1 Sep, 2017

Introduction to Artificial Lift

Production rate is the combined impact of reservoir delivery and wellbore plus flowline multiphase flow pressure change. When reservoir pressure declines or water fraction increases, the well’s natural flow rate may be inadequate and artificial lift processes are implemented to increase or maintain rate.

Six Primary Methods of Artificial Lift

Figure 1-1 Examples of the primary methods of artificial lift.

 

GAS LIFT          

Gas lift is a natural flow process in that the reservoir pressure is the driving energy to push fluid to the wellbore, up to the wellhead, and into the surface facility. The wellbore, surface facility, and reservoir responses are the same for a natural flow well and for a gas lifted well.

Purpose: To reduce the density of the flowing mixture of gas, oil, and water by increasing the gas-liquid ratio with gas injection into the tubing through a gas lift valve or orifice. Best lift occurs when injection is at a deep point in the wellbore. Gas lift is best applied when one or more of these characteristics are present:

Gas lift gas (or nitrogen or CO2 circulation through coiled tubing) causes density reduction, which reduces flowing bottomhole pressure (Pwf). This benefit is attained by first improving the gas to liquid ratio, supplementing reservoir gas and increasing the mixture velocity; second by changing the vapor-liquid distribution to one with better mixing and reduced liquid holdup; and third by reducing wellhead back-pressure to promote gas expansion. Gas lift is implemented by installing a system that has the following components:

Example of a gas lift system with listed components.

Fig. 1-2 Gas lift system

The most frequently used gas lift valve is an injection pressure operated (IPO) valve. The valve has a closing pressure set by the nitrogen pressure (Pbt) inside the bellows. The pressure to keep the valve open is controlled by the injection (casing) gas pressure (Pg) applied to the outside of the bellows plus the multiphase (tubing) fluid pressure (Pf) below the port.

Figure 1-3 shows the valve on a gas lift mandrel in the well and the pressure applied by the nitrogen, gas, and tubing fluid. The valve is a backpressure regulator and is set in the shop, at the calculated test rack opening (TRO) pressure, Pvo.

Figure 1-3   Gas lift valve in well and in test rack.

The schematic drawing of gas lift valves in a well are shown in Figure 1-4. The valves are in gas lift mandrels, which are attached to the tubing. For offshore wells, wireline retrievable valves are used. The upper valves are only used to unload the workover fluid, while a deeper valve is the operating (injection) point, which causes the gradient (density) change shown.

 

Figure 1-4   Gas lift schematic and pressure gradient graph.

The plunger lift system is shown in Figure 1-5. The plunger device rests above the bumper spring shown in illustration. The controller opens the well to flow, and the lubricator, catcher, and sensor on top of the existing wellhead retain the plunger when it surfaces. The controller timer shuts the well and releases the plunger, which falls to the bumper spring to start a new cycle.

Figure 1-5   Plunger lift system components.

Plungers can be used to aid intermittent gas lift or to lift liquids accumulating in gas wells, Figure 1-6. The application in lift design is for relatively low liquid rates. The well is shut in with the surface wellhead control valve, out of the picture, and the liquid column builds in the tubing. The well is opened and the differential pressure drives the plunger to the wellhead catcher, causing a slug of liquid to be lifted above it. If gas lift gas is used intermittently, the slug size lifted can be a greater volume.

The cycle of shut in, unloading of the slug with the plunger, and afterflow (mostly vapor with liquid mist) is repeated periodically, based on a field operator’s judgment of optimum time. Production testing to obtain rate versus cycle time is used determine the “optimum”.

Figure 1-6   Real-life example of plunger lift well.

PUMPING METHODS     

Pumping is a different process than gas lift. For pumping, the reservoir pressure is the driving energy to push fluid to the pump suction intake, not to the surface. Using the energy transferred downhole, the pump then raises the fluid pressure to drive it up to the wellhead, and into the surface facility (Figure 1-7). The pumping advantage is that reservoir pressure can decline much lower than that for natural flow or for a gas lift well.

Figure 1-7   Pump schematic and pressure gradient graph.

Purpose: To transfer energy down-hole to pump the fluid and raise its pressure. The selection is electrical, mechanical, or hydraulic energy transferred down-hole to drive a centrifugal, reciprocating, progressive-cavity (screw), or jet pump. Pumping is best applied when:

 

 

Pump systems transfer the energy in a variety of methods, including:

Electric submersible pumps: use cable strapped to the tubing to power the submerged motor, which drives the multistage centrifugal pump. An option is cable attached to the motor/pump assembly and suspended similar to wireline operations.

Sucker rod pumps: use a rod string lifted by the surface beam pump to reciprocate the down-hole positive displacement pump.

Hydraulic jet pumps: use pressurized crude oil or water from the surface high-pressure pumps to create a high velocity jet stream with a venturi effect that intakes reservoir fluid.

Hydraulic reciprocating pumps: use pressurized crude oil or water from the surface high-pressure pumps to power a down-hole “engine” pump that is directly connected to the reservoir fluid reciprocating pump.

Progressive cavity pumps: use the rod string and a motor driver at the surface to rotate the progressive cavity screw pump.

ELECTRIC SUBMERSIBLE PUMPS

Electrical submersible pumping system surface facilities consist of generators/access to a power system, and transformers and connectors to the wellhead. An example of the electric submersible pump/motor assembly is given in Figure 1-8. The rate design for the pump must closely match reservoir delivery unless a variable frequency drive is used to alter motor speed and pump throughput. Additionally, wellhead of the electric submersible pump system must have an electric cable entering. The downhole electrical submersible components consist of an electrical power cable, electrical submersible motor, motor protector, and centrifugal pump.

Figure 1-8   Electric submersible pump

SUCKER ROD PUMPS

Sucker rod pumping system surface facilities consist of access to a power system and electric motor to drive the surface beam pump, or a gas engine driver connected to the beam pump.

There are many pumping components (seen in Figure 1-9), but the primary ones are the beam pumping unit at the surface, sucker rod string, and downhole tubing pump or insert rod pump.

 

Figure 1-9   Beam pump components

 

The beam pump, Figure 1-10, is the indicator of the sucker rod pump in the well. Also called a pump jack, the surface pumping unit lifts the rod string, downhole pump, and fluid load. The beam pump is sized according to the fluid production rate and depth of lift.

Figure 1-10   Beam pump (pump-jack)

The down-hole sucker rod pump is shown in Figure 1-11. The rods reciprocate the plunger inside the pump barrel. The two check ball valves serve to fill the barrel chamber (standing valve) and then let the fluid be displaced above the plunger and be pumped up to the surface (traveling valve).

The lower standing valve opens during the up stroke when the barrel chamber pressure is less than the inflow pressure. The upper traveling valve opens during the down stroke when pressure in the chamber rises above the discharge pressure in the tubing above the plunger (Figure 1-12). If the fluid in the chamber is gassy, then it must be compressed before the traveling valve can open.

Figure 1-11 Sucker rod tubing pump

 

Figure 1-12   Sucker rod components

 

HYDRAULIC PUMPS 

Hydraulic pumping uses a surface pump to pressurize produced water or crude oil, depending on which is readily available, to drive a downhole pump. The components include a surface high pressure injection pump and pipeline, injection tubing, downhole assembly, and positive displace or jet pump.

The reciprocating hydraulic pump uses the high pressure injection “power” fluid, red in Figure 1-13, to drive the “engine” pump, which in turn drives the reservoir fluid pump. Ball check valves and a double acting pump forces the reservoir fluid to the surface.

Figure 1-13  Reciprocating hydraulic pump

The jet pump uses the high-pressure power fluid to create a high velocity venturi effect in the nozzle to throat gap (production inlet chamber) of the downhole pump, Figure 1-14. The low pressure induced in the gap causes reservoir production fluid to flow into the throat. The two fluids mix in the diffuser section, pressure recovery occurs, and the combined fluids flow back to the surface. 

Figure 1-14  Hydraulic pump components

The hydraulic pump well has wellhead connections to the power fluid manifold. The return production line must carry the power fluid plus produced reservoir fluid, where the power fluid required can range from 3 to 5 barrels for each barrel of produced fluid.

PROGRESSIVE CAVITY PUMPS

Progressive cavity pumps use the principle of the screw and interference fit of the helix and the elastomer in the case to drive fluid to the surface (Figure 1-15). The helix is driven by rods from a surface motor, or directly connected to a submerged motor.

Figure 1-15  Progressive cavity pump

The surface drive motor for a progressive cavity pump is illustrated at left in Figure 1-16, and the starter and variable speed drive are at right. Sucker rods are used to transmit motion to the downhole pump, but the rods are rotated rather than reciprocated. Bottom drive with a submersible motor can also be done, which eliminates the rods.

Figure 1-16  Progressive cavity pump and motor drive.

The proper application of each lift type is related to the reservoir fluid, reservoir pressure, and production rate delivery as determined by inflow and multiphase outflow. Lift selection guidelines are:

Chart 1-1  Lift selection guidelines. 

HOW TO CHOOSE BETWEEN GAS LIFT AND PUMPING

Gas lift and pumping are both efficient techniques under the right circumstances. To decide on an technique, you need to know the purpose and uses of each. To summarize, gas lift is an extension of natural flow and pumping is a technique that uses energy down-hole to raise fluid pressure. Choose the best technique for the project based on rate, reservoir and cost conditions.

Review

To learn more about artificial lift and gas lift concepts view our Artificial Lift Systems (ALS) and Gas Lift (GLI) courses. 

Did you like this article? Sign up for email updates on Tips of the Month!