Topic last reviewed: 1 February 2014
Sectors: Upstream
Oil and gas production wells generally produce their highest production rates at the beginning of the production cycle, after which the production naturally begins to decline. Most wells produce in a predictable pattern called a decline curve. Depending on the underground pressure, the natural flow of oil and gas can last from a few to many years. When the pressure differential is insufficient for the oil to flow naturally, some method of lifting the liquids, such as mechanical pumps, must be used to bring the oil to the surface. The technology used to increase production is referred to as artificial lift.

Artificial lift technologies are wide and varied. The term artificial lift applies to numerous tools, equipment, controls, instruments, computer hardware and software, technologies and techniques used to increase the flow of liquids (usually crude oil, water or a mix of oil and water along with natural gas) from a production well. Electric energy is often the most significant cost component in the production of oil and gas. Energy consumption, production rate and equipment lifetime all have a significant impact on the overall cost of production. Investment in more efficient energy technologies is often the most cost-effective way of improving the energy return on investment (EROI) and cutting emissions of greenhouse gases (GHG). Energy efficiency of a broad number of artificial lift systems that are currently being used to increase production is the focus of this paper.

Oil Wells

Several forms of artificial lift are used for oil wells including plunger lift, sucker rod, gas lift, progressive cavity pumps and electric submersible pumps (ESP). About 70% of the global crude oil production is derived from mature fields, of which most experience reservoir pressure deficiency, which is a crucial production parameter. Accordingly, more than 90 percent of producing wells require some kind of artificial lift or secondary production method.

Growing production in some parts of the world such as Canada promise a growth in artificial lifts for other applications. While artificial lift technologies are typically associated with mature fields, the technologies are used for a wide variety of wells, from high-rate deep water wells with subsea infrastructure to the oldest wells in the oldest fields. The relative energy efficiency of the various forms of artificial lift requires a closer look at the pumping requirements served by each type of lift. The relative energy efficiency of the pumping systems used for the various systems will depend on many factors including the depth of the wells, the utility rate of electricity and the amount of water contained in the liquids being pumped.

Sucker Rod Pumps

This method uses a surface power source to drive a downhole pump assembly. Beam and crank assembly at the surface (pump jack) creates reciprocating motion, which is converted to a vertical motion in a sucker-rod string that connects to the downhole pump assembly. See Figure 1 for a schematic of the Beam Pump. The pump contains a plunger and valve assembly to impart vertical fluid movement. Roughly two-thirds of the producing oil wells around the world use this type of lift. The limitations of this system arise with deeper and different types of wells. Sucker rod pumps are not generally considered applicable to offshore installations. A long –stroke pumping unit for sucker-rod pumps has been developed by Weatherford [Reference 1] that provides greater efficiency and cost-effectiveness for pumping deep, troublesome, and high-volume wells.

Figure 1. Beam or Sucker Rod Pump (Source: Calsac Corporation)

Sucker Rod Pumps

This method uses a surface power source to drive a downhole pump assembly. Beam and crank assembly at the surface (pump jack) creates reciprocating motion, which is converted to a vertical motion in a sucker-rod string that connects to the downhole pump assembly. See Figure 1 for a schematic of the Beam Pump. The pump contains a plunger and valve assembly to impart vertical fluid movement. Roughly two-thirds of the producing oil wells around the world use this type of lift. The limitations of this system arise with deeper and different types of wells. Sucker rod pumps are not generally considered applicable to offshore installations. A long –stroke pumping unit for sucker-rod pumps has been developed by Weatherford [Reference 1] that provides greater efficiency and cost-effectiveness for pumping deep, troublesome, and high-volume wells.

Hydraulic Pumping

With this technology, a downhole hydraulic pump, rather than sucker rods, are used to lift oil to the surface. The production is forced against the pistons, causing pressure and the pistons to lift fluids to the surface. The natural energy within the well is used to raise the production to the surface. Hydraulic pumps can be water-jet, turbine, or piston based. Piston pumps are generally composed of two pistons, one above the other, which are connected by a rod that moves up and down within the pump. Both the surface and subsurface pumps are powered by oil, water or clean oil that has previously been removed from the well. The surface pump sends power oil through the tubing string to the subsurface pump which sends the reservoir fluids up a parallel tubing string to the surface. Figure 2 shows the schematic of hydraulic pumping.

Figure 2. Hydraulic Pump (Source: Schlumberger)

Gas Lift

With gas lifts, compressed gas is injected down the casing tube annulus of a production well, entering the well at numerous entry points called gas-lift valves. The injected gas reduces the pressure on the bottom of the well by decreasing the viscosity of the fluids in the well. This, in turn, encourages the fluids to flow more easily to the surface. Typically, the gas that is injected is recycled gas produced from the well. With very few surface units, gas lift is the optimal choice for offshore applications. As the gas enters the tubing at these different stages, it forms bubbles, lightens the fluids and lowers the pressure. Gas lift is an artificial lift process that closely resembles the natural flow process and basically operates as an enhancement or extension of that process. Figure 3 shows a schematic of the gas lift system.

Figure 3. Gas Lift Schematic (Source: Tech Flo Consulting LLC)

Most applications of this technology involve the use of reservoir gas that is re-compressed for use as a lifting gas For very low gas to liquids ratios (GLR) this may not be feasible and another supply of gas may be necessary. Gas lift systems that inject gas into crude are sometimes used in conjunction with surface operating reciprocating pumps or horizontal centrifugal pumps. These systems require a supply of gas to be stored at the surface or the use of gas produced as lifting gas (by re-compressing). This requires additional compression capacity, which typically has high capital costs. In this type of system maintenance costs can also be high. Older gas-lift systems with high water cut are frequently being converted to ESP systems.

Electric Submersible Pumps (ESP)

Electric submersible pump (ESP) systems employ a centrifugal pump below the level of the reservoir fluids. The pumps are composed of several impellers, or blades that move the fluids within the well. The whole system is installed at the bottom of a tubing string. An electric cable runs the length of the well, connecting the pump to a surface source of electricity. Figure 4 shows a schematic of the ESP.

Figure 4. Electric Submersible Pump (Source: Schlumberger)

Because ESPs can work with a variety of flow rates and depths, they are well-suited to work inside oil wells. When used accurately, an ESP pump can decrease well pressure at the bottom, enabling the withdrawal of a higher amount of oil than otherwise could be extracted under normal pressure conditions. Over the last several years, ESP technology has developed a reputation as a low-maintenance, cost-effective alternative to other surface applications in the petroleum industry. As a rule, ESPs have lower efficiencies with significant fractions of gas, typically greater than about 10 percent volume at the pump intake. As the amount of gas in the fluid approaches 10%, gas lock can occur. ESPs have been deployed in vertical, deviated and horizontal wells, but they should be located in a straight section of casing for optimum run life performance. On a cost-per-barrel basis, ESPs are considered economical and efficient.

Progressive Cavity Pumps

This technology is similar to the ESP in that progressive cavity pumps (PCPs) consist of a helical bore that rotates inside a similar helical cavity. The rotation of the bore creates cavities with negative pressure (vacuum) to open and close, forcing fluid up through the pump body. This technology has proven performance in crude oil at high viscosity. However, PCPs are vulnerable to damage from abrasive materials and are generally limited to well depths of approximately 5000 ft. and are limited to typical wells (e.g. wells without deviated or horizontal wellbores). The basic surface-driven PCP system configuration illustrated in Figure 5.

Gas Wells

In mature gas wells, the accumulation of fluids in the well can impede and sometimes halt gas production. A common approach to temporarily restore flow in a gas well is to vent the well to the atmosphere which produces substantial methane emissions. At different stages in the life of a gas well, alternatives to repeated venting are deployed such as shutting-in the well to allow bottom hole pressure to increase, swabbing the well to remove accumulated fluids and installing an artificial lift system. Following are the primary artificial lift systems

Plunger Lift

Plunger lifts are commonly used to lift fluids from gas wells. A plunger lift system is a form of intermittent gas lift that uses gas pressure buildup in the casing-tubing annulus to push a steel plunger and a column of fluid above the plunger up the well tubing to the surface. A valve mechanism and controller at the surface cause gas volume and pressure to build up in the wellbore initiating the plunger release cycle. At this point, the surface valve closes and the plunger drops to the bottom of the well. Once adequate pressure is reached, the surface valve opens and the plunger rises to the surface with the liquid load. Insufficient reservoir energy or too much fluid buildup can overload a plunger lift. When that occurs, venting the well to the atmosphere (well blowdown) instantaneously reduces the backpressure on the plunger and usually allows the plunger to return to the surface. Again, this can cause significant releases of methane emissions.


Some gas reservoirs can produce a high amount of liquid, but because gas can damage ESPs, care must be taken when using an ESP to remove liquid from a gas well. However, ESP systems can be designed that enable the gas to flow freely up the pump’s casing, while the pump efficiently removes fluid. The gas flow depends largely on casing head pressure. Care must be taken sufficiently research the exact well situation for such uses before an ESP method is employed.

In the Western US, downhole submersible pumps are used for Coal-bed Methane (CBM) wells. There are an estimated 30,000 producing CBM wells in the US. Most coal seams with gas in commercial quantities contain water that is Taproduced along with the gas. The coal zones typically require local or regional dewatering before commercial gas production can be achieved, and the key to economic production is cost-effective reservoir dewatering techniques. This has inherent problems as flows decrease, methane gas increases and coal fines are introduced into the wellbore. Traditionally, electrical submersible water well systems and rod-driven progressing cavity pumping systems (PCPs) have been employed to dewater CBM wells. However, reliability has been an issue with water well equipment, while cost considerations have stymied PCP and more rugged oilfield electrical submersible pumping systems. Newly designed hybrid ESP systems are more robust than water well systems are now being used for CBM wells (see Alternative Technology section)


PCP systems have been used in CBM wells since 1986, both as the primary dewatering system and as a solution for troublesome wells, since PCPs can effectively pump coal fines, sand particles and gaseous fluids. Plus, PCP is a positive displacement system with the output rate directly tied to the speed of the pump. This feature allows the system to be adjusted via pump speed to match the decline curve of the water production, eliminating over-pumping the well.

Artificial Lift System Efficiencies

Artificial lift systems are served by separate pumping requirements. The use of more efficient pumping systems can have a significant impact on the cost of artificial lift systems. Optimizing production and decreasing costs require not only consideration of individual well characteristics and a lift system operational capabilities but also the cost of electricity.

Table 1 provides limitations for the selection of the type of artificial lift selected as well as overall system efficiencies [Reference 2]:

Rod PumpProgressive CavityGas LiftPlunger LiftHydraulic PistonElectrical Submersible
Operating Depth (ft TVD)100-16,0002,000-6,0005,000-15,0008,000-19,0007,500-17,0001,000-15,000
Typical Operating Volume (BPD)5-5,0005-4,500200-30,0001-550-4,000200-30,000
Operating Temperature (°F)100-50075-250100-400130-500100-500100-400
Corrosion HandlingGood to ExcellentFairGood to ExcellentExcellentGoodGood
Gas HandlingFair to GoodFair to GoodExcellentExcellentFairPoor to Fair
Solids HandlingFair to GoodExcellentGoodFairPoorPoor to Fair
Fluid Gravity (°API)>8<35>15GLR required 300 SCF/BBL>8>10
Build Angle<15°/100’<15°/100’N/AN/A<15°/100’<10°/100’
ServicingWorkover or Pulling RigWorkover or Pulling RigWireline or Workover RigWellhead Catcher or WirelineHydraulic or WirelineWorkover or Pulling Rig
Prime MoverGas or ElectricGas or ElectricCompressorWell’s Natural EnergyMulticylinder or ElectricElectric Motor
Overall System Efficiency (%)45-6040-7010-30N/A unless compressed gas added45-5535-60

Table 1. Limitations for Selection of Artificial Lift Method (Source: Halliburton)

A comparison of four different types of pumping systems used in artificial lift is shown in Table 2 [3]. The table provides insight into the most efficient systems and therefore a relative sense of the efficiency of the pumping systems. The comparison is based upon a 5,000 ft well, a utility rate of $0.06 per kWh and 90% water cut.

ing System

Pumping Speed (rpm)

Production Rate (bpd)

Input Power (kW)

Lift Power (kW)

Energy Efficiency (%)

Cost per Barrel ($)

Sucker Rod








































































































































Table 2. Artificial Lift Comparison Summary (Source: Gas Automation Solutions)

Technology maturity

Commercially available?:Yes
Offshore viability:Yes
Brownfield retrofit?:Yes
Years experience in the industry:21+

Additional notes

Plunger Lift - 20 + years but Electronic supervision, automation and optimization have created options that were not possible just a few years ago

Sucker Rod Pumps - 20+ years but sophisticated rod string design and better rod and coupler materials as well as pump rod controllers has made use of the technology more tolerable to rod dynamics in recent years. Recent improvements in motor technology and use of VFDs has helped improve efficiency

Hydraulic Pumping – 20+ but recent use of natural gas rather than diesel fuel as well as dual fuel has significantly reduced costs as well as emissions

Gas Lift - 20+ years but emerging technology being used for offshore applications due to few surface units. Represent about 10% of US market

ESP – 20+ years but are the fastest growing pumping technology. Represent about 15 to 20 percent of worldwide market. Monitoring, diagnosis and control have proven to maximize efficiency in recent years. Hybrid ESP/PCP systems have recently been developed. These systems facilitate the handling of viscous and abrasive fluids, increase the flow rate as well as improve efficiency

PCP – 20+ years for both on-shore and off-shore applications. In recent years, use of efficient permanent magnetic motors and innovative torque converters has shown gains in efficiency and costs as well as use in more diverse environments. Motor technology and use of VFDs – 5 to 10 yrs. Use of these technologies have helped improve efficiency


Specific Gravity
Efficiency 100%0.1320.1230.1160.109

Key metrics

Range of application:Conventional crude production, CBM wells, deep and ultra-deep offshore production, rehabilitation of fields and redevelopment of mature fields
Efficiency:Power consumption for artificial lift technologies are a factor of the production, depth of well and API gravity. Lift factors (kWh/bbl) are shown in Table 3
Guideline capital costs:Investment costs for ESP, hydraulic and gas lift higher than other technologies
Guideline operational costs:Operational costs can be significant, however increases in efficiencies can offset operational costs and in some cases result in a cost savings (see Table 4)
GHG reduction potential: Oil Wells: Increase in GHG unless methane captured by vapor recovery device Gas Wells*: Savings from avoiding well venting/blowdowns up to 250 lbs/well/year [5 Increase in Production could increase GHG by up to 1400 lbs/well/year [5] however improvements in efficiency could offset any increases
Time to perform engineering and installation: 1 month to 6 months depending on the specific installation
Typical scope of work description:The scope of work begins with the identification and collection of data to determine the type of artificial lift needed to address a production problem or a new application that deviates from a conventional well. For example, to convert a gas lifted well to ESP would include an analysis of the installation costs, de-completion costs, sand control problems, well inflow performance, electrical power requirements and well bore trajectory. This would be weighed against the higher production rate of the ESP, the use of gas lift as a backup and benefit of no gas compression and reduction of NOx emissions among other benefits of the ESP system. Additionally, intervention is now a significant concern.

Decision drivers

Technical: Footprint: Some physical-constrained land locations or offshore platforms may not be able to accommodate a particular type of lift. Additionally the lift must physically fit into the production casing, liners and/or open hole
Wellbore configuration: Is the well bore of a different configuration such as horizontal, or dog-leg. Such deviations can eliminate or reduce the effectiveness of various lift types
Desired rate vs. depth: Some lift types have rate limitations while others have depth limitations. Basically, the achievable rate decreases as the depth increases. This is due to power requirements, equipment overload, pressure limitation, temperature limitations and/or total dynamic head needs
Temperature: Most types of lifts have an upper temperature limits, since over-heating of an electrical component or material degradation could cause equipment failure
Fluid make-up properties: Gas-to-liquid (GLR) ratio, chemical properties, solids/sand all must be evaluated for compatibility with the type of artificial lift technology. Some technologies have work with higher GLR while other have low tolerances. Hydrogen sulfide and carbon monoxide can have a negative impact on lift types that employ elastomers and the technologies vary in the amount of sand that can be tolerated
Infrastructure: Some lift types require electrical power while others require a reliable source of natural gas. The availability and cost of infrastructure is an important metric
Pumping Systems: Use of more efficient pumping systems can result in cost savings as well as GHG emission reductions
Operational: System service and support generally involves the manufacturer of the equipment, those who install and maintain the equipment and those who will be operating the equipment. Lack of this metric can be a determining factor. Table 4 provides a comparison of different methods and specific operational issues
Commercial: Specific technologies may require examination as to number of wells, the specific type of activation desired and specialized suppliers to meet needs. Overall commercial availability should be based on suppliers of the technology
Environmental: Improved efficiencies will not only reduce cost but can lead to reductions in Methane Emissions (GHGs), nitrogen oxides (NOx), carbon monoxide (CO), volatile organic compounds (VOCs), and particulate matter (PM).
Economic rule-of-thumb: Table 1 provides limitations of each lift system and its overall efficiency. Table 2 provides a cost comparison of difference lift systems based upon a 5,000 ft well, a utility rate of $0.06 per kWh and 90% water cut. On a cost per barrel, ESP and PCP systems are higher particularly at lower pumping speeds and production rates. While costs per barrel of production are higher for PCP and ESP systems the costs can be offset by improvement in Efficiency

Additional comments

Note: X indicates high initial capital cost. XX indicates very high initial capital cost

Table 4. Advantages and Shortcomings of Each Artificial Lift Technology (Source: Canadian Oilwell Systems Company Ltd.)

Optimizing production of an entire field can demonstrate the incremental production between optimized rates and baseline rates as shown in Figure 6 below. Added value can result from reduced operating costs and lower capital costs per barrel of production as well as significant increased production.

Figure 6. Incremental Production from Field Optimization (Source: Fleshman, Obren Lekic)

Recent developments

In recent years, the emphasis has been on lowering the operational costs of production systems and optimizing well performance. This has required focused application engineering, proper system selection, the development of more efficient installation or deployment techniques and improved operational efficiencies of existing technologies. Moreover, there has been a growing emphasis on the timely monitoring, communicating and analyzing of well performance and production data. While the benefits of each technology cannot in itself be quantified, all the technologies are designed to optimize performance and reduce operating costs Following are a few of the most recent developments (The topic of power systems is also the subject of other topic papers):

Power Systems

  • A single centrifugal compressor coupled to a single radial turbine, driving a high load-capability synchronous generator through a speed reduction planetary gearbox. The design allows for high tolerance for source gas, significantly lowers emissions compared to the typical diesel-fired generator and is available for offshore, arctic, and tropical environments. [Reference 6]
  • Regenerative VSD Control – a low maintenance solution for a variable speed drive control that returns excess power back in its deliverable state (similar to hybrid vehicles with rechargeable electric motor). This system continuously monitors the equipment and production allowing for detection of any malfunctions and is applicable to heavy crude production, steam flood operations and situations where shutting down would adversely affect production operations. [Reference 7]
  • Use of higher efficiency motors such as the NEMA Design 'B' Motors which maintain exceedingly high breakdown and locked torque while providing the highest rated efficiency levels.
    Electric Submersible Pumps
  • To address issues with unconventional oil wells, this technology (Flex Pump) can handle dynamic well conditions and flowrates from 50 bpd (oil) to 10,000 bpd (oil). The pumps are more efficient than previous designs and improved uptime by reducing cyclic shut downs. They also run at lower temperatures reducing operating expenses[Reference 8]
  • Progressive Cavity Pumps (PCPs) are traditionally used at lower flowrates, combined with higher solids in heavy oil, in gas well deliquification and in shale and CBM well applications. The PCPs are traditionally driven to the surface via a rod system. The development of a torque drive system allows the deployment of a PCP that delivers power directly to the PCP downhole utilizing efficient permanent magnetic motors and innovative torque converters. This system reduces lifetime lifting costs, extends production life, and can produce with high gas, sand or solid content.[Reference 9]

Sucker Rod Pumps

  • The use of long-stroke pumping unit for sucker-rod pumps provides greater efficiency and cost effectiveness for pumping deep, troublesome, and high-volume wells. This technology is available for applications where ESPs or hydraulic subsurface pumps are used [Reference 1]. The Rotaflex unit reduces stress on equipment because the rod string is operated at relatively constant velocities. Constant velocity and fewer strokes per barrel increase the lift span of the pumping unit, downhole pump and rod string.

Progressive Cavity Pump Systems

  • Hybrid artificial lift technologies, such as bottom-drive progressive cavity pumping, which combine features of the ESP and the PCP systems facilitate the handling of viscous and abrasive fluids, increases the flow rate, and diminish the operational costs. Advantages of this application also include the complete elimination of tubing wear by eliminating the rod string, greater torque capacity, lower surface maintenance, lower load and horsepower requirements, and less frictional losses thereby improving overall efficiency.

Hydraulic Pump Systems

  • Recent increases in oil production via shale plays has brought about interest in the use of jet pumps. While jet pumps have traditionally been considered high energy users, new technologies have been developed using gas from the well. New challenges with deviated wells, tons of corrosive sand and large volumes of flowback and produced fluids have made traditional lift solutions less efficient. The new designs make it easy to retrieve the pump from deviated and/or horizontal wells eliminating the need for workover rigs or crews to maintain the system. Overall, these systems have a lower lift-cycle cost over ESP and Rod pumps and have lower emissions due to the use of produced gas as a fuel.[Reference 10]

Well Monitoring/Remote Sensing

  • Intelligent Rod Rotator-remote sensing technology for beam/sucker rod lift systems that detects rod rotation, and allows the operator to make changes to increase efficiency and avoid premature failure. [Reference 11]
  • A new generation of wireless hardware and software (the TAM total asset monitor) that greatly improves and facilitates data acquisition of fluid level and dynamometer data for analysis of well performance. By providing operators a real-time visualization of what is occurring in the well and in the downhole pump, it is possible to observe system performance directly instead of having to interpret numerical and graphical displays [Reference 12]
  • Advances in the development of downhole sensors for in-depth diagnostics and analysis provide the ability to monitor beam/rod pumps, progressive cavity pumps (PCPs) and gas lift systems. Temperature, pressure, vibration, current-leakage and flow data are measured and recorded by an integrated surface panel (ISP). The benefits allows monitoring and control of gas lift wells, provides comprehensive analysis of conditions and ability to optimize future operations [Reference 13]
  • Downhole sensors to operate in both benign and corrosive environments, this technology increases equipment run life by detecting abnormal conditions, and helps prevent ESP from overheating and reducing premature failure of the pump as well as increases pump operating time. [Reference 14]

Chemical Treatment

  • Chemical Treatment-development of improved methods for delivering chemicals such as foaming agents and corrosion, paraffin and scale inhibitors to help optimize production rates. The deployment tool is preloaded with a proprietary blend of chemicals in solidified stick form. Depending on well conditions, the chemical sticks typically yield eight or more months of steady chemical release. [Reference 15]

Operational issues/risks

The method used to select an artificial lift system involves the development of a strategic plan based on well optimization. Proper selection of an artificial lift system should include an analysis of the individual well’s parameters and the operational characteristics of the available lift systems. Table 4 provides a comparison of the positive features and the shortcomings of the various lift systems. Analysis should start when reservoir, drilling and completion decisions are being made; not after the well has been drilled and completed. Different pumps and lift systems have unique operational/engineering criteria, but they all require similar data to properly determine application feasibility. Existing systems can show increase electric energy costs. Consideration of the following issues can lead to decisions that reduce high operating costs:

  • Decreased production, due to pump failure from gas-locking or solids production;
  • High operating costs, due to constant tubing wear and pump maintenance issues; and
  • Expensive workovers and lost production from excessive downtime.
  • High energy costs due to inefficient pumping systems

Opportunities/business case

Natural Gas Star Partners have reported that by avoiding or reducing well blowdowns, annual methane emissions savings range from 500 thousand cubic feet (Mcf) per well to more than 27,000Mcf/well. The benefit of increased gas production will vary considerably among individual wells and reservoirs, but can be substantial. Partners report that increased gas production following plunger lift installation yielded as much as 18,250 Mcf per well [Reference 5]. The EPA Gas Star Partners reported [Reference 16] that installation of a plunger lift system serves as a cost-effective alternative to beam lifts and well blowdown and yields significant economic and environmental benefits. The extent and nature of these benefits depend on the liquid removal system that the plunger lift is replacing. The following benefits are identified:

  • Lower capital cost versus installing beam lift equipment
  • Lower well maintenance and fewer remedial treatments
  • Continuous production improves gas production rates and increases efficiency
  • Reduced paraffin and scale buildup
  • Lower methane emissions

EPA’s Natural Gas STAR Partners report that “smart” well automated control systems for plunger lifts have reduced the labor cost for field monitoring by approximately $7,500 per well. Velocity tubing eliminates well swabbing, well blowdowns and chemical treatments, the cost of which are reported to range from a few thousand to more than $13,000 per treatment. Two Partners report implementing “smart” automation systems to control plunger lift operations.

Industry case studies

Systematic solution overcomes artificial lift challenges [Ref. 17]

The purpose of this study was to manage reservoir deliverability from the stimulated Eagle Ford Shale (South Texas) reservoir volume and increase production efficiencies. Electrical submersible pump (ESP) systems are used but the Eagle Ford shale play includes unique reservoir characteristics and fluid behaviors that are especially challenging in downhole conditions that include high temperatures, high gas volume, slugging, unsteady flow, paraffin and some scale deposits that complicate artificial lift solutions.

Magnum Hunter Resources Corp. (MHR) and Schlumberger teamed up to implement an unconventional ESP solution as part of a systematic approach to transitional lift. The production phase encompasses three main stages: initial production or natural flow, transitional artificial lift with the use of ESPs and traditional beam pump or gas lift for the remainder of the well life.

The operator well depths average 10,000 feet with laterals of 6,000 feet. At the companies Gonzo North 1H well, located in Gonzales County, production declined rapidly from March 2011, dropping from 913 b/d to 150 b/d in four months. The water rate declined from 836 b/d to 40 b/d in the same period. Following conventional design, an ESP system was installed in July 2011. Initial production was encouraging, but the uniqueness of the light fluid and unstable flow caused a decline in production over 20 days from installation, dropping production from 965 b/d to 339 b/d. The overheated ESP failed and two additional ESP motors with similar configurations were installed. These two ESP motors also failed in a short period of time. The failures prompted an investigation involving collaboration of Schlumberger experts to find a solution.

After careful study, a systematic approach was devised that included a customized ESP design, fit-for-purpose hardware configuration of downhole and surface equipment, real-time surveillance and control and performance analysis and optimization from experts dedicated to the project. The system was configured to provide maximum flexibility on flow rates and multiphase flow compression, abrasion-resistant pumps and mixed flow stages, Advanced Gas Handler devices, and Poseidon gas-handling devices all configured using a compression-type construction for extended operating ranges, variable rating motors and a SineWave variable speed drive to minimize potential harmonics and stress on the ESP electrical system. The LiftWatcher real-time surveillance and control service was also installed so personnel could monitor, configure and set alarms when both the ESP operation parameters and surface parameters that were connected to the motor controller as analog inputs. The LiftWatcher service enabled personnel to remotely adjust the ESP operating parameters, including the target pump intake pressure (PIP), to meet the controlled drawdown strategy.

The first unconventional system was installed in Sept 2011 and remained in operation until Sept 2012. Ideally, the ESP systems should operate continuously, but the system at Gonzo North 1H was shutting down several times a day to protect the system or when drawdown reached the lowest PIP. The excessive cycling raised concerns over the impact of the expected run life, so adjustments to the settings on the motor controller kept the ESP running for 21 consecutive days. No appreciable changes were noted in production and motor temperature increased only periodically. Cyclic operation resumed in late Nov 2011. The well would flow during the ESP off cycle at approximately 25% of the ESP on rate, creating a more efficient lifting system that reduced lifting costs with no significant effect on the overall production decline trend. Via the LiftWatcher, the operations teams received automated alerts by SMS or email when an operating parameter fell outside the defined threshold. The ESP system could be remotely adjusted to optimize system performance. The ESP accumulated an unprecedented 1, 478 starts, more than 10 times the starts of a typical ESP in its full life cycle. Unconventional ESP systems are being installed in all new wells. For this type of application, it is recommended that a systematic approach be used that includes appropriate and flexible ESP technology, operating procedures, real-time surveillance and control and qualified personnel.

ESP Performance for Gas-Lifted High Water Cut Wells [Ref. 18]

This study evaluated the potential operating envelope of the suitable options based on selected well operating conditions and determined the appropriate design required to fulfill the field project objectives. Present gas lift flow conditions were simulated to determine the operating envelope and the conditions at which gas lift flow ceases. The study used the PROSPER model which is a well performance, design and optimization program for modeling most types of well configurations. Gas Lift vs. ESP performance comparisons were then carried out for each well over their lifecycle. PROSPER provides unique matching features which tune fluid characterization (PVT), multiphase flow correlations and reservoir inflow (IPR) to match measured field data, allowing a consistent model to be built prior to use in prediction (sensitivities or artificial lift design). PROSPER models were revised and calibrated by matching the calculated inflow performance to data measured during production tests. The results of a review of artificial lift strategy in a brownfield environment (Lebada West Field, Romania) with severe gaslift constraints showed that ESP provided particular advantages related to high water cut well applications and easy surveillance access in addition to operating flexibility for changing conditions. Gas lift versus ESP performance comparisons were carried out for each well over their lifecycle. The revenue and cost impact were demonstrated showing that ESPs can match or exceed the gas lift performance for middle and late life cases.

Selected wells for each field were constructed to be used as the base case to allow comparisons of alternative lift types. The input base case for selected wells in each field are shown in Table 5.

Table 5. Input Data for Each Field

Gas Lift Performance Analysis

Wells were selected for gas lift evaluation due to the high water cuts and low PIs resulting in reduced overall gas lift efficiency and instability. Gas lift and ESPs were evaluated for the selected design ranges of these wells. A well operating envelope was selected to determine the range over which the ESP system was to be evaluated. The following lifecycle scenarios were used for gas lift and ESP modelling and analysis.

Table 6. Lifecycle Scenarios for Well – B1

Using optimum liftgas injection rates Well B-1and B-2 were evaluated for ESP versus gas lift performance. For well B-1, the analysis showed that ESPs can match well performance of gas lift under current operating conditions, and that ESPs can outperform gas lift and achieve an upside when the water cut increases provided that the Field Bottom Hole Pressures (FBHP) below the bubble point pressure are allowed and that there is not productivity impact because of the resulting gas saturation increases in the near wellbore area. For well B-2, the ESPs were able to match the well performance of gas lift under current operating conditions when the FBHP well below the bubble point pressure are allowed and that there is no productivity impact because of the resulting gas saturation increases in the near wellbore area.

As described above, the study simulated present flow conditions to determine the operating envelope and conditions at which Gas Lift flow increases using PROSPER models. Present Gas Lift flow conditions for specific wells identified in the study were simulated to determine the operating envelope and the conditions at which Gas Lift flow ceases. Gas Lift vs. ESP performance comparisons were then carried out for each well over their lifecycle. Based on the study, it was concluded that ESPs can match the well performance of gas lift under present conditions and ESPs outperform Gas Lift in middle and late life cases when water cuts are high (50 – 80%).


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  5. Options for Removing Accumulated Fluid and Improving Flow in Gas Wells, Lessons Learned from Natural Gas STAR Partners, US EPA, 2011.
  6. Flex Turbine
  7. Rod Pump & Progressing Cavity Pump Applications
  8. Flex Series Electrical Submersible Pumps
  9. Zilift TorqueDrive System for PCP
  10. Muster, S, Clark, C and Jones,B., Rethink Artificial Lift with Hydraulic Pumping Systems
  11. Extending the life of rod-pumped wells
  12. TAM Software and Wireless Well Monitoring Equipment
  13. Weatherford Gas lift optimization
  14. GE Osiris downhole sensors
  15. Chemical Treatment
  16. Installing Plunger Lift Systems in Gas Wells, Lessons Learned from Natural Gas STAR Partners, US EPA, 2006
  17. Systematic solution overcomes artificial lift challenges, E&P, April 2013, Ferguson, Narvaez
  18. ESP Performance for Gas-Lifted High Water Cut Wells, Society of Petroleum Engineers, SPE 131758, Bagci, Kece, Nava, September 2010
  19. Brown, Kermit E. The technology of artificial lift methods, 1980.

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