Pressure Testing of Well Control Equipment


This article describes the main requirements for Pressure Testing of Well Control Equipment.

Well Heads and BOP Equipment

Pressure tests on the ram type preventers, other BOP equipment, wellhead components and their connections in general shall be made in line with API RP 53, but see Drilling Programme for the minimum required test pressures.

Where wellhead or BOP outlets are opened for testing or any other purposes theyshall not be left unattended under any circumstances.

Manufacturer's approved handles shall be securely fitted to all wellhead and BOP valves

During subsequent drilling operations, the equipment shall be pressure-tested at regular intervals using a plug type or cup type tester.  Test to at least the anticipated pressures or to the original casing test pressure (in case a cup type tester is used), whichever is lower.

Plug and cup type testers suitable for pressure-testing the wellhead and BOP equipment on all casing strings shall be available on the rig site.

Use proper cup size for various casing weights.  Retrievable packers with large slip areas may also be used if available.

The pressure test shall consist of:

  • Low pressure test - 500 psi
  • High pressure test to the full rated working pressure of the equipment
  • All equipment shall hold the low pressure test for 10 minutes and the high pressure test for 10 minutes.

Pressure Test Wellhead Equipment

After each complete installation, the wellhead and ram type BOP equipment shall be pressure-tested, using a plug type tester, to the rated working pressure of the wellhead, the ram type preventers or the pressure detailed in the Drilling Programme, whichever is lower.  The wellhead side outlets below the tester shall be open, to prevent pressuring the casing.

Seals and bushings around casing stubs shall be tested through the test port to only 50% of the collapse rating of the casing provided that this does not exceed the manufacturers rating for the casing hanger when piston forces and string weight are taken into account.  These seals can later be tested to 65% of the casing burst rating (or flange rating whichever is the lower) using a cup-type tester (test port open).  Ensure that the cup-type tester does not leak and the drill pipe is open so that the cemented casing is not tested as well.

During the drilling and completion phase, the outer side outlets of the wellhead exposed to the live annulus shall have Manually operated side outlet valves.

Pressure Test BOP equipment

The annular preventer shall be pressure-tested to maximum 70% of its rated working pressure unless specified differently in the Drilling Programme, and then only when closed around the pipe.

The complete BOP operating unit shall be tested in accordance with Manufacturer's recommendations and pressure-tested to its rated working pressure / well rated pressure, whichever is lower.

The choke manifold, valves, kill and choke lines and valves on side outlets shall be pressure-tested with water to the test pressure of the ram type preventers.

All lines shall be flushed to ensure they are not blocked.  No tests shall be performed against closed chokes.

The kelly and kelly stop-cocks shall be pressure-tested to their rated working pressure with a test sub. Pumps, discharge lines standpipe manifold shall be pressure tested.

If the BOP has been pressure and function tested on the stump, or if a new spool has been installed, only the new connections need testing.

If the BOP is moved between wells, the BOP shall be fully pressure/function tested prior to any operations on that well.

Pressure Test Frequencies

The pressure tests of all blowout preventers, wellhead components and their connections, BOP operating unit, choke manifold, kill and choke lines, kelly and kelly-cocks shall be made:

  • After installation of wellhead and BOP assembly and prior to drilling.
  • Every 14 days. This period between tests may be extended, depending on the type of operation being carried out and yet to be carried out during that period, but only after consultation with the Head of Operations.
  • Prior to drilling into a suspected high pressure zone.
  • After setting casing and re-nippling BOP.
  • When rough drilling conditions are experienced e.g. stack shaking.
  • After changing out rams.
  • Any time requested by the Drilling Supervisor.

The results of all pressure tests shall be recorded on the Test Sheet for Blowout Preventers and Related Equipment.

Pressure Test Casing Strings

After Installation

Newly installed casing strings shall be pressure tested to pressures as given in the Drilling Programme. The test pressures will depend on the reservoir and the well location (onshore/offshore). Ideally, this should be performed immediately once the cement slurry is in place (i.e. immediately after bumping the top plug) to prevent the formation of a micro-annuli.

The test pressure shall be limited by the internal yield (burst) pressure of the casing (or coupling, if lower) and/or the maximum collapse pressure of the cementing plugs.  The effects of differential pressure resulting from a difference in the fluid level and/or a difference in mud density in the casing and annulus shall be considered when establishing the internal test pressure.

In the case of liners, the test pressure immediately after bump should not exceed 1500 psi unless specifically authorised in the drilling programme.

Note:   The acceptance criteria for the test shall be a stable pressure (i.e. straight line on the pressure recorder) for a minimum of 10 minutes.

Casing test pressures are predetermined due to drilling in known reservoirs.

In general the following equations may be used for casing pressure tests.

For Production Casing the maximum expected surface pressure shall consider closed in pressure arising from complete evacuation of the string to hydrocarbon gas from the deepest TD:


Surface Pressuremax = Po - HHgas



Po = Reservoir Pore Pressure @ deepest section TD as per well proposal (psi)

HHgas = (TVD of Section TD) x (Expected Gas Gradient) (psi)


For Intermediate Casing the intermediate casing string shall be tested to the maximum expected surface pressure as defined in its design criteria which shall be clearly identified in the Drilling Programme.


In general the maximum surface pressure shall be the lesser of:

a.   Closed in casing head pressure arising from the casing being completely evacuated to hydrocarbon gas from the casing shoe using the formation strength gradient criteria

Surface Pressuremax = Maximum Pressure at Shoe - HHgas


Max Pressure at Shoe = Max expected formation strength gradient at shoe x Shoe depth (psi)

b.     Closed in casing head pressure arising from the casing being completely evacuated to hydrocarbon gas from deepest section TD using the pore pressure gradient criteria.
Surface Pressuremax = Po - HHgas


Po= Reservoir Pore Pressure @ deepest section TD as per well proposal (psi)

HHgas = TVD of Section TD x expected gas gradient (psi)

Subsequent Casing Pressure Tests

Cemented casing shall not be tested to excessive pressure as this may lead to loss of zonal isolation - ballooning of the casing can cause the formation of a micro-annulus after the test.

Note:    In wells where casing wear or corrosion is experienced or expected, calliper logs should be performed. The reduced strength of the casing can thus be calculated and if this value is less than the operating (design) criteria then these criteria and pressure testing requirements will have to be reviewed to prevent total failure of the casing. Operating (design)  criteria and pressure testing requirements may also be changed due to changes in downhole reservoir pressures (depletion) or the installation of a straddle or tie-back string to cover detected weak spots in the string. The basis for design of pressure tests shall be highlighted in the Drilling Programme.

Functional Tests, Inspection and Precautions

BOP’s shall be function tested daily. All pressure and manually operated kill and choke line valves and kelly cocks shall be function tested every 7 days.

The blind rams or blind/shear rams shall be functioned each time the bit is pulled.

Should any of the above tests indicate faulty equipment, this equipment shall be repaired before drilling or any other operation related thereto is continued.

Frequently inspect tightness of flange bolts and clamps, particularly before and after pressure testing.

Pump through kill and choke lines at regular intervals. Do not leave weighted mud in choke manifold and kill lines but ensure that they are kept full of fluid.


#1 fatima 2014-02-08 05:49
hi every one.i want to change well head pressure to bottom hole pressure,i need some one help me please?

You have no rights to post comments

Additional information