IntroductionIf the producing bottomhole pressure becomes so low that it will not allow the well to produce at a desired flow rate (or perhaps any flow rate!), some sort of artificial energy supply will be needed to lift or help lift the fluid out of the well-bore. Energy can be supplied indirectly by injecting water or gas into the reservoir to maintain reservoir pressure, or through a variety of artificial lift methods that are applied at the producing well itself.There are many artificial lift methods, however, all are variations or combinations of three basic processes:1. lightening of the fluid column by gas injection (gas lift);2. subsurface pumping (beam pumps, hydraulic pumps, electric submersible centrifugal pumps); and3. piston-like displacement of liquid slugs (plunger lift).

Gas LiftGas lift provides artificial lifting energy by the injection of gas into or beneath the fluid column. The gas decreases the fluid density of the column and lowers the bottomhole pressure, allowing the formation pressure to move more fluid into the wellbore. Injected gas bubbles also expand as they rise in the tubing above their injection point, pushing oil ahead of them up the tubing. The degree to which each of these mechanisms affects the well's production rate depends on the type of gas lift method applied: continuous flow or intermittent flow.Continuous flow gas lift relies on the constant injection of gas-lift gas into the production stream through a downhole valve (Figure 1).

FIGURE 1The installation can be designed to allow for injection from the casing/tubing annulus into the tubing (most common), for injection into a smaller concentric tubing string within the production tubing ("macaroni" string), or for injection from the tubing into the casing/tubing annulus (annular flow installation). The fluid column above the injection point is lightened by the aeration caused by the relatively low density gas. The resulting drop in bottomhole pressure causes an increase in production rate.Intermittent gas lift (Figure 2) allows for the buildup of a liquid column of produced fluids at the bottom of the well-bore.

FIGURE 2At the appropriate time, a finite volume of gas is injected below the liquid and propels it as a slug to the surface. The propelling gas may be injected at a single point below the liquid slug or may be supplemented by multipoint injection as the slug moves past successive valves. An intermitter at the surface controls the timing of each injection-production cycle. Intermittent gas lift is used on wells with low fluid volumes, a high productivity index and low bottom-hole pressure, or a low productivity index and high bottomhole pressure. Gas lift is a very flexible artificial lift method. A properly designed installation can produce efficiently at a rate as high as 1000 (159 ) or as low as 50 (7.9 ).There are a number of gas-lift valves that are used in gas-lift operations. They are distinguished by their sensitivity to the casing and/or tubing pressures needed to open and close them (Figure 3,

FIGURE 3pressure operated, Figure 4, fluid-operated, and Figure 5, throttling valve).

FIGURE 4The casing pressure-operated valve (also called a pressure valve) requires a buildup in casing pressure to open and a reduction in casing pressure to close.

FIGURE 5Fluid-operated valves require a buildup in tubing pressure to open and a reduction in tubing pressure to close. A throttling pressure valve is sensitive to tubing pressure in the open position, and once opened by casing pressure buildup, requires a reduction in tubing or casing pressure to close.For a specific gas-lift design, the valves will be located at appropriate intervals in the tubing string. The type of valve and its location will depend on the expected flow characteristics of the well over its lifetime, whether continuous or intermittent gas lift is to be used, and whether the upper valves are to be used for simply unloading the fluid in the annulus or for multipoint injection.Conventional gas-lift valves are attached to gas-lift mandrels and wireline retrievable gas-lift valves are set in side-pocket mandrels (Figure 6, (a) conventional, (b) wireline retrievable).

FIGURE 6For conventional valves to be changed or serviced, the entire tubing string must be pulled, while retrievable valves can be latched and set through tubing with a wireline unit.

Subsurface PumpingSubsurface pumping can be achieved by various methods. The most common is sucker rod pumping, where the pumping motion is transmitted from the surface to the pump by means of a string of narrow jointed rods placed within the tubing. Rod pumping systems (Figure 1) consist essentially of five components: the subsurface pump, which displaces the fluid at the bottom of the well and thereby reduces bottomhole pressure;

FIGURE 1 the rod string, which transmits power to the pump from the surface; the surface unit, which transfers rotating motion to a linear oscillation of the rod string; and, the gear reducer, which controls the speed of the motor or engine that is the prime mover.The subsurface pump (Figure 2) is essentially a plunger and valve arrangement within a tube or barrel.

FIGURE 2When the close-fitting plunger is lifted within the barrel, it creates a low-pressure region below the plunger, which is filled by fluid from the formation. Simultaneously, the plunger and rods lift fluid up the tubing. The valves are designed to open and close so that they allow fluids to enter the pump on the upstroke and be displaced above the traveling valve on the downstroke. The fluid above the traveling valve moves one full stroke upward on the upstroke.There is a wide variety of pumps designed for many different applications. The API (American Petroleum Institute) has designed a classification system using the criteria listed below: The different types of API pump designations are given in Figure 3 and Figure 4.

FIGURE 3Subsurface pump classification criteria:

FIGURE 4 Tubing size Pump bore size Rod or tubing pump Barrel-type Plunger-type Pump seating assembly location Traveling or stationary barrel Type of seating assembly Barrel length Plunger length ExtensionsThe sucker rods are usually about 25 ft (7.62 m) long and are connected with threaded couplings. In deep wells, a tapered string of rods, decreasing in diameter with depth, can be run to maximize strength at the point of maximum load the top of the string (Figure 5, sucker rod, and Figure 6, coupling).

FIGURE 5

FIGURE 6The surface unit also varies in design and size. Typical designs are the conventional (Class I) and the Mark II or air balanced units (Class III units) (Figure 7,

FIGURE 7Figure 8, and Figure 9).

FIGURE 8Unit sizes are designated by torque rating, peak load, and stroke length. They can range from a unit with a 16-inch (.406 m) stroke and a maximum load of 3200 lb (1451 kg), to one with a 300-inch (7.62 m) stroke and a maximum load of 47,000 lb (21,319 kg).

FIGURE 9The torque rating for the gear reducer of these two units varies by a factor of 570. Prime movers are either internal combustion engines or electric motors.For any given pumping unit, the production rate may be changed within a limited range by changing the pump rate or stroke length. Rod pumping meets a wide range of artificial lift needs with typical producing rates from 5 to 600 (0.795 to 95.4 ).Rodless PumpingThe majority of rodless subsurface pumps fall into two categories: hydraulic and electric submersible. Hydraulic pumps rely on the use of a high-pressure power fluid pumped from the surface to operate a downhole fluid engine. The engine, in turn, drives a piston to pump formation fluid and spent power fluid to the surface (Figure 10).

FIGURE 10Most engine/pump units can be circulated in and out of the well for maintenance. The power fluid system can be either open (OPF) or closed (CPF) depending on whether or not the power fluid is commingled with the produced fluids or is returned to the surface in a closed conduit. In addition to the downhole equipment, this type of pumping system requires a surface power fluid pump and a power fluid reservoir. The power fluid is normally crude oil or water. Hydraulic pumps have a fairly wide range of production rate applications, typically 135 to 15,000 (21.5 to 2385 ).Electrical submersible centrifugal pumps are a second type of rodless pumping system. In Figure 11, we see a typical system layout.

FIGURE 11Electrical power is supplied via a bank of transformers that convert primary line voltage to system voltage. A switchboard provides instrumentation for control and overload protection. The junction box acts as a vent to prevent gas, which may have migrated up the power cable, from reaching the electrical switchboard. Power is transmitted through the power cable to an electric motor at the bottom of the tubing string. The motor is isolated from well fluids by a protector. Above that is a gas separator and the motor driven pump, which normally is a multistage centrifugal pump (Figure 12). These pumps can handle a wide range of rates from 200 to 60,000 (31.8 to 9540 ).

FIGURE 12Rod and rodless pumping systems achieve a reduction in bottomhole pressure by mechanical displacement of fluid up the tubing. A third artificial lift process involves the use of gas to power a plunger the length of the tubing string- in effect, a gas-lift powered pump that utilizes the entire tubing string as the barrel.Plunger lift is typically an intermediate artificial lift method for wells that ultimately must be pumped but have a low productivity index ( ) and a high enough gas-oil ratio to operate the plunger.Several variations on the above mentioned methods include: jet pumping, a hydraulic pump, which uses a nozzle to transfer power fluid momentum directly to the produced fluid; chamber lift, a gas-lift installation, which allows for production from low wells without the backpressure from injected gas; and modified rod pumping unit designs, such as the winch- or pneumatic-type pumping unit.

Examples of Artificial Lift ApplicationsThe examples below show how applications of artificial lift will vary depending on conditions (Brown 1982).Sometimes the newly completed well requires artificial lift from its first day of production. Often the drilling program and the completion must be designed to accommodate the artificial lift equipment that will become necessary even when the well initially flows on its own. In the next section, we will analyze our own well and determine the optimum completion design, anticipating the need for future artificial lift capability.Applications of artificial lift:Example 1 Offshore well producing from depth of 8000 ft (2438.4 m), deviated hole High productivity, fairly high GOR, high bubble-point pressure, high PR Tendency towards sand production Part of a fairly large field with gas compression capabilities 2 -inch (7.31cm) tubing inside 7-inch (17.79 cm) casing Best artificial lift application: continuous gas lift with wireline retrievable valvesExample 2 Land well producing from 3000 ft (914.4 m), straight hole Desired rate 400 (63.59 ), medium GOR, = 1200 psia (8270 kPa) No sand or problems, but oil is fairly viscous 2 -inch (7.31cm) tubing inside 7-inch (17.79 cm) casing Infrequent field personnel supervision only Best artificial lift application: beam pumping unitExample 3 Land well producing from 8000 ft (2438.4 m) = 1920 psia (13,240 kPa) Fairly high productivity, above bubble point, low GOR, 50% water cut 2 -inch (7.31cm) tubing inside 7-inch (17.79 cm) casing Desired rate of 4500 (715.44 ) Deviated hole in an urban environment Economic electric power supply Best artificial lift application: electrical submersible pumpExample 4 Deep land well producing from 11,000 ft (3353 m), deviated hole Some slight sand production Low productivity and fairly low bottomhole pressure since reservoir is partially depleted, medium GOR Waxy, viscous crude: maximum rate of 200 (31.8 ) desired 7-inch (17.79 cm) production casing Best artificial lift application: hydraulic pumping

The four principal methods of artificial lift are and this is how they work: Sucker Rod Pumping Gas Lift Electrical Submersible Pumping Hydraulic PumpingSucker rod pumping employs a subsurface valve and plunger (pump), which decreases the bottomhole pressure by lifting fluid away from the formation and up the hole. The pump is operated by a string of jointed rods that are reciprocated by a surface unit that transfers the rotating motion of an engine into the oscillating motion of the rod string.Gas lift lightens the fluid column by the injection of hydrocarbon gas into the tubing at one or several locations. Continuous gas lift employs constant injection of gas-lift gas through a downhole valve. Intermittent gas lift allows for a buildup of a liquid column of produced fluids before a volume of gas is injected below the liquid, propelling it to the surface.Electrical submersible pumps are centrifugal pumps operated by an electric motor supplied by a power cable from the surface to the pumps location down hole. The pump operates much like a fluid pump might operate on the surface, taking a volume of fluid and raising its pressure to push it up the tubing.Hydraulic pumps rely on a high-pressure fluid pumped from the surface to operate a downhole pump, which pushes both power fluid and formation fluid to the surface. The power fluid may be mixed with the produced formation fluids (OPF system) or returned to the surface in a closed system (CPF system).

1 Artificial lift is a method in which supplement energy is applied to the producing well through gas lift, subsurface pumps, or plunger lift.(A) True 2 In the intermittent gas lift method, the injected gas enhances the production rate by:(B) the expansion of gas bubbles as they rise in the tubing, thus pushing the oil ahead of them up the tubing. 3 The most common subsurface pumping method is:(C) sucker rod pump 4 Subsurface pumping reduces the bottomhole pressure by mechanically displacing the fluid at the bottom of the well. (A) True 5 From the provided example, the continuous gas lift method is applicable when the average reservoir pressure is high, the well is produced with high GOR, and the gas injection is feasible.(A) True