Artificial Lift Basics and Advancements Including Remote Monitoring and Reducing Electric Consumption

Based on a workshop sponsored by PTTC's North Midcontinent Region on September 12, 2000 in Wichita, Kansas

BOTTOM LINE

The information presented during the workshop provided attendees with the opportunity to refresh their knowledge of basic artificial lift concepts, while exposing them to new developments with the several different types of lift systems (beam pumps, electric submersible pumps, progressing cavity pumps, long-stroke pumps). A central philosophy in modern artificial lift is that pumps/systems are optimized, not just used. Optimization increases performance, reduces costs and failures, and generally increases production.

PROBLEM ADDRESSED

The artificial lift operations which are integral to production, especially in mature producing areas like the U.S., often, due to time limitations, do not get the attention required to maintain, let alone optimize, their performance. With limited time, it is also difficult to stay abreast of new advancements that could apply to one's situation. Bringing together speakers and material that provides refresher training on artificial lift as well as new options/choices offers value to busy independents.

KEY WORDS:

Beam Pumps, Field Automation, Power Cost Savings, Progressing Cavity Pumps, Rota-Flex Long Stroke Pumps, Submersible Pumps

SPEAKERS

Rota-Flex Long Stroke Pumping Unit
Susan Beck, Weatherford International

Electric Cost Savings Issues in Oil Production
Robert Egbert, Wichita State University

Electric Submersible Pumps
Stan Herl. Reda Pump

Progressing Cavity Pumps
Walt Pearcy and Jim Murrow, Wilson Supply

Sucker Rod Pumping Design & Implementation
Rodney Reynolds and Dwayne McCune, NMC PTTC

Modern Management of Artificial Lift Wells
Dieter Becker, Echometer Company

Using Software for Full-field Automation and Analysis
Steve Slezak, Case Services, Inc.

Sucker Rod Pumps
Lewis Watts, Harbison Fischer

TECHNOLOGY OVERVIEW

Artificial lift technology covers a broad spectrum involving several types of pumps-beam pump, electric submersible pumps, and progressing cavity pumps. Each type has its optimum application environment, and there are many nuances to be learned with each type. Industry speakers covered a myriad of topics related to advanced artificial lift.

Beam Pumps. Staff from PTTC's North Midcontinent Region described software, both freeware and commercial, that is available to assist operators with beam-pump design and analysis. Freeware programs available through SPE include (1) PUMPSPE, (2) APIROD, and (3) APIPUMP. Lufkin Industries, Inc. provides a basic rod loading program LOADCALB. In a similar vein, Echometer Company's QROD can be downloaded from their website (http://www.echometer.com). Integrity Consulting provides a spread-sheet based pumping unit design program within its Petroleum Engineering Tool Kit, which is relatively low cost. Higher-end commercial programs from Theta Enterprises, Inc. include RODSTAR and XDIAG. Additional handouts provided information on recommended plunger sizes for different conditions, rod sizes and properties, and motor properties, plus a copy of API RP11L (Recommended Practice for Design Calculations for Sucker Rod Pumping Systems).

Harbison-Fischer has developed different pump designs for different pumping environments-excessive gas, high solids or particulates, or high fluid volumes. There are two specialized pumps for gas locking conditions. The two-stage hollow valve rod pump overcomes most gas locking conditions and can handle moderate quantities of sand or other particulates. The gas chaser pump is designed for the very worst gas locking problems. Pump choices for high solids conditions include the Pampa pump, the Texas stripper pump (keeps sand from settling during shutdown periods), and the three-tube pump. The three tube pump is the traditional "trash" pump for extremely abrasive or dirty production. Oversize tubing or double displacement pumps are designed for high volume applications.

Progressing Cavity Pumps. Progressing cavity pumps consist of two helical gears, one inside (rotor) the other (stator), rotating along their corresponding longitudinal axis. As the rotor rotates eccentrically within the stator, a series of sealed cavities are formed, progressing from the intake to the discharge. Pressure capabilities of the pump are a function of the number of stages or seal lines. Pump capacity is a function of the rotor diameter, rotor eccentricity or offset and pitch length. Pitch length is defined as a length of one complete rotation of the crest trace of one of the helix lobes. Lifting capacity is referred to in feet of water, rather than stages. One stage is approximately equal to 231 feet of lift. Thus, an 18-stage pump is commonly referred to as a 4,000 foot pump. The external gear (stator) has one more tooth than the internal.

PCPs are highly efficient, exhibiting efficiencies greater than 60%. One of the reasons PCPs are efficient is because the frictional horsepower is low. Friction losses occur due to rotor/stator compression fit and speed. Compression fit is affected by downhole temperature, swell, and speed. Slip is another factor in PCP operation. As cavity pressure increases beyond seal limits, seal lines will deform and fluid will "slip" from one cavity to the next at very high velocities. Slip is dependent upon the number of stages, fluid viscosity, and the fit of the rotor in the stator. In most cases, slip is independent of speed.

PCPs have several advantages. They are simple in design, can handle solids and high viscosity fluids, do not emulsify fluids, and exhibit high volumetric efficiencies. Production capacities are limited to around 3,000 bfpd. PCP design factors include: (1) lift head requirement, (2) production rate, (3) API gravity and viscosity of oil, (4) gas, sand and water cut, (5) H2S and CO2 concentrations, and (6) well geometry/components. Elastomers can be incompatible with certain fluids, including greater than 12% aromatics, H2S > 6%, CO2 > 30%, and some chemical additives. Chemical compatibility can be tested in the laboratory. Conventional elastomers are stable to 210 °F, while special elastomers allow operations to 300 °F. Rod guides should be considered in deviated wells, high water-cut wells, high rpm applications, when used for coalbed methane dewatering, or if there is a history of rod/tubing wear. When pump failures occur, common mechanisms include, for the rotor, abrasive wear and fluid incompatibility. For the stator, failure mechanisms include (1) abrasion/wear/high pressure wash, (2) overpressure/hysterisis, (3) fluid incompatibility/chemical attack, (4) high operating temperature, and (5) mechanical damage.

Rota-Flex Long Stroke Pumps. The 24-foot stroke length of the Rota-Flex pumping unit gives the pump high production capability, up to 2,200 bpd from 4,000 feet with the RF1100 unit, making it an alternative for submersible pumps in some situations. Its 60% system efficiency is attractive when compared to the 30 to 40% efficiencies experienced with electric submersible pumps. This efficiency, plus other mechanical considerations, makes it a cost-effective alternative for deep, troublesome and high-volume wells. With a 40 to 60% reduction in rod reversals, rod life is extended. Power costs are typically 20 to 50% less and peak power demand is lowered. Its 100% mechanical design makes it low maintenance. It can be folded over for shipment as a single piece and can be quickly rolled away from the wellhead for easy well access. The strokes per minute (SPM) can be varied from 1 to 4.5. With the vector drive option, SPM settings are adjustable at constant speed, the maximum average SPM can be increased from 4.5 to 5.2 with two-speed operation, and adjustable upstroke and downstroke SPM settings can be made for heavy crudes. The speed sentry displays operating SPM, has underspeed and overspeed shutdowns, and engages the emergency brake after a speed violation.

Submersible Pumps. Reda Pump highlighted several areas where advanced technologies in artificial lift can be helpful. Their Advanced Gas Handler (AGH) can improve the producing economics of reservoirs with high volumes of associated gas. The AGH can increase flow rate by increasing drawdown, reduce downtime and restarts caused by gas locking, and allow production of reservoir fluids in a common flow line. Unlike gas separators which lower the vapor:liquid ratio (VLR) by redirecting the vapor to another production flow path, the AGH ingests and commingles all the fluids, both gas and liquids, to raise the VLR that can be pumped.

Reda's Horizontal Pumping System (HPS) adapts the same pump used downhole for "horizontal" surface applications, such as water injection or crude oil transfer. Since initial testing of the concept in 1987, over 1,000 units have been installed worldwide. A HPS has the following components: (1) "I" beam and square tubing skid, (2) electric motor, (3) diesel/natural gas engine, (4) thrust chamber, (5) multi-stage centrifugal pump, and (6) electrical controls. They are quiet and produce less vibration. They can be delivered within a month after the motor is delivered to Reda and minimal site work is required for installation. A HPS requires only minimal maintenance-change oil in the thrust chamber every six months and follow manufacturer's recommendations for motor maintenance. Pumps can be changed out within two hours, and when repair is required, units can typically be repaired in Reda's Service Centers within 24 hours. Units can be operated in series or parallel. Worldwide, about five million bwpd are being injected using HPSs.

Modern Beam-Pump Management. Three pieces of information are required to effectively manage beam pumps-overall efficiency of the system, reservoir performance and mechanical loading. Echometer, and others, have developed computerized systems to obtain this information. These systems measure liquid level, on both a single and multi-shot basis, obtain dynamometer cards, and analyze power. Single acoustic shots can determine liquid level, while multiple shots versus time are required for pressure transient analysis. Pressure transient analysis enables one to calculate reservoir properties, such as pressure, skin factor and permeability. A key aspect of dynamometer card measurements is pump fillage, which can reveal gas locking problems. Motor power measurements help analyze balance, and computerized reports provide information about motor sizing, unit balance, power factor, and efficiency.

Field Automation. Production field automation provides an environment where production costs can be reduced and total production maintained or increased. Typical systems provide four primary functions: (1) basic status, (2) alarming, (3) trending, and (4) control. Advancing computer and communications technology, combined with continued staff reductions and productivity improvements, make production field automation increasingly attractive where operations are concentrated. Automation reduces both the time required for manual reporting and the errors inherent with manual monitoring. Trending functions, that is, software functions that compare current readings/performance with historical data, allow producers to quickly see, and sometimes preclude, problems.

Industry reports benefits from production field automation. One production supervisor reports reducing his trips to the field from weekly to monthly. An industry operator near Denver City, Texas, whose operations were concentrated, organized field operations into teams responsible for a group of wells and facilities. Each team includes a well analyst, an injection flood analyst, a lease operator, a rig supervisor, and a technician. Each analyst is responsible for optimizing more than 220 wells. Injection flood analysts spend several hours each day looking for exceptions. Communication with the field is greatly enhanced. In January of 1996, before installing automation and the team environment, there were 36 beam-pump failures. In May of 1997, after the changes were made, failures dropped to 15, representing a significant reduction in repair costs and lost production. The operator was also able to reduce the number of repair rigs from 30 to 13.

Electrical Power Cost Savings. To reduce energy costs, one must look at the pumping unit as a complete system. Problems in any subparts (meter, power factor correction, switch gear, conductors, motor, belts, gearbox, balance system, bearings, stuffing box, pump valves) can be costing dollars. Another key concept is to look for the forest, not the tree. Energy required to raise fluid to the surface is called the Energy Intensity Index (EII). EII equals (meter kWh x 1000) divided by (bbl-ft/day x billing days per month). The theoretical minimum for EII is 0.13 kWh/bbl/1,000 ft. Anything else is losses. By calculating the EEI for each power meter, one can identify those applications having high EIIs. A well-tuned pumping system may exhibit an EII as low as 0.20. Actual numbers in Kansas range from 0.20 kWh/bbl/1000 ft to 1.6 kWh/bbl/1000 ft.

In performing an energy assessment, a good first step is to start with the account bills. Questions to ask include: Do rate schedule changes invite savings? If on time-of-day schedule, it may be possible to turn pumps off during high rate periods. Is a power factor penalty being paid? If you are being charged a power factor penalty, the capacitor is probably incorrectly sized. An energy professional can help determine the amount of correction needed and the cost and savings to eliminate the penalty. The switch gear and conductors should be inspected to determine if connections are solid or hot spots exist. Conductors should be appropriately sized.

The different components of the beam pump should be inspected. Motors should be checked for general condition, noise and vibration, lubrication and size. When purchasing motors, consider efficiency, not just lowest cost. Broken, cracked or falling belts cost power. When replacing belts, use energy-efficient cogged v-belts. Although they cost more, they last longer and do create energy savings. If gears are worn, energy savings may result from reversing the direction of rotation. When reversing gear rotation, one must check to see that the inside oiling mechanism still works properly. A simple ammeter measurement can be used to check unit balance. Bearings and stuffing box also need to be checked.

CONNECTIONS:

Susan Beck
Weatherford International
1231 Greenway Drive, Ste. 960
Irving, TX 75038
Phone: 972-751-8950 Fax: 972-550-0707
E-mail: susan.beck@weatherford.com

Robert Egbert
Wichita State University
1845 Fairmont 
Wichita, KS 67260
Phone: 316-978-3140 Fax: 316-978-5509
E-mail: bobe@ece.twsu.edu

Stan Herl
Reda Pump
11133 NW 10th St.
Yukon, OK 73099
Phone: 405-354-7070 Fax: 405-354-7074
E-mail: sheri@slb.com

Walt Pearcy
Wilson Supply 
R.R. 5 Box 55
Chuckasha, OK 73023
Phone: 405-224-2757 Fax: 405-224-0944
E-mail: wpearcy@wilsononline.com

Steve Slezak
Case Services, Inc.
738 Hwy 6 South, Ste. 800
Houston, TX 77079
Phone: 281-497-0242 Fax: 281-497-0683
E-mail: steve@caseservices.com

Lewis Watts
Harbison Fischer
P.O. Box 978
El Dorado, KS 67042
Phone: 316-321-5940 Fax: 316-321-5525 

Dieter Becker
Echometer Company
5001 Ditto Lane
Wichita Falls, TX
Phone: 940-767-4334 Fax: 940-723-7507
E-mail: dieter@echometer.com

For information on PTTC’s North Midcontinent Region and its activities contact:
Rodney R. Reynolds, Project Manager, Kansas University Energy Research Center,
Tertiary Oil Recovery Project, University of Kansas
1930 Constant Ave., Lawrence, Kansas, KS 66047-3726
Phone: 785-864-7398 , Fax: 785-864-7399, E-mail: reynolds@cpe.engr.ukans.edu

Disclaimer: No specific application of products or services is endorsed by PTTC. Reasonable steps are taken to ensure the reliability of sources for information that PTTC disseminates; individuals and institutions are solely responsible for the consequences of its use.

The not-for-profit Petroleum Technology Transfer Council is funded primarily by the US Department of Energy’s Office of Fossil Energy, with additional funding from universities, state geological surveys, several state governments, and industry donations.

Petroleum Technology Transfer Council, 2916 West T. C. Jester, Suite 103, Houston, TX 77018
Toll-free 1-888-THE-PTTC; Fax 713-688-0935; E-mail hq@pttc.org; web www.pttc.org