Early planning of artificial lift is essential for long-term profitability of the wells. Decisions on the artificial lift method to be used may not be available at the field development planning stage.

In most cases the artificial lift systems are installed at a later stage in the field life cycle as reservoir energy is depleted and/or the wells produce water. Main methods available:

• gas lifting (continuous);
• beam pumping;
• electric submersible pumping (ESP);
• hydraulic reciprocating pumping;
• progressive cavity pumping (PCP);
• hydraulic jet pumping;
• intermittent gas lift;
• plunger lift.

1. Artificial-lift selection

The selection will be based on two major criteria:

1. Technical: which method is capable of achieving the required lift rates within a set of technical constraints.
2. Economic: selection of the optimum artificial lift method will always involve an economic evaluation of the technically viable lift methods. This will include the operating cost factors (i.e. well intervention for ESPs, etc.).

Technical viability

This includes the ability of the lift method to operate successfully under the current and expected well conditions. Factors that play an important role include:

• rate and head achievable;
• sand tolerance;
• wax, asphaltene tolerance;
• deviation/crooked hole;
• gas tolerance (gas liquid ratio);
• corrosion tolerance;
• depth limitations;
• temperature tolerance.

Economic viability

• Geographic location. An offshore and/or arctic location can limit the viable lift methods through size/weight restrictions or environmental concerns. Back-up and repair support (i.e. ESP workshops) availability within the area will be a consideration. This will include local experience with the lift method.
• Capital costs. These include not only the lift equipment, but also the production facilities required to support the lift method (e.g. compression requirements for gas lift). It must also include the CAO (Computer Assisted Operation) requirements for lift method optimisation, an item often overlooked.
• Operating costs. These costs include the energy needed to operate the lift method, the cost of maintenance and repair, and the cost of monitoring/optimising the system. This includes aspects such as resource availability, workover possibilities and efficiency of the lift method.
• Production flexibility. This includes the minimum and maximum rates available from the lift method based on normal operating conditions.
• Reliability. This impacts largely on the operating costs for the field and, together with repair logistics, on the associated hydrocarbon deferment. Local circumstances and infrastructure will often play a role in assessing reliability and its impact on lift method selection.

2. Beam pumping

Generally it is applied in non-deviated wells with an API gravity in the range 20 to 30 and low GOR.

The beam pumping system consists essentially of five parts:

1.The subsurface pump assembly (plunger, standing/travelling valves and pump barrel).

2.The sucker rod string which transmits the surface pumping motion and power to the subsurface pump. Also included is the tubing string within which the rods operate and conducts the pumped fluid to surface.

3.The surface pumping unit which changes the prime mover motion into oscillating linear pumping motion.

4.The power transmission unit or speed reducer.

5.The prime mover which furnishes the necessary power to the system.

Subsurface pump

Selection between an insert pump or tubing pump. The insert pump is an integral unit run on the sucker rod, while the tubing pump consists of a pump barrel run as an integral part of the tubing string. The selection between an insert or tubing pump will depend on the required flowrates for a given tubing size (tubing pumps having greater displacement), sand/wax/scale probabilities and expected workover requirements/plans, and the stage within the life of the well when the pump will need to be fitted. When fitting an insert valve provisions will need to be made in the well conduit design for some means of locking the pump in place.

Rods and Xmas tree

Sucker rods are available in several standard sizes (1/2, 5/8, 3/4, 7/8, 1 and 11/8") and are primarily made from carbon steel. CRA and fiberglass rods are available for corrosive environments.

For depths greater than about 3500 ft, it is common for the string to be tapered.

Operational considerations at the design stage include:

• Tubing/rod friction and wear.
• Type of Xmas tree and stuffing box.
• Monitoring ports.
• Gas anchors.

Supervisory Pump Off Controllers (SPOC)

This system provides a complete capability for monitoring, control, analysis, and design for beam pumping operations. It provides integration with other CAO applications, such as well testing and data transfer. It uses wellhead, microprocessor based pump-off controllers (POC units) which communicate the SPOC system on a host CAO system via radio or hardwired communications.

Progressive cavity pumps, PCPs

The principle development within this method of lift has been the introduction of downhole motor driven PCPs.

Moineau principle

The principle of operation of the progressive cavity pump is based on an invention by the French professor Renè Moineau.

The discharge head is proportional to the torque. The production rate is proportional to the speed, but decreases slightly - due to clearance losses - at high counterpressure.

Due to the combination of elastic stator elastomeric and inelastic rotor material based on the Moineau principle and the absence of inlet and outlet valves, the PCP is suited for use in wells with a high sand content. Because of the virtually pulsation-free production stream the PCP does not tend to mobilise the sand, but rather leaves it in the reservoir. Contrary to this, the pulsing stream in the beam pump, which is in any case sand-prone, may promote the separation of sand particles from the rock matrix.

The use of PCPs instead of the beam pump/wire-wrapped liner or slotted liner combination has proved suitable in workover applications resulting from defective liners or reduced production.

In many cases, consideration is given to not running gravel packs because of their production restrictions and to allow a certain sand influx. Therefore the artificial lift system will need to be tolerant to sand particles.

The Moineau principle, favours the application of the PCP for production of highly viscous fluids with paraffin, wax or emulsions. Contrary to the oscillating beam pump, downhole emulsification is avoided due to the uniform production with the PCP.

Down hole motor (DHM) PCP: The conventional PCP is limited, with respect to production rates, setting depths and hole deviation, by the power transmission of the sucker rods. To alleviate these restrictions, PCPs may be supplied with downhole motors, principally using similar technology as the ESP drive mechanisms. Using a downhole motor BEB have experienced run lifes of 31 months.

The DHM-PCP will have application in deep, high production rates, and deviated wells where a degree of sand tolerability is required.

3 Electrical submersible pumps (ESPs)

The use of ESPs has increased significantly with the main growth in "high" volume pumps. ESP reported run lives range from 200 to 2000 days (average 3.3 years). In general it would appear that fixed speed ESPs have a longer run life than variable speed drives (1500 vs. 1000 days respectively). Two distinct trends are distinguished:

• pumps running in shallow (2000-5000 ft) wells, low temperatures, high water cut (low GOR) have average run lifes of 3-4 years;
• deep, hot, hostile environment, high rate and big horsepower pumps show an average run life of 12-18 months.

3.1 System configuration

The ESP system arranged from bottom to top consists of:

. Motor, the driving force which turns the pump. The non-conductive oil in the motor housing lubricates the motor bearings and transfers heat generated in the motor to the motor housing. This heat is dissipated by the well fluids moving past the exterior surface of the motor.

·Motor seal chamber. The chamber performs five basic functions:

• it connects the pump to the motor;
• it contains the pump thrust bearing to carry the axial thrust by the pump;
• it prevents well fluids to enter the motor;
• pressure inside the motor is equalised with the well bore pressure;
• it compensates for expansion and contraction of motor oil.

·Intake section or gas separator. The purpose of the gas separator is to vent the gas to the annulus in high GOR wells, thereby preventing cycling, gas lock and cavitation.

·Pump. Electrical submersible pumps are multistage centrifugal pumps. Each stage consists of a rotating impeller and a fixed diffuser. The impeller imparts a radial velocity to the fluid and the diffuser changes some of the velocity energy into an increase in pressure.

·Motor Lead Extension (MLE). The motor lead extension is a special low profile power cable extending from the pothead on the motor to above the end of the pump where it connects with the lower cable. The pothead allows the power to be connected while preventing ingress of well fluid to the motor housing.

·Motor cable termination or pothead. This is the interface between the lower power cable and the MLE.

·Y-tool/wireline adaptor. When there is a need to perform wireline operations below the pump, a Y-tool or wireline adaptor may be included in the completion.

·Cables. Electrical supply is supplied to the pump motor using a cable which passes through the tubing/casing annulus.

·Surface controller. The surface equipment consists of an electrical power supply, step down/up transformers, switchgears and controllers to monitor/control the downhole equipment.

Operational considerations

• The pump intake pressure should be maintained above bubble point to avoid gas pressure locks in the pump system.
• Motors should be slightly oversized to overcome the increasing power demand from wells as water cuts increase.
• Tubing leaks will result in pump recycling and reduced production. Tubing leak and the subsequent well fluid flow in the annulus, may cause cable armour corrosion and eventual cable failure.
• Pump specific rate/pressure limitations should be applied while bullheading through to the ESP.
• Ammeter chart interpretation should be used actively during troubleshooting since different failures or operational problems often produce distinctive chart patterns.
• To avoid increased shaft stresses the recommended dogleg severity should not exceed 7°/100 ft.
• Reduce the number of stop/starts, each of which may result in debris build up in the pump and current surges respectively.
• VSD or soft start to reduce the start up current surge and allow initial clean up and production at a low flow rate.
• Annulus pressure monitoring, bleeding and gas disposal considerations, ensuring that any pressure is bleed off slowly.

Drain valves

Packers

The use of packers is required for wells capable of producing to surface under natural flow conditions. Where possible the use of packers should be discouraged (unless required for safety reasons) as this introduces the requirement for an extra downhole connection in the cable system, which has historically been a weak point.

Manufacturers such as Baker, Otis and Camco have modified dual packers available for use with ESP systems. The packers are hydraulically set on the production tubing. These packers are retrieved by applying excess overpull to the production tubing. Some designs are available which permit the packer to be set, unlatched, and reset, allowing repairs or spacing out of the upper part of the string. The packers are similar to standard dual packers, with the second bore used for the ESP power cable. Depending on the pressure rating required and downhole conditions, the second bore may contain a feed-through connector, packing gland, or other pressure tight means of transmitting power, similar to those used on wellheads.

Depending on the size and type of packer, further vent tubes through the packer may be provided for injection of chemicals below the packer, for the venting of gas or for instrumentation cables. In some designs, these functions are provided within the second bore together with the power connection.

During operation the weight of the pump is supported by the packer. The packer must be capable of withstanding the torque loads imposed by the motor at startup and shut down. If a packer is required consideration should be given to running the packer beneath the ESP pump. When combined with a deep set SCSSV this both removes the additional cable complication and obviates the need for additional annular safety.

Downhole injection

The injection of treating chemicals via the annulus may be required for inhibition of corrosion, or scale, or to prevent formation of viscous emulsions within the pump. Injection of pour point depressants or hydrate suppressants may also be required in some wells.

Downhole sensors

Downhole sensors are used to monitor both reservoir conditions and for monitoring/controlling pump conditions. Downhole measurements of pressure, temperature and flow may in future eliminate the need for routine well testing. The inclusion of a pressure sensor in an ESP assembly permits testing of new wells, allows optimum drawdown to be maintained, and may improve the efficiency of operation of ESPs in high GOR wells. A pressure sensor allows maximum benefit to be derived from the use of a VSD. Furthermore, downhole monitoring systems give information on the status of the ESP. This may enable failure detection in an early stage, prior to breakdown. Reported examples include detection of incorrect setting of the rotation phase and detection of a bypass plug in the Y-tool coming unseated. Although reliability of downhole sensors has increased, it is recommended to use sensor systems that in the event of failure leave the operation of other components of the ESP system unaffected.

Wellhead chokes

Provision for fixed or variable chokes should be made to allow flowrate control of the pump. For a fixed speed pump this is the only method available for controlling the operating range of the pump. The installation of a variable choke will also allow testing of the well under a range of flowing conditions.

Subsea completions

Specialised power cables and wellhead feed through connections have been developed for subsea completions. These are designed to allow electrical connections to be made or broken underwater without loss of insulation. For low power circuits such as those used for downhole sensors inductive couplings are used.

The soft start controller

In order to reduce start up currents and transient loads on the motor and pump a "soft" start controller is often used. This reduces system voltage drops, electrical and mechanical stresses on a motor, which may otherwise lead to premature failure. The controller limits the initial current inrush for a short period following start-up.

Variable speed drives

VSDs are expensive and contain sophisticated electronic equipment. The electronics must be protected from dust and humidity, often requiring an air conditioned enclosure. Provision must be made for maintenance and repairs to the equipment, and availability of spare parts. The use of VSDs should be avoided where possible.

4. Hydraulic pumping

Generally speaking jet pumps cannot compete as an effective lift method in isolation due to very low hydraulic efficiency and the need for large surface facilities and pumps. In some specific cases, however, when the lift method can also be used for other purposes (e.g. treating the production stream, blending heavy crude with a lighter crude) then there may be merit in the system.

The two principal types of hydraulic pumping include:

• hydraulic reciprocating pump;
• jet pumping.

The hydraulic reciprocating pump is operated by directing hydraulic fluid (power fluid) alternatively to either side of a "working" cylinder, which is connected by a rod to the "production" cylinder (pump).

Further development includes coiled tubing jet pumps, which may be run within 23/8" or 27/8" tubing to eliminate workovers. Applications include producing crude, dewatering gas wells and replacing gas lift installations.

Typical operational considerations include:

• power fluid supply, i.e. open or closed system;
• metering and testing of the produced fluid in an open system design;
• emulsion difficulties;
• intervention requirements for valve/jet replacement.

5. Gas lift

Gas lift is by for the most widely used form of artificial lift method within the group. Gas lift optimisation, the management of the optimisation process and of the production system itself, continues to be a key challenge to improve lift efficiency.

Gas lift is the continuous or intermittent injection of gas into the lower section of the production tubing via valves to sustain or increase well potential. The injected gas is commingled with produced fluids, thereby decreasing the flowing gradient, enabling wells to be operated at reduced flowing bottom hole pressure, hence increasing or sustaining production.

·The size of the production casing will be selected in line with the desired well potential, and on the physical size of the required downhole equipment (gas lift mandrels, SSSV). The production casing must be large enough to accommodate the intended completion - particularly when reviewing the feasibility of multiple tubing strings.

·The well and completion should be configured to facilitate through-tubing operations. Wireline/coiled tubing tools will be used to maintain the well and monitor production performance (e.g. Flowing Gradient Survey) and change valves as required.

·There are a number of gas lift operating conditions that can result in the pressure in the production casing being evacuated to atmosphere (as a result of human intervention, a surface leak or equipment failure), therefore the collapse rating of the production casing, and the design of the primary cementation, should be carefully considered during the design phase.

·It should also be noted that during initial kick off operations the production casing can be exposed to full gas lift pressure on top of a full column of completion fluid. The production casing and tubing should therefore be designed accordingly.

"golden rules" of gas lift:

• The success of any gas lift system depends on an adequate and reliable source of "quality" lift gas throughout the period when gas lift is required.
• The gas injection point should be as close as possible to the top of the completion interval. In this respect, the equilibrium curve concept should be used as the basis of all gas lift design studies.
• Lift should be as stable as possible.
• Gas lift systems should operate with minimum (practical) back pressure at the wellhead.
• Completions should be designed for single-point lift.
• Lift gas availability should be optimised to enable the system to operate near-continuously in the most profitable configuration (e.g. minimise compressor down time).
• All gas lift system designs should address future, as well as present, operating conditions.
• Overly conservative design assumptions should be avoided - design factors should reflect the availability and quality of design data.
• CAO surveillance and control should be considered as an integral part of any gas lift system. Good quality data is a prerequisite for an efficient gas lift design. The ability to control gas distribution is essential for efficient gas lift operation.
• Gas lift clearly requires a "systems think" approach in order to identify bottlenecks in production, disposal or flare systems.
• Gas lift systems should be designed with all modes of operation in mind (e.g. start up, turn down).

6. Plunger lift

Plunger lift production systems include a small cylindrical plunger which travels from a tubing stop installed as close to the formation as possible to a surface catcher/lubricator. The plunger travels in reaction to a time/pressure sequence in order to expel accumulated fluids into a surface collection system. The plunger is designed to serve as an interface between the fluid column and the lifting gas. As the plunger is surfacing, gas is breaking around the sides of the plunger, creating a high velocity sweeping effect that gathers fluids in its passage. This prohibits fluid fallback. The volume of fluid above the plunger should be the approximate amount of fluid arriving at the surface.

The produced slug size can be low (0.25 barrels) and cycle frequency high in order to minimise the impact of slugging on production facility operations. Typical designs range from 0.25-2 barrels/slug at 3 to 7 cycles per hr (depends on plunger fall-back time).