Examples of programs for Pressure Testing Wellheads. 1. Onshore 20in Casing After installing the 20in casing and 20.3/4in -3 000 psi CHH, pressure test CHH and BOP’s to 500 psi against the bag type annular preventor and cement plug with the BHA in the casing prior drilling out the shoe track. 13.3/8in Casing After bumping … Pressure Testing Wellheads
The well completion typically includes the perforations, sand exclusion system, (liner), tubing, wellhead, tubing accessories, packers, associated safety equipment and Xmas tree. The perforations, gravel pack etc. provide the ‘inflow system’ into the well structure, while the tubing with flow controls, safety devices for isolating the reservoir, the Xmas tree and, where necessary, artificial lift … General completion design considerations
This article describes the Completion design considerations. Reservoir considerations Reservoir drive mechanism may determine whether or not the completion interval will have to be adjusted as gas-oil or water-oil contacts move. A water drive situation may indicate water production problems. Dissolved gas drive will result in pressure depletion and may indicate artificial lift. Dissolved gas … Completion design considerations
This article descirbes the Tubing and Casing Connections Functional and Operational requirements. Functional requirements: – strength -sealing properties, -resistance to damage, corrosion or erosion. Operational requirements: -easy to make-up and break-out in the field (e.g. handling, stabbing, testing, etc); -reusable; Connection types For low pressure wells API 8RD thread connections have been the standard in … Tubing and Casing Connections
The Purpose of the Packer Accessories and tailpipe assembly is described in this article. the ability to isolate the well below the packer; the ability to land off downhole pressure and temperature gauges and redirect flow into the tailpipe higher up; the ability to guide the exit from and retrieval into the tubing string of … Packer Accessories and tailpipe assembly
The designer must ensure that there is critical flow through the choke in order to eliminate the effects of downstream pressure variations on the formation. This is achieved when the FTHP is approximately 1.7 times the downstream flowline pressure. Actuated chokes By its very nature the choke is subjected to very high pressure drops, which … Completion Chokes
Guidelines for starting and operating an Electrical Submersible Pump (ESP) system. 1 Personnel A field engineer from the pump supplier should be present whenever an Electrical Submersible Pump is to be started for the first time. The field engineer should remain on the location until the well has stabilised and the Electrical Submersible Pump is … Starting up and operating an Electrical Submersible Pump (ESP)
Retrieval of an Electrical Submersible Pump (ESP) requires similar precautions to those taken during installation and some additional points should also be considered when retrieving ESPs. Analysis of the reasons for ESP failure may not be possible if additional damage is sustained by the equipment during retrieval from a well, or during subsequent storage and … ESP – Retrieving Electrical Sumbersible Pumps
Prior to leaving location it is recommended that a well test is carried out to the Electrical Submersible Pump using a dedicated test separator with the rig on site. This will ensure that any immediate problems can be rectified without having to move a rig back. In addition the use of a dedicated test separator … ESP – Testing
Proper handling and running procedures are essential to ensure cable reliability. The majority of cable failures are caused by damage resulting from improper handling. The ESP cable is often the most expensive item in an Electrical Submersible Pump (ESP) system. It is easily damaged if subjected to incorrect handling procedures. The weight of a drum … ESP – Cable handling