What's New in Artificial Lift?

PRODUCTION TECHNOLOGY

What’s new in artificial lift?

Part 2: In this second of two tems. Hence, investing in an ESP system While ESPs can be prone to prema- monthly reports, the authors might appear to be riskier than investing in ture failures, a long-stroke’s downhole rod highlight innovations in ESPs, alternative lift methods, whose cost struc- pump is usually more tolerant to extreme PCPs and plunger lift systems. ture is concentrated in the surface equip- downhole conditions. ment with a runlife of 20 years or more. In this case history, a mature oil well Like conventional beam/rod pump provided an opportunity to compare op- systems, long-stroke pumping units em- erating expenses (OPEX) of an ESP and a ŝŝJOE D. WOODS, International Pinpoint; ploy sucker rods connected to a downhole long-stroke pumping unit. The well’s pro- JAMES F. LEA, PL Tech LLC; and HERALD W. pump. However, the surface equipment is duction had slowly declined from an initial WINKLER, Texas Tech University fundamentally different for the long-stroke rate of 3,000 bpd to less than 1,200 bpd. unit, as the pumpjack is replaced with a The existing ESP pump was nearing the vertical unit that is shipped and installed at end of its operating life and running at 30 Continuing last month’s “What’s new the wellsite in one piece, Fig. 1. Hz in a down-thrust condition. The opera- in artificial lift?” discussion, this report As its name implies, when compared to tor was forced to replace the downhole lift covers recent developments in the areas of a beam pumping unit, a long-stroke system electric submersible pumps (ESPs), pro- has a longer stroke length. These units also Fig. 1. The Weatherford Rotaflex long- gressive cavity pumps (PCPs) and plunger operate at fewer strokes or cycles per min- stroke pumping unit (foreground). lift developments. ute (an average of 3.75 strokes/min. vs. an The method used in choosing an artifi- average of 8 strokes/min. for conventional cial lift system is too often a “we’ve always surface pumps). During a large part of its done it this way” decision process, rather pump cycle, the long-stroke unit’s rod than a strategic plan based on thorough op- string moves at a relatively steady velocity. erational and cost analyses. Hence, before This results in fewer acceleration-decelera- profiling several product developments, tion cycles and fewer rod reversals. we want to underscore yet again the impor- Long-stroke units use a torque arm with tance of proper lift system selection. a shorter radius than the distance between To that end, Weatherford provided us the saddle bearing and the horsehead on a a recent case history involving what might beam/rod unit. This transmits power at a typically have been an ESP application. lower torque, and extends the applicability However, upon analysis, the operator de- of the long-stroke unit to a wider range of termined there was a good alternative. production rates and well depths. For well servicing, after disconnecting ESP vs. LONG-STROKE ROD PUMP the bridle and carrier bar from the pol- In the oil field, conventional wisdom ished rod, the long-stroke unit is rolled holds that the rod lift artificial lift method away from the wellhead without any is suitable for wells producing at rates of further disassembly. When a workover 200 bpd or less. Of course this is heavily is completed, the unit is rolled back into dependant on the depth of the well and place, and the carrier bar is reconnected Fig. 2. General operating ranges for ESPs weight of the fluid column. So, under the to the polished rod. Hence, the long- vs. reciprocating rod pumps (RPP). right conditions, some might put this rate stroke units often can provide simpler 16,000 as high as 400 bpd or even 600 bpd. well servicing. However, most low-rate ESPs (up to Long-stroke units routinely achieve 1,000 bpd to 1,500 bpd) feature low ef- up to 1,500 bpd at 6,000 ft (1,800 m) ficiencies compared to higher rate ESPs. and 100 bpd at 10,000 ft (3,000 m). In

This can result in increased power costs shallow wells, which are typically non- Depth, ft and reduced runlife. From a cost structure ESP applications, long-stroke units can ESP perspective, the bulk of ESP system costs deliver production rates exceeding 4,000 0 RRP are concentrated in the downhole equip- bpd, Fig. 2. In some cases, they can pro- 0 95,000 ment, which generally can have a lower vide greater operational efficiency than Production, stbopd runlife compared to surface-centric lift sys- ESPs at similar depths. Article copyright © 2014 by Gulf Publishing Company. All rights reserved. Printed in U.S.A. Not to be distributed in electronic or printed form, or posted on a website, without express written permission of copyrightWorld holder .Oil / JUNE 2014 59 PRODUCTION TECHNOLOGY

Table 1. Well parameters for the candidate well. Fig. 3. Summit Corsair high-efficiency ESP Initial Flow Rate 3,000 bpd at 65% water cut motor. Current Flow Rate 1,180 bpd at 97.5% water cut Oil API 18.2 Fluid Mixture SG 1 Production Level 3,650 ft (1,112 m) Tubing Head Pressure 220 psi Tubing Length 4,520 ft (1,378 m) Tubing OD 4.5 in. Power Cost $0.10 per kWh

Table 2. OPEX comparisons for the ESP and the long-stroke pumping unit. Long Stroke System ESP Total system sales price $300,000 $300,000 Downhole pump price $9,000 $145,000 Total price, % 3% 48% Total downhole price $59,000 $235,000 Total price, % 20% 78% VSD $45,000 $65,000 Rig time, days 1 1 Workover cost $12,950 $148,950 Failure rate/3 years 1 1 Workover cost over 3 years for 15 wells $194,250 $2,234,250 Power cost/3 years for 15 wells $27,000 $435,000 Savings from the use of Long Stroke System $3,670,020 Power cost reduction 37% Workover cost reduction 91% Inventory cost reduction 94% OPEX reduction 62% system ahead of imminent ESP failure. The Additionally, the workover cost for well parameters for the evaluation process the ESP is 91% higher than for the long- are shown in Table 1. stroke unit. Workover costs include rig Both lift systems in this geographic re- rental cost, cost of deferred produc- gion have essentially the same sales price, tion and the replacement price of a but the overall OPEX associated with the downhole pump. ESP is $3,670,020 higher, Table 2. OPEX is estimated as a sum of The reason for the significant OPEX workover cost (assuming a reasonable This case history provides a good ex- difference is in the price breakdown of rate of one failure per three years), power ample of artificial lift system selection. For both systems. For the long-stroke system, cost for three years, and the cost of three a more detailed discussion regarding artifi- total downhole price comprises the cost of downhole pumps used as inventory for an cial lift system selection, refer to SPE paper the rod pump and sucker rods, while the oilfield consisting of 15 such wells. 52157 entitled “Selection of Artificial Lift” ESP price comprises the downhole pump For the ESP, for example, this works out by James Lea and Henry Nickens. Also, assembly (multi-stage centrifugal pump, to $2,234,250 (workover cost over three more useful system selection information intake, protector, motor and power cable). years for 15 wells considering run life of can be found in the Petroleum Engineering Focusing on the long-stroke system, three years per well) + $3,271,860 (power Handbook, Volume IV: Production Opera- the $9,000 represents the price of the cost of ESP wells in this region for a life tions Engineering. downhole reciprocating rod pump. The to- span of three years) + $435,000 (three ESP tal downhole price represents the price of pumps at $145,000 each). ESP DEVELOPMENTS the rod pump plus the sucker rods ($9,000 This exercise demonstrated that the An ESP downhole assembly will typical- + $50,000 = $59,000). For the long stroke long-stroke pumping unit could provide ly include the electric submersible pump, a system, the cost of the variable speed drive significant financial benefits in wells that gas handler/separator or standard intake, (VSD) represents only the price of the were traditionally considered to be low- a seal section, a submersible motor with drive, since a step-up transformer is not and medium-flow ESP applications. While a connected power cable that runs to the required. both the ESP and the long-stroke pumping surface, and often a downhole sensor pack- For the ESP, $145,000 represents the unit can deliver a 1,180-bpd production age that communicates pump and wellbore price of the downhole pump, intake, pro- rate, the OPEX associated with the long- performance information back to a surface tector and motor. The total downhole stroke unit proved lower, due to benefits in interface system. The surface equipment price ($235,000) includes the downhole three major areas: may include a VSD or switchboard, a mo- assembly ($145,000) plus the power cable • Power cost reduced 37% tor protection system and/or an intelligent ($90,000). The VSD price includes a load • Workover cost reduced 91% control system. This year, we feature several filter and a step-up transformer. • Inventory cost reduced 94%. submissions related to ESP systems.

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design motor technology. The new Corsair The sand will accumulate at the top of the Fig. 4. Summit Defender Super Sand seal motors (Fig. 3) in both 456 series and 562 seal section, which contains a mechanical section. series have several distinct advantages that seal and vent port. allow for increased horsepower ratings When the pump is put back into opera- along with reduced operating tempera- tion accumulated sand will remain at the tures, promoting reliability and extending top of the seal. Over time, accumulation of run life. the sand will plug the vent port and prevent In these new motors, Summit has elimi- well fluid from making good contact with nated the recessed rotor, which required the mechanical seal faces, which must be motor bearings to be inserted into the ro- in contact with well fluid in order to cool tor increasing friction, reducing cooling ex- the faces. The sand can compact around posure and increasing heat to the system. the mechanical seal and prevent well fluid Eliminating the recessed rotor allows for from transferring heat. The sealing faces utilization of a wider motor bearing fa- will overheat and lead to failure. cilitating better heat transfer and internal The vent port is used to vent expand- cooling properties. ing motor oil to the wellbore to maintain The new motors offer positive lock- equalized pressure. The expanding oil is ing bearings that are non-magnetic, which released through an internal check valve lo- eliminates concerns of bearings operating cated inside the seal. If, as described above, outside of the brass lams used in other mo- the vent port is blocked off, the seal can- tors. Additionally, the motor shaft has add- not equalize pressure effectively. This will ed lubrication slots for each bearing. This cause a pressure build-up inside the seal to improves lubrication between the bearing such a degree that it will separate the me- and sleeve and reduces internally gener- chanical seal faces. When this occurs, well ated heat and wear. fluid and sand will enter the clean oil sec- The motors employ coffin-shaped rotor tion of the seal. bars (which increase the copper content A bronze bushing in most legacy man- by 22%), closed slot all steel stator lamina- ufactured seals is located inside the seal tions and double-wrapped polyimide insu- section head, just below the mechanical lated windings. For extreme temperatures seal. Well fluid contamination and sand the double-wrapped polyimide windings will rapidly destroy the bronze bushing can be extruded with patent-pending Peek causing a catastrophic failure due to loss insulation, which provides the benefits of of shaft support. Most seals contain mul- the insulation’s higher temperature rating tiple chambers for redundancy. As the seal and maintains the advantages of the poly- chambers fail, eventually the shaft will fail, imide’s dielectric strength. due to side loads causing buckling. Improved seal section. As previously The new patent-pending Defender Fig. 5. Nautilus power cable deployable mentioned, major downhole components Super Sand seal section (Fig. 4) is a revo- ESP system for 51/2-in. tubing/casing. of an ESP system are an electric motor, lutionary design from Summit ESP that seal section, pump intake and centrifugal eliminates concerns from sand contami- DC cable pump. The motor is designed to operate nation, upper mechanical seal failure and (100 HP motor +) in well fluid and is generally protected shaft bushing overload due to incipient Tubing from well fluid ingress by means of a seal buckling of the shaft. The top end of this Power conversion module (PCM), 456 series section that is bolted directly to the top of new seal has “sand exclusion technology” the motor. The seal section provides four added just above the mechanical seal. This 7-in. 26 lb/ft casing (or larger) main functions: 1) provides a fluid barrier technology prevents sand from falling into Standard motor, 456 series between the well fluid and motor oil, 2) the mechanical seal eliminating the initial 5½-in. tubing/casing allows for motor oil expansion, 3) pro- mode for seal failures. Special seal, 400 series vides pressure equalization, and 4) car- Additionally, a well fluid thrust bear- Pump discharge ries the thrust of the pump bolted directly ing has been added to the design, along Isolation/packo„ above the seal. with an improved head design, which al- Bottom intake pump, 400 series In many instances, produced fluids con- lows for increased well fluid lubrication to tain frac sand and/or formation reservoir cool the bearing. Perforations sand, which enters the pump along with Relocating the thrust bearing to the top the fluid. While sand may wear the pump, of the seal greatly reduces any concerns of it generally does not pose a problem to the buckling the shaft. The seal includes addi- High-efficiency ESP motors. Sum- seal, as long as the pump is operating. How- tional improvements that flush away any mit ESP has released a new line of motors, ever, during shutdown the sand carried in accumulated debris from the mechanical dramatically increasing horsepower per ro- the produced fluids will fall back through seal when the unit is stopped. The bronze tor, efficiency and performance over legacy the pump and pump-intake, due to gravity. shaft bushing has been replaced with a self-

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cently at an SPE Workshop, where a paper gas entrained in the production fluid. The Fig. 6. Zeitecs rigless ESP Shuttle System. was presented on the first rigless replace- presence of gas reduces the pumping ef- ment of an ESP on CT in response to an ficiency of ESP systems and impacts the Landing nipple unexpected ESP failure. bottom line. Gas accumulation prevents Seal bore GS W/L profile Seal mandrel Improved ‘non-invasive’ ESP convey- fluid progression through the pump, which ESP cable Expansion seal as’y ance system. The Artificial Lift Company creates gas locking and causes the system Space-out tubing (ALC) has released its new V2 Advantage to shut down or potentially become dam- Adjustable union non-invasive ESP conveyance system. This aged, due to overheating. Gas handling is 9⅝-in. or 7-in. Standard pump casing unique technology further simplifies the often a slow, sometimes tedious process Standard seal ability of an operator to quickly and easily with only limited success. Standard motor ESP monitors install and retrieve ESP systems on slick- The Baker Hughes Electrospeed Ad- Docking station Motor connector line, without a rig. The system is designed vantage VSD has production software with Lubricator valve Connectors specifically for high-value wells, where ac- specific solutions for recurring ESP prob- W/L re-entry guide Retrievable cess to the location is difficult, rig inter- lems, including gas slugs and gas locking. Permanent components components ventions are cost-prohibitive and where It features MaxRate software, which is de- subsequent delays in production cannot be signed to mitigate production interference accepted. It is not unusual in these environ- due to high gas content by automatically Fig. 7. V2 Advantage system side-pocket ments for an operator to lose up to 10% of purging accumulated gas and controlling mounted downhole wet connector. production to ESP downtime, in addition the draw down rate to achieve the opera- to the high cost of replacing failed ESPs. tor’s target. This “rigless” conveyance system com- Gas is a common challenge for most bines a robust production-tubing land- artificial lift systems. When gas collects in ing string with a side-pocket-mounted low-pressure areas of an ESP system, fluid downhole wet connector (Fig. 7) and a progression through the pump stages is high-power permanent magnet motor blocked, resulting in a gas-lock condition. (PMM). The system provides easy instal- Due to undulations in horizontally drilled lation and retrieval of ESP systems up to wells, gas tends to migrate to the highest 400 hp via standard 0.125-in. slickline (or point of a horizontal wellbore creating a aligning carbide bushing set that will oper- coil or tractor) through 4.5-in. tubing (or gas slug. When an ESP encounters a gas ate in contaminated well fluid conditions higher hp in larger tubing). It is compat- slug, the event can last several minutes or and offers radial shaft support. ible with 7-in. and larger casing, and can be longer. The VSD registers a decrease in Power cable-deployable ESP system. used with all ESP provider pumps (400 se- motor torque, indicating that the pump has Zeitecs, Inc. recently announced the ini- ries), VSDs, cables, protectors and gauges. encountered enough gas to stop fluid flow. tial field installation of the Nautilus power With the ESP retrieved, full bore access is The MaxRate software automatically cable deployable ESP system, Fig. 5. The achieved through the well, providing for a slows the system down to allow produced second-generation system requires no multitude of intervention options. fluid to backflow through the pump, flush- tubing-deployed semi-permanent compo- Unlike conventional ESP deployment ing the gas bubbles from behind the impel- nents. Instead, it allows standard ESPs to techniques that require the use of a costly ler vanes. Once the gas lock is cleared, the be deployed on ultra-strong DC coaxial workover rig, the V2 Advantage system drive will ramp the motor frequency back power cable. The equipment includes a provides the ability to install and retrieve up to resume pumping. The software will downhole power conversion module to ESP systems through a standard 4.5-in. lu- make several attempts to break the gas lock convert DC current back to AC to power bricator, without killing the well. condition. If it determines that the situa- the standard, 3-phase induction motor. The system has been developed to fur- tion has not been cleared, a system shut- This system is undergoing final field tests. ther increase reliability and address the down will occur to prevent any damage to ESP shuttle system. Zeitecs also an- complicated installation processes used the equipment string. During the gas purge nounced new installations of its “rigless” with traditional ESP systems. An impor- event, the ESP motor slows down while ESP Shuttle System, Fig. 6. A downhole tant component of the system is ALC’s back-flowing fluid runs past the unloaded docking station with a three-phase electri- fourth generation permanent magnet mo- motor. This cools the motor and results in cal wet-connector system is first deployed tor. The system’s 3.75-in., 135-hp, single- extended run life for the ESP system. at the bottom end of the production tubing piece motor is only 9.6 ft long (compared The software also contains logic to and then the standard ESP system (pump, to more than 50 ft for a traditional ESP mo- manage drawdown in challenging situa- seal and motor) is run into the tubing on ei- tor). Motors up to 400 hp are available for tions, such as horizontally completed wells ther wireline, coiled tubing or sucker rods. this system (3.75-in., 26-ft long). The high or wells with long-duration gas slugging. Until recently the system required larger power density of these PMMs eliminates By using a novel approach to downhole tubing sizes, but it is now commercially the need to run tandem and triple ESP mo- pressure targets and control loops, opera- available to deploy the complete range of tors to achieve the desired power rating. tors can automatically manage fluid levels standard ESP sizes from 562 series in 7-in. Baker Hughes software improves and bottomhole pressure. casing to newly developed designs for 375 ESP gas-handling capabilities. One of Halliburton software targets ESP series in 41/2-in. tubing. The value proposi- the challenges most operators encounter gas handling performance. Halliburton tion of this technology was confirmed re- when producing oil wells is high levels of Artificial Lift continues to refine its un-

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Fig. 8. Halliburton’s VSD software reduces costly downtime. Fig. 9. New VSD software algorithm helps alleviate common gas problems associated with ESP systems.

Table 3. Pump Checker software calculated that this ESP was under-perfoming. rameters to input with the rate information Calculated Measured Difference based on the exact form of artificial lift em- Pump Discharge Pressure, psig 2813 ployed, including ESP systems. Pump Intake Pressure, psig 596 2301 1705 Armed with the right data, producers Pump dP, psi 2217 512 1705 Pump Rate, bpd 1310 798 512 can then base system optimization strate- Pump Degradation, % 76.9 gies on results that are specific to their lift In Range? In Range system. It’s a more specific approach than Calculated Pwf, psig 2586 standard well test reporting. Lost Gross Rate, stbpd 432 Pump checker. According to ALP, this Lost Oil, stbpd 180 software is specifically designed to opti- mize ESP production, and diagnose res- conventional well VSD algorithm tech- using proven gas-handling technology ervoir inflow performance for future ESP nology to work in conjunction with its coupled with improved VSD algorithms, system design. The software pinpoints Q-Max GBP gas bypass technology to operators are realizing higher well pro- where ESPs are losing production and why. improve ESP performance. ductivity, a quicker return on investment It validates Well Test data (double-check- The Q-max gas bypass has proven to be and a higher degree of reliability from ing the input), quantifies lost production effective in increasing drawdown charac- downhole ESP systems. and determines bottomhole flowing pres- teristics in very high-GOR wells. The com- New software for ESP system opti- sure. It determines whether the lift system pany’s proprietary VSD software works in mization. Optimizing artificial lift systems is performing as designed. conjunction with the Q-max gas bypass depends on access to accurate and relevant In Table 3, Pump Checker revealed to consistently allow the ESP to draw the data. While operators and suppliers pro- that this ESP system has degraded by working well pressure farther than previ- duce lots of data, some of it may not be nearly 77% from its performance when ously thought possible. relevant to driving artificial lift improve- installed. That means 180 bpd (or around As seen in Fig. 8, this well was shutting ment. Often, if good data do exist, they are $18,000/day at $100/bbl) of lost produc- down and restarting multiple times in a so scattered across multiple systems and tion. With this information, the operator week. The downtime was costing the op- spreadsheets that they are virtually unus- can take appropriate action to maximize erator lost production over a 24-hr period. able. Pulling all the critical data together well performance. On March 25, Halliburton’s proprietary can be problematic. Pump analytics. Using this software, VSD program was activated remotely Artificial Lift Performance Ltd. (ALP) producers can challenge “well conditions” from a computer, hundreds of miles away. has introduced three new software ap- as being the cause of repetitive failures in The result can be seen from the date of plications that can be run in the cloud or root cause failure analysis (RCFA) reports optimization. This well since has run con- on a server, all using a core set of relevant from ESP suppliers, by forcing failure cat- tinuously with reduced intake pressures data underpinned by application-specific egorization through a structured process and higher production. figures to show an operator exactly what a that drives corrections. The goal is to im- A similar situation is depicted in well is doing and what it should be doing. prove artificial lift performance and ensure Fig. 9. After the VSD on the well was pro- Armed with the difference between the fit-for-purpose equipment. grammed to operate using the new VSD two, action can be taken to maximize well The software helps producers build an algorithm, it stopped cycling and has run performance at minimal cost. easily managed, reliable well and equip- continuously. The well continues to slow- Well test. Each method of artificial lift ment history and failure-tracking database ly draw down the BHP without reducing differs, but most data-gathering systems that provides artificial lift system perfor- the stock tank liquid. primarily tend to focus on collecting pro- mance for a field over time. With an intui- Since 2010, Halliburton Artificial Lift duction rates. ALP’s Well Test software tive “dashboard” (Fig. 10), it facilitates the has installed over 1,800 gas bypass sys- not only analyzes production data, it also performance comparison of various sys- tems in unconventional shale wells. By prompts producers which operating pa- tems/equipment.

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All-in-one ESP control and data toring system and remote commands. A the SCADA system. The Instruct unit also acquisition system. Aimed at enhanc- modular design provides greater service- can operate as a stand-alone device for re- ing productivity and maximizing uptime, ability and expandablitity. The Instruct mote monitoring applications. Schlumberger has developed a centralized, unit installs directly into the company’s Integral to the troubleshooting pro- single platform that provides protection, VSDs, and can be configured to automati- cess, the Instruct unit maintains a record control and data acquisition for artificially- cally make adjustments to optimize well of up to 500 alarms and events in internal lifted wells equipped with ESPs. and pump performance, program alarms memory. By monitoring ESP (or horizon- The data-gathering and storage system, and trip settings. The unit also has emer- tal surface pump) operating data points, it the Instruct all-in-one acquisition and con- gency shut-down capability. provides protection from fault conditions trol unit (Fig. 11), gathers, analyzes and For remote monitoring and con- on any of the monitored signals. transmits critical data in real time from sur- trol, the system can be connected to the face and downhole sensors to optimize en- Schlumberger 24/7 Artificial Lift Surveil- Fig. 11. The Schlumberger Instruct all-in- gineering analysis and troubleshooting and lance Center via the LiftWatcher real-time one protection, control, acquisition and manage pump and well performance. The surveillance and optimization service or transmission unit with at-a-glance wellsite system can monitor assessment, and intuitive feedback and control interface. up to four wells at once, and transmits Fig. 10. The Pump Analytics user dashboard facilitates the data from a variety of performance comparison of various systems/equipment. sources, eliminating the need for multiple surface components. Users can moni- tor electrical system data, information from external analog or digital devices, data measured by the downhole moni-

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New ESP monitoring system. persistence from many individuals and Schlumberger has developed an ESP mon- companies, PCP systems have experienced Fig. 12. The new Schlumberger Endurant itoring system that ensures continuous a gradual emergence as a common form of ground-fault-immune ESP monitoring system. communication in case of ground faults, artificial lift. extending ESP run life and reducing fail- Permanent magnet motor PCP top ures and operating costs. drive. Over the past decade, manufactur- The Endurant ground-fault-immune ers tried developing a direct-drive PCP top ESP monitoring system (Fig. 12), repre- drive motor that can perform reliably in sents a significant step-change in address- demanding applications. Several attempts ing one of the biggest causes of failure in have achieved moderate success in con- ESP monitoring systems, which historical- trolled environments, but none have dis- ly have been highly susceptible to ground played long-term, field-proven results. faults or electrical shorts. Designed for the A permanent magnet motor (PMM) high-cost intervention market (including PCP top drive (Fig. 13), developed by offshore, subsea and harsh environments), General Magnetic Group (GMG), is the the system can continue operating and first commercially successful solution in transmitting measurements even during the market, according to its manufacturer. ground fault cable failure and in high-tem- Due to a partnership between GMG and perature downhole environments. National Oilwell Varco (NOV) Mono, this The system is especially suited for product is now part of NOV Mono’s world- fields prone to ground faults and wells wide Artificial Lift Solutions offering. experiencing startup and instability Currently available M-75-PMM and problems, erratic production or needing M-105-PMM models feature easy installa- reservoir build-up analysis. It delivers tion, reduced electrical consumption and high reliability in the harshest environ- no gearboxes or external moving parts to ments, engineered for high-performance create potential hazards. These drives help high-temperature downhole monitoring. optimize oilfield operations by reducing Designed with metal-to-metal Inconel maintenance, minimizing costly stoppages, transducers, a stainless steel body and and increasing jobsite safety. high-temperature circuitry, the system Because conventional electric motors can operate continuously and reliably in only have operating efficiencies over lim- temperatures up to 150°C. ited operating speeds, even with a VFD, Fig. 13. NOV’s permanent magnet motor A dual power supply prevents the gauge any significant changes in RPMs ultimately PCP Top Drive. breakdown caused by ground faults so the require changes in the gear ratio between system can continue communicating to the motor and pump. PMM driveheads surface, without interruption. In real time are engineered specifically for PCP appli- the system receives and transmits intake cations. Using a permanent magnet motor pressure and temperature, motor winding topology, they are ideal for low- and vari- temperature and pump discharge pressure. able-speed applications. The monitoring system also enhances With a 92.9% system efficiency, these reservoir understanding by providing an driveheads deliver higher production vol- advanced, high-speed telemetry uplink umes without increased energy consump- for continuous data transmission at rates tion. They also integrate seamlessly with of 100 bits per second, even if the ESP external optimization equipment such as is shut down. This facilitates high-reso- pump-off controllers. With reduced green- lution, high-sample-rate monitoring of house gas emissions and low noise output reservoir fluid build-up to determine res- (68 decibels at 10 ft), they are considered ervoir performance. to be environmentally-friendly top drives. The downhole gauge communicates The slightly higher manufacturing with a surface acquisition system by way of cost of creating a permanent magnetic the ESP power cable. Alarms can be set for field in the rotor is offset by quantifiable individual parameters appropriate to each lifecycle savings resulting from lower ESP completion. operating costs, reduced energy con- of operating at high efficiencies through- sumption and higher system efficiencies out its entire speed range spectrum. PCP DEVELOPMENTS brought on by the elimination of speed- Changing speed with a PMM drive is It was not until the late 1970s that a con- reduction equipment. as simple as pushing a button on the VFD, certed effort was made to use progessive Because it does not require any electri- which eliminates time-consuming, man- (or progressing) cavity pumps (PCP) as cal current to create a magnetic field in the power-intensive well shutdown activities. a method of artificial lift in the petroleum rotor or losses from speed reduction equip- The PMM can also be integrated with a industry. With technical contributions and ment, the PMM PCP top drive is capable number of other products, allowing own-

Article copyright © 2014 by Gulf Publishing Company. All rights reserved. Printed in U.S.A. World Oil / JUNE 2014 71 Not to be distributed in electronic or printed form, or posted on a website, without express written permission of copyright holder. PRODUCTION TECHNOLOGY ers to further customize their operations powered submersible motor that con- fluid viscosity, break down paraffin and and boost production rates. nects to a PCP. The submersible motor other beneficial processes. The NOV Mono PMM drivehead line and pump are conveyed into the well via Using an optional data cable with delivers full power and torque continu- CJS’s FlatPak or ArmorPak umbilical downhole data sensors, the HydraPak ously from 30 to 450 RPM. The drivehe- tubing. Two of the tubes in the umbili- PCP system allows well optimization with ads have rated torques up to 1,000 ft-lb cal power the submersible motor driving information like pump intake pressure, dis- and deliver 92.9% efficiency from utility the PCP to force production fluids to charge pressure and temperature readings. to rod string. the surface. The motor and pump can be The umbilical and PCP system is low- HydraPak PCP. The HydraPak PCP reversed to flush solids out of the pump ered into the well via a conventional coiled system (Fig. 14) developed by CJS Pro- back into the well cellar. The HydraPak tubing unit. The submersible motor and duction Technologies incorporates a PCP system can include a conduit for downhole pump can be positioned in the coiled tubing umbilical and hydraulically injecting additives to reduce production heel or lateral of the well. CJS also offers hydraulic surface con- trol automation to monitor and control pump speed and fluid level to prevent well “pump off.” Flow control technology. To ensure steady and reliable PCP performance, it’s essential to properly regulate the pump speed. Pump too fast and you risk outpac- ing well inflow, which can lead to pump off and consequential pump failure. Alter- natively, if you pump too slowly, you can reduce production to levels far below the well’s potential. WellPilot flow control technology (FCT) from Weatherford eliminates the guesswork and optimizes PCP perfor- mance by constantly comparing pump speed to the monitored flowrate. Used with a variable-speed controller, the Well- Pilot FCT continuously fine-tunes pump speed to achieve optimal production while protecting against flow loss. The WellPilot FCT (Fig. 15) has no moving parts. Based on the principle of thermal cooling, the system uses two stain- less-steel probes to determine changes in flowrate. One probe generates heat and detects heat absorption, while the other is unheated and acts as a high-precision thermometer. The probes alternate roles periodically, switching between heated and unheated functions, to deter scale and paraffin buildup. To determine flowrates, the heated probe detects how much heat is being

Fig. 14. The HydraPak PCP system includes the CJS triple coiled tubing umbilical, hydraulic submersible motor and PCP.

72 JUNE 2014 / WorldOil.com Article copyright © 2014 by Gulf Publishing Company. All rights reserved. Printed in U.S.A. Not to be distributed in electronic or printed form, or posted on a website, without express written permission of copyright holder. PRODUCTION TECHNOLOGY absorbed by the passing fluid. The high- climbing speeds and corresponding flow multiple methods to see which one may er the flow, the more heat is absorbed, rates, comparing the current flowrate work best, based on the candidate wells. which creates a greater cooling effect. against those observed at lower speeds. Plunger design evens fluid produc- The unheated probe helps fine-tune the It then starts the climbing process again, tion in erratic wells. Multi Products Com- flow detection by reading the fluid’s am- selecting the lowest recorded speed that pany focuses on advancing plunger lift bient, in-motion temperature. The con- resulted in a flowrate at or above the cur- technology to increase versatility and fluid troller continually analyzes changes in rent production rate of the well. When handling capability in a wider range of wells. temperature readings from the probes. the control indicates a situation where One of their new technologies recently Based on this information, it signals the adequate flow is not being produced, the commercialized is the Steady-Flo plunger variable speed drive, to adjust pump FCT can be set to shut down the well. (Fig. 16), designed for midrange wells speed in relation to the production capa- Because gas absorbs heat at a much that produce high fluid volumes but lack bilities of the well. lower rate than oil or water, the instru- the reservoir energy to evacuate the fluid. The WellPilot FCT is an auto-cali- ment can easily identify gas in the flow Steady-Flo is a single-piece plunger with- brating instrument. Once installed and line and make automatic adjustments to powered on, it begins controlling the well avoid a pumpoff condition. Fig. 15. Weatherford WellPilot flow control immediately. The objective is to always When integrated with the WellPi- technology. operate the pump at the lowest speed lot VSD, the WellPilot FCT delivers a required to deliver maximum produc- complete set of available safety options tion from a well. To find this speed, the to protect the pump in response to well- instrument follows a patented process related problems. called “climb and double-back.” This process assures optimal control and reli- PLUNGER LIFT DEVELOPMENTS ability for the PCP. If an increase in pump Increasing the range of candidate speed causes flow rate to decline, or if the wells for plunger lift gives operators flowrate remains unchanged as a result more options for optimizing well per- of a speed increase, WellPilot FCT auto- formance and lift economics. Instead of matically compensates. It doubles back, looking at one or maybe two artificial lift searching through its progressive table of methods, operators can analyze costs on

Article copyright © 2014 by Gulf Publishing Company. All rights reserved. Printed in U.S.A. World Oil / JUNE 2014 73 Not to be distributed in electronic or printed form, or posted on a website, without express written permission of copyright holder. PRODUCTION TECHNOLOGY

Fig. 16. Multi Products’ new Steady-Flo Fig. 18. The pressure cut plot for a regular pad plunger (above) vs. the pressure cut plot plunger (12-in. length). for the jetted pad version of the same plunger (below).

Fig. 19. Flow trajectories isolated to flow that passes through two jets; one in the Jetted pad plunger. Recently, a major lower pad set, another in the upper set. part of Well Master’s effort to increase the effectiveness of plunger lift technology has included the use of computational fluid dynamics (CFD) to evaluate designs and model physical phenomena associ- ated with plunger lift. The use of CFD resulted in a new patents-pending, jetted Fig. 20. The new Baker Hughes Artificial pad plunger, Fig. 17. Lift Research and Technology Center in CFD’s great advantages are that it can Claremore, Okla. model flow in a CAD model quickly and Fig. 17. Jetted pad plunger (note the bore consistently, and provide an intuitive through the center and holes under pads). means of reviewing data as well as quan- tifying results, which makes side by side comparison of designs a manageable task. While CFD has a wide variety of appli- cations in plunger lift, Well Master high- lights its role in design while considering an issue encountered with padded plung- ers in horizontal and deviated wells. At angles above 20° or so, plunger pads collapse, compromising seal and large fluid load on one plunger trip, and severely limiting performance. A new then very little fluid on the next trip. Well Master plunger design combats this out any moving parts, and has fall speeds The through-bore design also helps effect by jetting flow from a bore in the in between common bar stock plungers ensure that the plunger falls faster than plunger to the underside of the pads. and high-rate bypass plungers. Because conventional plungers, which decreases This creates an expansion effect, closing faster fall speeds translate to more plunger well shut-in time and increases the number the gaps that occur with pad collapse and cycles per day, and considering that wells of plunger runs per day. It provides more increasing efficiency. The mechanics of must be shut in for conventional plungers predictable, easily tracked runs, allowing the jetted pad are illustrated using the to fall to bottom; utilizing this new plung- operators to optimize production so that CFD post-processing, Fig. 18. er increases the amount of well uptime, each run delivers a similar fluid volume. In Fig. 19, two cut plots map the pres- resulting in more production. On one highly-deviated 8,000-ft well sure for two plunger designs on a plane that The Steady-Flo plunger incorporates in the Rockies, an operator was able to in- bisects through the center of the plunger a through-bore design, which allows the crease production 15% by replacing a bar (warm colors indicate areas of high pres- plunger to find a hydrostatic equilibrium stock plunger with the Steady-Flo plung- sure, cool indicate low pressure). The new point in the wellbore by slipping fluid as er. In another near-by well with low reser- jetted pad plunger features a hollow bore the plunger rises. With this design, the voir pressure, an operator was required to with holes that jet fluid from the bore to plunger uses the well’s available energy inject compressed gas to effect fluid pro- the underside of the pads. As a principal of to produce an even amount of fluid on duction. After installing the Steady-Flo fluid dynamics, flow travels from high pres- each plunger cycle, resulting in consis- plunger, the operator was able to elimi- sure to low pressure. Here, the high pres- tent removal of the fluid load from the nate compressor use. Fluid production sure fluid in the bore exerts an outward wellbore. This helps eliminate the situa- stabilized at 45 bpd and gas production force on the pad as it leaves the jet before tion of having a well that might bring in a increased by 120% to 220 Mcfd. slipping under the upward side of the pad.

74 JUNE 2014 / WorldOil.com Article copyright © 2014 by Gulf Publishing Company. All rights reserved. Printed in U.S.A. Not to be distributed in electronic or printed form, or posted on a website, without express written permission of copyright holder. PRODUCTION TECHNOLOGY

While pressure cut plots are useful for ALRTC adjacent to artificial lift manufac- for over 12 years. Previously, he was V.P. of marketing at GEO International Corp. He also examining how certain features enhance turing allows engineers from R&D, manu- held key marketing positions at Halliburton. He a plunger’s seal, a more intuitive way to facturing, and the company’s quality and has written numerous articles on subjects, such as expandable sand screens, intelligent wells, observe the flow direction and patterns is reliability teams to work synergistically to: UBD, drilling with casing, perforating, artificial by looking at flow trajectories. One of the • Accelerate new product develop- lift systems, fracturing conductivity and features of flow trajectories is being able to ment and commercialization proppants. He attended Texas A&M University and received his BS degree from the University select an area and see only the flow that in- • Conduct total system integration of North Texas. teracts with that area: where it came from testing prior to field installation and where it’s going. • Test alternative intervention meth- JAMES F. LEA teaches courses in artificial lift and production The flow trajectories demonstrate that ods to mitigate change-out costs for Petroskills. He holds BS and flow is inducted into the bore of the plung- • Meet material traceability require- MS degrees in mechanical er and forced out of the holes. It shoots ments. engineering from the University of Arkansas, and a PhD from through the jet holes against the underside The ALRTC features equipment and Southern Methodist University. of the pad, mushrooming, and slips out to- system testing options in a wide variety He worked for Sun Oil as a research engineer from 1970 to 1975, taught at the University of wards the fishing neck. The flow through of simulated downhole conditions. At Arkansas from 1975 to 1978, was team leader of the jets clearly pushes the pads outward. the center’s core are vertical test wells production optimization and artificial lift at This closes the gaps created by collapsed of various diameters and depths to test Amoco EPTG from 1979 to 1999, and was chairman of Texas Tech University’s petroleum pads, increasing efficiency. everything from a single ESP system engineering department from 1999 to 2006. He component to the full production sys- has contributed to this series for over 25 years. OTHER DEVELOPMENTS tem comprised of artificial lift and other HERALD W. WINKLER is Baker Hughes recently opened a well equipment. former chairman and now a $60-million electrical submersible pump professor emeritus and research and development facility in Clare- JOE D. WOODS is president of research associate in Texas International Pinpoint, a Tech University’s Petroleum more, Okla., Fig. 20. The 80,000-sq ft facil- marketing and technical Engineering Department in ity is called the Artificial Lift Research and information company in Lubbock, Texas. He also works Technology Center (ALRTC). It is next to Houston. Mr. Woods has over as a consultant to the industry in artificial lift, 35 years of energy industry specializing in gas lift. Early in his career, he the company’s manufacturing center. Ac- experience. He was director of worked for ARCO and Camco. He, too, has cording to company officials, locating the marketing and associate publisher at World Oil contributed to this series for over 25 years.

Article copyright © 2014 by Gulf Publishing Company. All rights reserved. Printed in U.S.A. World Oil / JUNE 2014 75 Not to be distributed in electronic or printed form, or posted on a website, without express written permission of copyright holder.