ARTIFICIAL LIFT Artificial lift definition Artificial lift is a method used to lower the producing bottomhole pressure (BHP) on the formation to obtain a higher production rate from the well. This can be done with a positivedisplacement downhole pump, such as a beam pump or a progressive cavity pump (PCP), to lower the flowing pressure at the pump intake. It also can be done with a downhole centrifugal pump, which could be a part of an electrical submersible pump (ESP) system. A lower bottomhole flowing pressure and higher flow rate can be achieved with gas lift in which the density of the fluid in the tubing is lowered and expanding gas helps to lift the fluids. Artificial lift can be used to generate flow from a well in which no flow is occurring or used to increase the flow from a well to produce at a higher rate. Most oil wells require artificial lift at some point in the life of the field, and many gas wells benefit from artificial lift to take liquids off the formation so gas can flow at a higher rate. Types of Artificial lift Sucker-rod (beam) pumping Electrical submersible pumping (ESP) Gas lift and intermittent gas lift Reciprocating and jet hydraulic pumping systems Plunger lift Progressive cavity pumps (PCP) 1. Sucker Rod Pump (SRP) Sucker rod pumping systems are the oldest and most widely used type of artificial lift for oil wells. About 85 percent of all artificially lifted wells in the USA are produced by rod pumps. This is also true in some areas of S. America and Canada. About 80 percent of all oil wells are stripper wells, making less than 10 bopd. A vast majority of these stripper wells are lifted with sucker rod pumps. Of the remaining 20 percent, about 27 percent are rod pumped, 52 percent gas lifted and the remainder lifted with ESP’s, hydraulic pumps and other methods of lift. Although these statistics are ca. 1980, and are no doubt somewhat different today, they indicate the dominance of rod pumping for onshore operations. For offshore and higher rate wells, the use of ESP’s and especially gas lift increases dramatically. Sucker rod pumping systems should be considered for new, low volume stripper wells because operating personnel are usually familiar with these mechanically simple systems and can operate them more efficiently. Inexperienced personnel also can often operate rod pumps more effectively than other types of artificial lift. Sucker rod pumping systems can operate efficiently over a wide range of well producing characteristics. Most of these systems have a high salvage value. Sucker rod systems also should be considered for lifting moderate volumes from shallow depths and small volumes from intermediate depths. It is possible to lift 1,000 barrels from about 7,000 feet and 200 barrels from approximately 14,000 feet (special rods may be required). If the well fluids contain hydrogen sulfide, sucker rod pumping systems can lift 1,000 barrels of liquid per day from 4,000 feet and 200 barrels per day from 10,000 feet (exclusive of other mitigating conditions). Most of the parts of the sucker rod pumping system are manufactured to meet existing standards, which have been established by the American Petroleum Institute. Numerous manufacturers can supply each part, and all interconnecting parts are compatible. The sucker rod string, parts of the pump and unanchored tubing are continuously subjected to fatigue. Therefore, the system must be more effectively protected against corrosion more than any other lift system to insure long equipment life. Sucker rod pumping systems and well dog-leg severity are often incompatible. Deviated wells with smooth profiles may allow satisfactory sucker rod pumping. The ability of sucker rod pumping systems to lift sand is limited. Paraffin and scale can interfere with the efficient operation of sucker rod pumping systems. If the gas-liquid separation capacity of the tubing-casing annulus is too low, or if the annulus is not used efficiently, and the pump is not designed and operated properly, the pump will operate inefficiently and tend to gas lock. One of the disadvantages of a beam pumping system is that the polished rod stuffing box can leak. However, if proper design and operating criteria are considered and followed, that disadvantage can be minimized. If the system is not sized to the well productivity and is over-pumped without POC (pump-off control), mechanical damage and inefficient pump operation will occur. Advantages of using SRP : Relatively simple system design. Units easily changed to other wells with minimum cost. Efficient, simple, and easy for field people to operate. Applicable to slimholes and multiple completions. Can pump a well down to very low pressure (depth and rate dependent). System usually is naturally vented for gas separation and fluid level soundings. Flexible-can match displacement rate to well capability as well declines. Analyzable. Can lift high-temperature and viscous oils. Can use gas or electricity as power source. Corrosion and scale treatments easy to perform. Applicable to pumpoff control if electrified. Availability of different sizes. Hollow sucker rods are available for slimhole completions and ease of inhibitor treatment. Has pumps with double valving that pump on both upstroke and downstroke Disadvantages of using SRP : Crooked holes present a friction problem. High solids production is troublesome. Gassy wells usually lower volumetric efficiency. Is depth limited, primarily because of rod capability. Obtrusive in urban locations. Heavy and bulky in offshore operations. Susceptible to paraffin problems. Tubing cannot be internally coated for corrosion. H2S limits depth at which a large-volume pump can be set. Limitation of downhole pump design in small diameter casing. 2. Electrical Semisubmersible Pump (ESP) An electric submersible pumping (ESP) assembly consists of a downhole centrifugal pump driven by a submersible electric motor, which is connected to a power source at the surface. The pump and motor assembly, which may be several hundred feet long, is connected to the surface by an armored cable that provides electric power and control. On a cost-perbarrel basis, ESP systems are among the most efficient and economical of lift methods. Fluid volumes ranging from 100 to 60,000 B/D, including high water-cut fluids, can be handled by ESP systems. These systems can be installed in high-temperature wells (above 350°F) using high-temperature motors and cables. The pumps can be modified to lift corrosive fluids and sand. ESP systems can be used in high-angle and horizontal wells if placed in straight or vertical sections of the well. ESP pumps can be damaged from “gas lock”. In wells producing high GOR fluids, a downhole gas separator must be installed. Another disadvantage is that ESP pumps have limited production ranges determined by the number and type of pump stages; changing production rates requires either a pump change or installation of a variable-speed surface drive. The tubing must be pulled for pump repairs or replacement. Advantages : Adaptable to highly deviated wells - up to 80°. Adaptable to required subsurface wellheads 6' apart for maximum surface location density. Permit use of minimum space for subsurface controls and associated production facilities. Quiet, safe and sanitary for acceptable operations in an offshore and environmentally conscious area. Generally considered a high volume pump - provides for increased volumes and water cuts brought on by pressure maintenance and secondary recovery operations. Permits placing well production even while drilling and working over wells in immediate vicinity Disadvantages: Will tolerate only minimal percents of solids (sand) production. Costly pulling operations to correct downhole failures (DHF’s). While on a DHF there is a loss of production during the time well is covered by drilling operations in immediate vicinity. 3. Not particularly adaptable to low volumes - less than 150 B/D gross. Gas lift and intermittent gas lift Constant flow gas lift is recommended for high volume and high static bottom hole pressure wells where major pumping problems will occur. It is an excellent application for offshore classic-type formations with water drive, or waterflood reservoirs with good productivity indices (PI’s) and high gas-oil ratios (GOR’s). When high pressure gas is available without compression or where gas is low in cost, gas lift is especially attractive. Constant flow gas lift supplements the produced gas with additional gas injection to lower the intake pressure to the tubing, including lowering formation pressure. A reliable, adequate supply of good quality high-pressure lift gas is mandatory. This supply is necessary throughout the producing life if gas lift is to be effectively maintained. In many fields the produced gas declines as water cut increases, requiring some outside source of gas. The gas lift pressure is typically fixed during the initial phase of the facility design and as the water cut increases the depth of lift is decreased not allowing the gas lift system to obtain the desired flowing bottom hole pressure. Also the wells will produce erratically or not at all when the lift supply stops or pressure fluctuates radically. Poor quality gas will impair or even stop production. Thus, the basic requirement for gas must be met or other artificial lift means should be installed. Constant flow gas lift imposes a relatively high back pressure on the reservoir compared to pumping methods and is at best only moderately efficient. The high back pressure may significantly reduce production as compared with some pumping methods and poor efficiency significantly increases both capital cost and operating energy costs. Gas lift involves injecting high-pressure gas from the surface into the producing fluid column through one or more subsurface valves set at predetermined depths. There are two main types of gas lift: Continuous gas lift, where gas is injected in a constant, uninterrupted stream. This lowers the overall density of the fluid column and reduces the hydrostatic component of the flowing bottomhole pressure. Thus, for a given average reservoir pressure and productivity index, the well is able to flow at a higher rate. This method is generally applied to wells with high productivity indexes and high bottomhole pressures relative to their depths. Advantages : Can handle large volume of solids with minor problems. Handles large volume in high-PI wells (continuous lift}; 50,000 B/D (7949.37 m /d). Fairly flexible-convertible from continuous to intermittent to chamber or plunger lift as well declines. Unobtrusive in urban locations. Power source can be remotely located. Easy to obtain downhole pressures and gradients. Lifting gassy wells is no problem. Sometimes serviceable with wireline unit. Crooked holes present no problem. Corrosion is not usually as adverse. Applicable offshore. Disadvantages : Lift gas is not always available. Not efficient in lifting small fields or one-well leases. Difficult to lift emulsions and viscous crudes. Gas freezing and hydrate problems. Problems with dirty surface lines. Some difficulty in analyzing properly without engineering supervision. Cannot effectively produce deep wells to abandonment. Requires makeup gas in rotative systems. Casing must withstand lift pressure. Safety problem with high pressure gas. Intermittent gas lift, which is designed for lower-productivity wells. In this type of gas lift installation, a volume of formation fluid accumulates inside the production tubing. A highpressure “slug” of gas is then injected below the liquid, physically displacing it to the surface. As soon as the fluid is produced, gas injection is interrupted, and the cycle of liquid accumulation-gas injection-liquid production is repeated. Intermittent gas lift method is generally used on wells that produce low volumes of fluid (~<200 bpd). Wells where intermittent lift is recommended normally have the characteristic of (1) high PI and low bottom hole pressure (BHP ) or (2) low PI with high BHP. Its use stems from known major pumping problems or where continuous gas lift is already installed or low cost high pressure gas is available. If an adequate, good quality, low cost gas supply is available and plans are to lift a relatively shallow, high GOR, low PI or low BHP well with a bad dog-leg that produces some sand, then intermittent gas lift would be an excellent choice. Intermittent gas lift has many of the same advantages/disadvantages as constant flow gas lift, and the major factors to be considered are similar. Only the differences will be highlighted in the ensuing discussion. The availability of gas and the costs for compression and injection are major considerations in planning a gas lift installation. Where these gas injection requirements can be satisfied, gas lift offers a flexible means of optimizing production. It can be used in deviated or crooked wellbores, and in high-temperature environments that might adversely affect other lift methods, and it is conducive to maximizing lift efficiency in high-GOR wells. Wireline-retrievable gas lift valves can be pulled and reinstalled without pulling the tubing, making it relatively easy and economical to modify the design. On the negative side, gas lift system costs can adversely impact profitability if the source gas requires additional processing or surface compression. Lift efficiency can be reduced by corrosion and paraffin, which increase friction and backpressure. Tubing size and surface flowline length also affect system efficiency. Another disadvantage of gas lift is its difficulty in fully depleting low-pressure, low-productivity wells. Also, the start-andstop nature of intermittent gas lift may cause downhole pressure surges and lead to increased sand production. Advantages : Intermittent gas lift has a significantly lower producing BHP than the constant flow methods. It has the ability to handle low volumes of fluid with relatively low production BHP’s. Disadvantages : Intermittent gas lift is limited to low volume wells. For example an 8,000 foot well with 2" nominal tubing can seldom be produced at rates of over 200 BPD with an average producing pressure much below 250 psig. Smaller sizes of tubing have even a lower maximum rate. The average producing pressure of a conventional intermittent lift system is still relatively high when compared to rod pumping. However, the producing BHP can be reduced by use of chambers. Chambers are particularly suited to high PI, low BHP wells. The output to input horsepower efficiency is low. More gas is used per barrel of produced fluid than with constant flow gas lift. Also the slippage increases with depth and water cut making the lift system even more inefficient. However, slippage can be reduced by use of plungers. In general if the cycle time allows time for the plunger to fall, then plunger should be used with intermittent lift if not solids are present. The fluctuation in rate and BHP can be detrimental to wells with sand control. The produced sand may plug the tubing or standing valve. Also surface fluctuations cause gas and fluid handling problems. Intermittent gas lift requires frequent adjustments. The lease operator must alter the injection rate and time period routinely to increase the production and keep the lift gas requirement relatively low 4. Reciprocating and jet hydraulic pumping systems Hydraulic pump systems use a power fluid—usually light oil or water—that is injected from the surface to operate a downhole pump. Multiple wells can be produced using a single surface power fluid installation. Downhole hydraulic pumps may be either of two types. With a reciprocating hydraulic pump, the injected power fluid operates a downhole fluid engine, which drives a piston to pump formation fluid and spent power fluid to the surface. A jet pump is a type of hydraulic pump with no moving parts. Power fluid is injected into the pump body and into a small-diameter nozzle, where it becomes a lowpressure, high-velocity jet. Formation fluid mixes with the power fluid, and then passes into an expanding-diameter diffuser. This reduces the velocity of the fluid mixture, while causing its pressure to increase to a level that is sufficient to lift it to the surface Hydraulic pumps can be used at depths from 1000 to 17,000 feet and are capable of producing at rates from 100 to 10,000 B/D. They can be hydraulically circulated in and out of the well, thus eliminating the need for wireline or rig operations to replace pumps and making this system adaptable to changing field conditions. Another advantage is that heavy, viscous fluids are easier to lift after mixing with the lighter power fluid. Disadvantages of hydraulic pump systems include the potential fire hazards if oil is used as a power fluid, the difficulty in pumping produced fluids with high solids content, the effects of gas on pump efficiency and the need for dual strings of tubing on some installations. Advantages : Can lift from as deep as 20,000 feet (5486 m) Can produce 25,000 B/D (3975 m3/d) from 5,000 feet ( 1520 m) Crooked holes present no problems. Unobtrusive in urban locations. Power source can be remotely located. Installations can be analyzed. Flexible. Normally able to match output to delivery of well. Can use diesel, natural gas or electricity as power source. Downhole pumps can be installed /retrieved using the power fluid. No record of plugging due to producing sand. Can be used on offshore platforms. Can use any liquid for power fluid. Typically a liquid being produced from the well is used (water or oil) Easy to pump in cycles by qualified personnel. Power fluid can be heated to reduce viscosity of produced fluid. Additional liquids can be mixed with the power fluid (such as diesel) for this purpose also. Inhibitors can be mixed with the power fluid for the purposes of controlling corrosion, scale, emulsions from reservoir, etc. No record that a jet pump has ever created an emulsion Disadvantages : Uses momentum transfer as method for operation. A very inefficient form of energy transfer. Total system efficiency approximately 10-30%. Requires approximately 10% submergence to prevent cavitation damage at low production rates. Pump will cavitate if more production than planned is forced through the pump. As with other A/L systems, the less the back pressure the better. Producing more free gas for a given nozzle/throat combination than intended will reduce the amount of produced liquids and may cause cavitation damage. Pump must be retrieved and a larger throat installed. Power oil systems are a possible fire issue. High surface power fluid lines are required. Any leaks when using power oil pose an environmental issue. The issues of a leak when using a power water system are much less. Maintaining an oil inventory required for power oil system, and cannot be sold. Can install a vented system so gas can by-pass pump but such systems are more expensive. Qualified personnel needed for trouble shooting in field, as with other A/L systems. Qualified personnel needed to obtain valid well tests, as with other A/L systems. 5. Plunger lift Plunger lift is the only artificial lift method that relies solely on the well’s natural energy to lift fluids. The plunger, traveling inside the tubing, moves upward when the pressure of the gas below it is greater than the pressure of the liquid above it. As the plunger travels to the surface, it creates a solid interface between the lifted gas below and produced fluid above to maximize lifting energy. Any gas that bypasses the plunger during the lifting cycle flows up the production tubing and sweeps the area to minimize liquid fallback. Plunger lift provides a cost-effective method of artificial lift that can be used to efficiently produce both gas wells with fluid loads and high GOR oil wells. Advantages : Retrievable without pulling tubing. Very inexpensive installation. Automatically keeps tubing clean of paraffin and scale. Applicable for high GOR wells. Can be used with intermittent gas lift. Can be used to unload liquid from gas wells. Disadvantages : May not take well to depletion; therefore, eventually requires another lift method. Good for low-rate, normally less than 200 B/D (31.8 m/d) wells only. Requires more engineering supervision to adjust properly. Danger exists in plunger reaching too high a velocity and causing surface damage. Communication between tubing and casing required for good operation unless used in conjunction with gas lift. 6. Progressive cavity pumps (PCP) A progressive cavity pump consists of a spiral rotor that turns eccentrically inside an elastomer-lined stator. As the rotor turns, cavities between the threads of the pump rotor and stator move upward. The rotor is most often powered by rods connected to a motor on the surface, although some assemblies are driven by subsurface electric motors. Progressive cavity pumps are commonly used for dewatering coalbed methane gas wells, for production and injection applications in waterflood projects and for producing heavy or high-solids oil. They are versatile, generally very efficient, and excellent for handling fluids with high solids content. However, because of the torsional stresses placed on rod strings and temperature limitations on the stator elastomers, they are not used in deeper wells. Advantages : The pumping system can be run into deviated and horizontal wells. The pump handles solids in production well. The pump handles viscous production well. Several of the components are off the shelf ESP components. The production rates can be varied with use of a variable speed controller (VSC). Some types are retrievable with rods. Moderate cost. Low profile. Can use downhole electric motors that handle sand and viscous fluid well. High electrical efficiency. Disadvantages : The unit does not tolerate heat due to the softening of the stator material. Gas must be separated to increase efficiency. It will not gas lock but if ingesting large amounts of gas continuously, or if pumped off, it will overheat and damage will occur to the stator. If the unit pumps off the well, the stator will likely be permanently damaged. The gearbox is another source of failure if well-bore fluids or solids leak inside. Elastomers in stator swell in some well fluids. Pump off control is difficult. Lose efficiency with depth. Rotating rods wear tubing. Rod windup and afterspin of rods increase with depth. Sand and solids quickly wear chrome off of rotor.