Well completion is the process of making a well ready for production (or injection) after drilling operations. This principally involves preparing the bottom of the hole to the required specifications, running in the production tubing and its associated down hole tools as well as perforating and stimulating as required. Sometimes, the process of running in and cementing the casing is also included. After a well has been drilled, should the drilling fluids be removed, the well would eventually close in upon itself. Casing ensures that this will not happen while also protecting the wellstream from outside incumbents, like water or sand.

Lower completion (downhole completion) This refers to the portion of the well across the production or injection zone. The well designer has many tools and options available to design the lower completion (downhole completion) according to the conditions of the reservoir. Typically, the lower completion is set across the productive zone using a liner hanger system, which anchors the lower completion to the production casing string. The broad categories of lower completion are listed below.

Barefoot completion This type is the most basic, but can be a good choice for hard rock, multi-laterals and underbalance drilling. It involves leaving the productive reservoir section without any tubulars. This effectively removes control of flow of fluids from the formation; it is not suitable for weaker formations which might require sand control, nor for formations requiring selective isolation of oil, gas and water intervals. However, advances in interventions such as coiled tubing and tractors means that barefoot wells can be successfully produced.

Open hole The production casing is set above the zone of interest before drilling the zone. The zone is open to the well bore. In this case little expense is generated with perforations. Log interpretation is not critical. The well can be deepened easily and it is easily converted to screen and liner. However, excessive gas and water production is difficult to control, and may require frequent clean outs. Also the interval cannot be selectively stimulated.

Open hole completion This designation refers to a range of completions where no casing or liner is cemented in place across the production zone. In competent formations, the zone might be left entirely bare, but some sort of sand-control and/or flow-control means are usually incorporated.

Openhole completions have seen significant uptake in recent years, and there are many configurations, often developed to address specific reservoir challenges. There have been many recent developments that have boosted the success of openhole completions, and they also tend to be popular in horizontal wells, where cemented installations are more expensive and technically more difficult. The common options for openhole completions are:

Pre-holed liner Also often called pre-drilled liner. The liner is prepared with multiple small drilled holes, then set across the production zone to provide wellbore stability and an intervention conduit. Pre-holed liner is often combined with openhole packers, such as swelling elastomers, mechanical packers or external casing packers, to provide zonal segregation and isolation. It is now quite common to see a combination of pre-holed liner, solid liner and swelling elastomer packers to provide an initial isolation of unwanted water or gas zones. Multiple sliding sleeves can also be used in conjunction with openhole packers to provide considerable flexibility in zonal flow control for the life of the wellbore.

This type of completion is also being adopted in some water injection wells, although these require a much greater performance envelope for openhole packers, due to the considerable pressure and temperature changes that occur in water injectors.

Openhole completions (in comparison with cemented pipe) require better understanding of formation damage, wellbore clean-up and fluid loss control. A key difference is that perforating penetrates through the first of formation around the wellbore, whilst openhole completions require the reservoir fluids to flow through all of the filtrate-invaded zone around the wellbore and lift-off of the mud filter cake.

Many openhole completions will incorporate fluid loss valves at the top of the liner to provide well control whilst the upper completion is run.

There are an increasing number of ideas coming into the market place to extend the options for openhole completions; for example, electronics can be used to actuate a self-opening or self-closing liner valve. This might be used in an openhole completion to improve clean-up, by bringing the well onto production from the toe-end for 100 days, then self-opening the heel-end. Inflow control devices and intelligent completions are also installed as openhole completions.

Pre-holed liner may provide some basic control of solids production, where the wellbore is thought to fail in aggregated chunks of rubble, but it is not typically regarded as a sand control completion.

Slotted liner Slotted liners can be selected as an alternative to pre-holed liner, sometimes as a personal preference or from established practice on a field. It can also be selected to provide a low cost control of sand/solids production. The slotted liner is machined with multiple longitudinal slots, for example 2 mm × 50 mm, spread across the length and circumference of each joint. Recent advances in laser cutting means that slotting can now be done much cheaper to much smaller slot widths and in some situation slotted liner is now used for the same functionality as sand control screens.

Openhole sand control This is selected where the liner is required to mechanically hold back the movement of formation sand. There are many variants of openhole sand control, the three popular choices being stand-alone screens, openhole gravel packs (also known as external gravel packs, where a sized sand 'gravel' is placed as an annulus around the sand control screen) and expandable screens. Screen designs are mainly wire-wrap or premium; wire-wrap screens use spiral-welded corrosion-resistant wire wrapped around a drilled basepipe to provide a consistent small helical gap (such as , termed 12 gauge). Premium screens use a woven metal cloth wrapped around a basepipe. Expandable screens are run to depth before being mechanically swaged to a larger diameter. Ideally, expandable screens will be swaged until they contact the wellbore wall.

Horizontal open hole completions This is the most common open hole completion used today. It is basically the same described on the vertical open hole completion but on a horizontal well it enlarges significantly the contact with the reservoir, increasing the production or injection rates of your well. Sand control on a horizontal well is completely different from a vertical well. We can no longer rely on the gravity for the gravel placement. Most service companies uses an alpha and beta wave design to cover the total length of the horizontal well with gravel. It's known that very long wells (around 6000 ft) were successfully gravel packed in many occasions, including deepwater reservoirs in Brazil.

Liner completions In this case the casing is set above the primary zone. An un-cemented screen and liner assembly is installed across the pay section. This technique minimizes formation damage and gives the ability to control sand. It also makes cleanout easy. Perforating expense is also low to non-existent. However, gas and water build up is difficult to control and selective stimulation not possible the well can't be easily deepened and additional rig time may be needed.

Perforated liner Casing is set above the producing zone, the zone is drilled and the liner casing is cemented in place. The liner is then perforated for production. This time additional expense in perforating the casing is incurred, also log interpretation is critical and it may be difficult to obtain good quality cement jobs.

Perforated casing Production casing is cemented through the zone and the pay section is selectively perforated. Gas and water are easily controlled as is sand. The formation can be selectively stimulated and the well can be deepened. This selection is adaptable to other completion configurations and logs are available to assist casing decisions. Much better primary casing. It can however cause damage to zones and needs good log interpretation. The perforating cost can be very high.

Cased hole completion This involves running casing and a liner down through the production zone, and cementing it in place. Connection between the well bore and the formation is made by perforating. Because perforation intervals can be precisely positioned, this type of completion affords good control of fluid flow, although it relies on the quality of the cement to prevent fluid flow behind the liner. As such it is the most common form of completion.

Conventional completions Casing flow: means that the producing fluid flow has only one path to the surface through the casing. Casing and tubing flow: means that there is tubing within the casing that allows fluid to reach the surface. This tubing can be used as a kill string for chemical injection. The tubing may have a "no-go" nipple at the end as a means of pressure testing. Pumping flow: the tubing and pump are run to a depth beneath the working fluid. The pump and rod string are installed concentrically within the tubing. A tubing anchor prevents tubing movement while pumping. Tubing flow: a tubing string and a production packer are installed. The packer means that all the flow goes through the tubing. Within the tubing you can mount a combination of tools that will help to control fluid flow through the tubing. Gas lift well: gas is fed into valves installed in mandrels in the tubing strip. The hydrostatic head is lowered and the fluid is gas lifted to the surface. Single-well alternate completions: in this instance there is a well with two zones. In order to produce from both the zones are isolated with packers. Blast joints may be used on the tubing within the region of the perforations. These are thick walled subs that can withstand the fluid abrasion from the producing zone. This arrangement can also work if you have to produce from a higher zone given the depletion of a lower zone. The tubing may also have flow control mechanism. Single-well concentric kill string: within the well a small diameter concentric kill string is used to circulate kill fluids when needed. Single-well 2-tubing completion: in this instance 2 tubing strings are inserted down 1 well. They are connected at the lower end by a circulating head. Chemicals can be circulated down one tube and production can continue up the other.

Completion components The upper completion refers to all components from the bottom of the production tubing upwards. Proper design of this "completion string" is essential to ensure the well can flow properly given the reservoir conditions and to permit any operations as are deemed necessary for enhancing production and safety.

Wellhead with situation control

This is the pressure containing equipment at the surface of the well where casing strings are suspended and the blowout preventer or Christmas tree is connected.

Christmas tree

This is the main assembly of valves that controls flow from the well to the process plant (or the other way round for injection wells) and allows access for chemical squeezes and well interventions.

Tubing hanger