of the perforated zones, additional subs can be spaced out along the tubing string allowing deeper points of gas injection and, consequently, more fluid buildup below the packer to be produced out of the wellbore. The deeper points of gas injection will also create lower “flowing bottom-hole” pressures from the reservoir, thereby maximizing the drawdown in the well and subsequent production rates. As a result, the well may be able to productively flow on its own for a longer period of time without intervention. To date, the system has been run in more than 40 gas wells throughout the United States.
Plunger lift to dewater shale wells. As production declines and liquid loading begins, Haynesville shale operators are considering artificial lift to dewater their wells. Most Haynesville wells in north Louisiana are being produced into high line pressure, usually in excess of 100 psi. With such high line pressure, plunger lift is not typically thought of as being the preferred method of artificial lift, but early results have been promising. Another positive has been that fluid production has been more in the normal range for typical plunger lift operations, which are usually less than 20 bpd.
With most wells in the Haynesville requiring a packer set at about 10,500 ft (for wells with a TVD at about 11,000 ft and MD about 15,000 ft) due to the corrosive environment, most tubing is being landed in the vertical section, thus making the plunger operation much like a conventional well. The main issue with the tubing being landed in the vertical section is keeping liquid from falling out of the end of the tubing if the well is shut in and making its way back into the horizontal section. The best results have been achieved by using plungers that require little or no shut-in time, thus maintaining near-flowing conditions. Typical production increases range from 10% to 20% with initial rates before install of 1-1.5 MMcfd, Fig. 6. As production continues to decline and shut-in times are required to successfully operate plunger lift, the use of a standing valve could be required.
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Fig. 6. Plunger lift is a viable option to dewater Haynesville shale gas wells.
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HEAVY DUTY ROD PUMP
Microlift has added models for deeper, heavier rod pumping to a peak polished rod load of 40,000 lb per 192-in. stroke, and a gas pressure-powered model that needs no electricity, Fig. 7. Features include push button control of plunger space-out position. The pumping units gauge well loads at startup and self-adjust continuously to changes in well fluid level. The units are fully automated and easy to operate from the control panel in the field or remotely from a web browser. A built-in dynamometer is available to monitor and change production rate. The electronic device automatically calculates inferred production based on the pump data. The rod pump applies energy efficient self-balancing technology to harvest down-stroke energy, using as little as one-half the electricity, propane, or natural gas of typical beam pumping units. An extra-quiet model option is available for urban settings.
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Fig. 7. The Microlift heavy-duty rod pumping unit includes a dynamometer to monitor and adjust the production rate.
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‘GREEN’ BEAM GAS COMPRESSOR
The Beam Gas Compressor (BGC) from Permian Production Equipment Inc. in Midland, Texas, is designed to replace a gas engine screw compressor that may be handicapped by high noise and greenhouse gas emissions, Fig. 8. A recent example is a screw compressor that was operating near a “noise sensitive” trout fishing farm. The well had to be taken out of production during the trout fishing season with a loss of over 8 bpd of oil production along with the associated gas.
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Fig. 8. The beam gas compressor can increase oil or gas production with no additional noise or gas emissions.
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The BGC is used on rod pumping gas wells to increase gas production and sales by drawing the produced gas up the casing and into the flowline, which relieves gas locking from the downhole pump. The BGC can be installed on oil wells to relieve restricting backpressure caused by production facilities and sales line pressure. The BGC is powered by the walking beam movement that pumps the well. The system draws produced gas from the casing through check valves and discharges it into the flowline downstream from the pumping tee. The gas rejoins the tubing production and flows to the separator and/or on to the gas sales line. The size of the BGC is determined by the current relationships of the pumping units mechanics, production of the well and downstream effects of the sales line.
The BGC creates no noise on its own above the pump jack noise. With a BGC there are no emissions and, therefore, no increase will be needed in the “footprint” of the well. In many cases, if a conventional means of compression is being used, the size of the footprint can actually decrease by switching to the BGC.
INTEGRATED MOTOR CONTROL PANEL
Lufkin Automation has introduced a new motor control panel for beam-pumped artificial lift systems, Fig. 9. The standard model is pre-wired for any rod pump controller to ease connections. An optional model has the Lufkin rod pump controller integrated into the unit. The Lufkin rod pump controller uses patented algorithms to calculate a downhole card on every stroke of the beam pumping unit. Operators can save on installation costs of two products by installing the new motor control panel with the integrated rod pump controller.
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Fig. 9. The Lufkin motor control panel can be integrated with a rod pump controller.
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In addition to installation and maintenance savings, the motor control panels feature several safety mechanisms. Both models are touch safe, with all wire connections are covered, lockout/tagout ready to control the power supply while maintaining the unit and features easy-to-read safety warnings.
BRUSH SAND SEAL
Harbison-Fischer offers a new brush sand seal that reduces the potential hazard of sticking a bottom hold-down pump in the tubing due to accumulated particulates above the bottom hold-down, Fig. 10. For pressure balance, the lower bushing is vented. 
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Fig. 10. The Harbison-Fischer brush sand seal prevents particulates from affecting bottom hold-down performance.
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ACKNOWLEDGMENT
The authors thank the featured companies for providing the information for this article. The authors are not responsible for claims made by the manufacturers and vendors about their products’ capabilities.
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THE AUTHORS
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James F. Lea teaches 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 from Southern Methodist University. He worked for Sun Oil 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.
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Herald W. Winkler is former chairman and now a professor emeritus and research associate in Texas Tech University’s petroleum engineering department in Lubbock, Texas. He works as a consultant in artificial lift, specializing in gas lift.
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