Artificial lift refers to the use of artificial means to increase the flow of liquids, such as crude oil or water, from a production well. Generally this is achieved by the use of a mechanical device inside the well (pump or velocity string) or by decreasing the weight of the hydrostatic column by injecting gas into the liquid some distance down the well. Artificial lift is needed in wells when there is insufficient pressure in the reservoir to lift the produced fluids to the surface, but often used in naturally flowing wells (which do not technically need it) to increase the flow rate above what would flow naturally. The produced fluid can be oil and/or water, typically with some amount of gas included.
Why use Artificial Lift
Any liquid-producing reservoir will have a 'reservoir pressure': some level of energy or potential that will force fluid (liquid and/or gas) to areas of lower energy or potential. You can think of this much like the water pressure in your municipal water system. As soon as the pressure inside a production well is decreased below the reservoir pressure, the reservoir will act to fill the well back up, just like opening a valve on your water system. Depending on the depth of the reservoir (deeper results in higher pressure requirement) and density of the fluid (heavier mixture results in higher requirement), the reservoir may or may not have enough potential to push the fluid to the surface. Most oil production reservoirs have sufficient potential to produce oil and gas - which are light - naturally in the early phases of production. Eventually, as water - which is heavier than oil and much heavier than gas - encroaches into production and reservoir pressure decreases as the reservoir depletes, all wells will stop flowing naturally. At some point, most well operators will implement an artificial lift plan to continue and/or to increase production. Most water-producing wells, by contrast, will need artificial lift from the very beginning of production because they do not benefit from the lighter density of oil and gas.
Artificial Lift Technologies
Hydraulic pumping systems
Hydraulic pumping systems transmit energy to the bottom of the well by means of pressurized power fluid that flows down in the wellbore tubular to a subsurface pump. There are two types of hydraulic subsurface pump:
- a) a reciprocating piston pump, where one side is powered by the injected fluid while the other side pumps the produced fluids to surface,and
- b) a jet pump, where the injected fluid passes through a nozzle creating a venturi effect pushing the produced fluids to surface.
These systems are very versatile and have been used in shallow depths (1000 ft) to deeper wells (18,000 ft), low rate wells with production in the tens of barrels per day to wells producing in excess of 10,000 barrels per day (1,600 m³/d). Certain substances can be mixed in with the injected fluid to help deal or control with corrosion, paraffin and emulsion problems. Hydraulic pumping systems are also suitable for deviated wells where conventional pumps such as the rod pump are not feasible.
These systems have also some disadvantages. They are sensitive to solids and are the least efficient lift method. While typically the cost of deploying these systems has been very high, new coiled tubing umbilical technologies are in some cases greatly reducing the cost.
Electric Submersible Pumps consist of a) a downhole pump, which is a series of centrifugal pumps, b) a separator or protector, which function is to prevent that produced fluids enter the electrical motor, c) the electrical motor, which transforms the electrical power into kinetic energy to turn the pump, and d) an electric power cable that connects the motor to the surface control panel. ESP is a very versatile artificial lift method and can be found in operating environments all over the world. They can handle a very wide range of flow rates (from 200 to 90,000 barrels per day) and lift requirements (from virtually zero to 10,000 ft (3,000 m) of lift). They can be modified to handle contaminants commonly found in oil, aggressive corrosive fluids such as H2S and CO2, and exceptionally high downhole temperatures. Increasing water cut has been shown to have no significant detrimental effect on the ESP performance. It is possible to locate them in vertical, deviated, or horizontal wells, but it is recommended to deploy them in a straight section of casing for optimum run life performance. Although latest developments are aimed to enhance the ESP capabilities to handle gas and sand, they still need more technological development to avoid gas locked and internal erosion. Until recently, ESP's have come with an often prohibitive price tag due to the cost of deployment which can be in excess of $20,000.
Gas Lift is another widely used artificial lift method. As the name denotes, gas is injected in the tubing to reduce the weight of the hydrostatic column, thus reducing the back pressure and allowing the reservoir pressure to push the mixture of produce fluids and gas up to the surface. The gas lift can be deployed in a wide range of well conditions (up to 30,000 bpd and down to 15,000 ft). They handle very well abrasive elements and sand, and the cost of workover is minimum. The gas lifted wells are equipped with side pocket mandrel and gas lift injection valves. This arrangement allows a deeper gas injection in the tubing. The gas lift system has some disadvantages. There has to be a source of gas, some flow assurance problems such as hydrates can be triggered by the gas lift.
Progressing Cavity Pumps, PCP, are also widely applied in the oil industry. The PCP consists of a stator and a rotor. The rotor is rotated using either a top side motor or a bottom hole motor. The rotation created sequential cavities and the produced fluids are pushed to surface. The PCP is a flexible system with a wide range of applications in terms of rate( up to 5,000 bpd and 6,000 ft). They offer outstanding resistance to abrasives and solids but they are restricted to setting depths and temperatures. Some components of the produced fluids like aromatics can also deteriorate the stator’s elastomer.
Rod Pumps are long slender cylinders with both fixed and moveable elements inside. The pump is designed to be inserted inside the tubing of a well and its main purpose is to gather fluids from beneath it and lift them to the surface. The most important components are: the barrel, valves (traveling and fixed) and the piston. It also has another 18 to 30 components which are called "fittings".
Every part of the pump is important for its correct operation. The most commonly used parts are described below:
- Barrel: The barrel is a long cylinder, which can be from 10 to 36 feet long, with a diameter of 1.25 inches (32 mm) to 3.75 inches (95 mm). After experience with several materials for its construction, the API (American Petroleum Institute) standardized the use of two materials or compositions for this part: carbon steel and brass, both with an inside coating of chrome. The advantage of brass against the harder carbon steel is its 100% resistance to corrosion.
- Piston/Plunger: This is a nickel-metal sprayed steel cylinder that goes inside the barrel. Its main purpose is to create a sucking effect that lifts the fluids beneath it and then, with the help of the valves, take the fluids above it, progressively, out of the well. It achieves this with a reciprocating up and down movement.
- Valves: The valves have two components - the seat and the ball - which create a complete seal when closed. The most commonly used seats are made of carbon nitride and the ball is often made of silicon nitride. In the past, balls of iron, ceramic and titanium were used. Titanium balls are still being used but only where crude oil is extremely dense and/or the quantity of fluid to be lifted is large. The most common configuration of a rod pump requires two valves, called the traveling valve and the fixed (or static or standing) valve.
- Piston rod: This is a rod that connects the piston with the outside of the pump. Its main purpose is to transfer the up/down reciprocating energy produced by the "Nodding Donkey" (pumping unit) installed above ground.
- Fittings: The rest of the parts of the pump are called fittings and are, basically, small pieces designed to keep everything hold together in the right place. Most of these parts are designed to let the fluids pass uninterrupted.
- Filter/Strainer: The job of the filter, as guessed, is to stop big parts of rock, rubber or any other garbage that might be loose in the well from being sucked into the pump. There are several types of filters, with the most common being an iron cylinder with enough holes in it to permit the entrance of the amount of fluid the pump needs.