This valve allows fluids to pass up or be pumped down the production tubing. When closed the DHSV forms a barrier in the direction of hydrocarbon flow, but fluids can still be pumped down for well kill operations. It is placed as far below the surface as is deemed safe from any possible surface disturbance including cratering caused by the wipeout of the platform. Where hydrates are likely to form (most production is at risk of this), the depth of the SCSSV (surface-controlled, sub-surface safety valve) below the seabed may be as much as 1 km: this will allow for the geothermal temperature to be high enough to prevent hydrates from blocking the valve. On wells with gas lift capability, many operators consider it prudent to install a valve, which will isolate the "A" annulus for the same reasons a DHSV may be needed to isolate the production tubing in order to prevent the inventory of natural gas downhole from becoming a hazard as it became on Piper Alpha. This is a welded/machined product which contains a "side pocket" alongside the main tubular conduit. The side pocket, typically 1" or 1½" diameter is designed to contain gas lift valve, which allows flow of High pressure gas into the tubing there by reducing the tubing pressure and allowing the hydrocarbons to move upwards. This device is used for artificial lift to help provide energy to drive hydrocarbons to surface if reservoir pressure is insufficient. A completion component fabricated as a short section of heavy wall tubular with a machined internal surface that provides a seal area and a locking profile. Landing nipples are included in most completions at predetermined intervals to enable the installation of flow-control devices, such as plugs and chokes. Three basic types of landing nipple are commonly used: no-go nipples, selective-landing nipples and ported or safety-valve nipples. The sliding sleeve is hydraulically or mechanically actuated to allow communication between the tubing and the 'A' annulus. They are often used in multiple reservoir wells to regulate flow to and from the zones. The packer isolates the annulus between the tubing and the inner casing and the foot of the well. This is to stop reservoir fluids from flowing up the full length of the casing and damaging it. It is generally placed close to the foot of the tubing, shortly above the production zone. This is an electronic or fiberoptic sensor to provide continuous monitoring of downhole pressure and temperature. Gauges either use a 1/4" control line clamped onto the outside of the tubing string to provide an electrical or fiberoptic communication to surface, or transmit measured data to surface by acoustic signal in the tubing wall.