Casing, wellhead and BOP equipment tests

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206 testingAll pressure tests shall be recorded on pressure recorder charts. A record shall be kept of the volumes required to obtain the test pressure, and of the volumes returned when bleeding off.          

1 Casing tests

1.1 Pressure testing the casing

The casing shall be pressure tested directly after bumping of the top plug when the cement slurry has been displaced and while the cement is still soft. The maximum recommended test pressure shall be 70% of the casing internal yield pressure.

1.2 Subsequent pressure tests

The surface and intermediate casings shall be pressure tested after a period of about 30 days drilling or earlier, depending on hole deviation and dogleg severity, and thereafter when the Company drilling representative so requests. These casings shall also be tested after a liner has been installed, if well control aspects call for such a test Section 2.1.3.6 or if required according to the well programme.

The bottom 80 m (250 ft) of the casing or liner shall not be pressure tested during these subsequent tests in order to avoid damage to the primary cement. The same consideration applies if hydrocarbons are present behind the casing or liner, and pressure testing shall not be carried out within 80 m (250 ft) of the relevant section.

1.3 Pressure tests in wells where excessive casing wear is experienced

In wells where generally excessive casing wear is experienced, testing shall be done more frequently. The appropriate test frequency must be decided locally, and must be based on the estimated severity of casing wear. Factors affecting wear rate include:

·the type of drilling (i.e. rotating drillstring or turbine);

·mud quality;

·dog leg severity;

·roundtrip frequency.

Efforts must be made to minimise wear in casing, particularly in production strings, or in intermediate strings which will be used later on as production strings, i.e. with a production liner.

1.4 Pressure test specifications

The casing shall be tested to the expected wellhead pressure.

When establishing an internal test pressure, the differential pressure due to a difference in fluid level and/or fluid density, inside and outside the casing, shall be taken into account.

Casing under test shall support the pressure applied for at least 10 minutes.

1.5 Deviations from test procedures

Deviations from the above test procedures may only be made after written agreement of the Company drilling representative.

2 Tests for surface wellheads and BOP equipment used in operations on land and above water level

Testing requirements are given for the following equipment:

·Blowout preventers, wellhead components and their connections.

·The BOP operating unit.

·The choke manifold, valves, kill-and choke lines and valves on the side outlets of the casing spool.

·The kelly or top drive and kelly stop-cocks.

2.1 Blowout preventers, wellhead components and their connections

Pressure tests on the blowout preventers, wellhead components and their connections shall be made with water. The following test tools may be used:

·Plug Type Tester and test sub.

·Combination Cup Type Tester/hang-off tool.

·Cup Type Tester.

The PTT or combination CTT/hang-off tool is run on drillpipe and landed in the wellhead whilst the CTT is suspended on drillpipe. Test tool design, application, and testing procedures depend on the type and the design of the wellhead.

After any flanging up operation, the wellhead and BOP equipment shall be pressure tested to the rated working pressure of the wellhead or the blowout preventers, whichever is the lower, and to a low pressure of 500 psi. Wellhead side outlets below the test tool must be open during a test to avoid the risk of pressure increase below the test tool.

During subsequent drilling operations, the equipment shall be pressure tested at regular intervals Section 3.6.5 Subsequent tests of the wellhead and preventers shall be to the anticipated wellhead pressure with a maximum limit for the annular preventer of 70% of its working pressure.

The cup type tester shall be run with open ended pipe to prevent pressurisation of the casing. The pipe shall also be strong enough to withstand the tensile load caused by the hydraulic pressure on the cup area.

Blind/shear rams shall be tested with the test tool converted into a blind plug. During this test the wellhead side outlets below the tester shall be open to prevent pressurising the casing.

Casing rams plus BOP bonnets shall be pressure tested after installation with a Casing Ram Tester/CTT combination tool. The CRT/CTT combination tool should be pulled against the closed casing rams after which the test is carried out. The test can also be carried out against a PTT which is landed in the wellhead.

All equipment shall hold the applied test pressure for at least 10 minutes.

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

Retrievable packers with large slip areas may be used also.

It should always be possible to close-in the well or any annulus immediately, if flow is observed from the well or annulus.

Annular valves opened during pressure testing or any other type of operation shall not be left open unattended.

2.2 The BOP operating unit

The complete BOP operating unit shall be tested in accordance with the manufacturer's recommendations. It shall be pressure tested to its rated working pressure and should hold the test pressure applied for at least 10 minutes.

The tests shall also confirm that all BOP control:

·are properly connected;

·activate the functions indicated on them;

·perform as specified in Section 5.

2.3 The choke manifold, valves, kill-and choke lines and valves on the side outlets

The choke manifold, valves, kill-and choke lines and valves on the side outlets shall be pressure tested with water to the rated working pressure of the ram type preventers or the rated working pressure of the manifold, whichever is the lower. The equipment shall hold the test pressure applied for at least 10 minutes.

All lines shall be flushed to ensure they are not blocked.

No tests shall be performed against closed chokes.

2.4 The kelly or top drive and kelly stop-cocks

The kelly or top drive and kelly stop-cocks shall be pressure tested to their rated working pressure with a test sub. The equipment shall hold the applied test pressure for at least 10 minutes.

3 Tests for underwater wellheads and BOP equipment

3.1 Tests before lowering the BOP stack

All underwater BOP stack components which can be tested at surface shall be installed, checked, and pressure tested to their rated working pressure and to a low pressure of 3450 kPa (500 psi) whilst the stack is mounted on the test stump. After the surface tests, all clamp connections and all studded connections must be checked for tightness.

The complete BOP operating unit shall be tested in accordance with manufacturers' recommendations and pressure tested to its rated working pressure. The test shall include at least the following:

·to test every BOP control;

·to check that each function is properly connected;

·to activate the functions which are indicated from both control pods;

·to check test volumes and response times for each function.

The choke manifold, valves, kill-and choke lines and failsafe valves shall be pressure tested with water to the rated working pressure of the ram type preventers, or the rated working pressure of the manifold, whichever is the lower.

All lines shall be flushed to ensure they are not blocked.

No tests shall be performed against closed chokes.

The kelly or top drive and kelly stop-cocks shall be pressure tested to their rated working pressure with a test sub.

3.2 Tests during lowering and after connecting the BOP stack, kill-and choke lines, marine riser, and operating hoses.

When running the BOP stack on riser joints, the kill-and choke lines shall be pressure tested at least when the stack is below the splash zone and both before and after landing.

After the BOP stack is connected to the wellhead, a full function test on both pods, plus a low pressure test of 500 psi, shall be carried out.

All blowout preventers, wellhead components, their connections, and the kill- and choke lines shall be pressure tested with water. To prevent excessive pressuring of the kill-and choke lines, the BOP stack can be tested through the string by using a perforated test sub or test joint connected to the PTT.

The PTT or combination CTT/hang-off tool is landed inside the casing head housing and packs off the hole below the test tool seals. Caution is required to ensure that the casing below the test tool, or the casing/casing annulus, is not pressurised, should the test tool or casing hanger seals fail to seal. This can be done by monitoring accurately the fluid volume pumped during each pressure test. A test assembly with an extended "x-over" tool can be employed to avoid excess pressure being applied below the test tool.

The pressure applied shall be the rated working pressure of the wellhead or the ram type preventers, whichever is lower. It shall also be pressure tested to a low pressure of 500 psi.

Subsequent pressure tests of the wellhead or preventers shall be to the anticipated wellhead pressure with a maximum limit for the annular preventer of 70% of its working pressure. It shall also be pressure tested to a low pressure of 500 psi.

All equipment shall hold the applied test pressure for at least 10 minutes.

The opening/closing times and the volumes of hydraulic operating fluid required for the operation of the various underwater stack components (i.e. rams, kill-and choke line valves, annular preventers, hydraulic connectors, etc.) shall be recorded during testing of the stack underwater. These results shall be compared with the normal opening/closing times and volumes required of the hydraulic system. Any major differences are an indication that the system is not operating 'normally' and shall require further investigation and possible repair.

4 Tests for accumulators

The accumulator bottles precharge pressure (nitrogen) shall be checked prior to drilling out cement in the casing shoe. Unless otherwise specified, the precharge pressure for a 3000 psi WP system should be 1000 psi.

Accumulator tests should be performed prior to first use of BOP's, or after repairs have been made to the accumulator system, i.e. bottles, bladders, pumps, etc.

The accumulator unit performance test is made by operating all BOP's on the stored energy in the accumulator, i.e. the pressure and the volume available without recharging.

The complete test procedure is as follows:

·Check accumulator fluid pressure.

·Check accumulator reservoir level.

·Switch off accumulator pumps.

·Close and open all preventers and check accumulator fluid pressure after each function and the volume of fluid used for each function for subsea units; record closing times. Adequate pressure and volume should still be present to close one annular and one ram type preventer. Precharge pressure should still be the same in all accumulator bottles.

·Switch on accumulator pumps.

·Record accumulator recharging time.

It is recommended to check the recharging capacity of the airpumps with the electric power switched off prior to start up of a newly contracted rig.

·Check BOP closing times and accumulator recharge time with manufacturer's data for the system in use.

·Cycle the annular preventer and check that the pumps will automatically start when the closing unit pressure has decreased to less than 90 percent of the accumulator operating pressure. This should be checked with only the electric pumps operative.

·Should an emergency control system be employed, this should also be tested at the same time as the accumulator unit.

·Results should be recorded on the daily tour sheets and the Blowout Prevention Equipment Checklist (click link).

It is of utmost importance that the unit can be charged with only one of the two power systems operative.

5 Test frequency

The pressure tests of all blowout preventers, wellhead components and their connections, BOP operating unit, choke manifold, kill-and choke lines, kelly or top drive and kelly stop-cocks shall be made in line with government regulations and/or

·After installation of wellhead and BOP assembly and prior to drilling.

·Weekly (the period between tests may be extended to 14 days maximum, depending on type of operation being carried out and still have to be carried out during that period).

·Prior to drilling into expected high pressures.

·Prior to a production test.

·At any time requested by the Company drilling representative.

Results of all pressure tests shall be recorded on the daily tour sheets and the Blowout Prevention Equipment Checklist Section 6.19.

6 Functional tests, inspections and precautions

All preventers which close around pipe, all pressure and manually operated kill-and choke lines valves, and all kelly cocks, shall be operated each time a new bit has been run to the shoe of the casing.

All ram type BOP's should be function tested at an operating pressure of not more than 1500 psi.

The blind/shear rams shall be operated at least once a week.

Should any of the above tests indicate faulty equipment, this equipment must be repaired and re-tested before drilling, or before any other operation related thereto is continued.

Inspect the tightness of flange bolts and clamps frequently, particularly after pressure testing.

Pump through kill-and choke lines at regular intervals and displace weighted mud from choke manifold and kill lines. In freezing conditions replace mud in lines by anti-freeze fluid.

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