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Testing, Inspection and Maintenance of BOP

by Chess Subsea Engineering · Published October 2, 2015 · Updated November 1, 2016

Testing, Inspection and Maintenance of BOP

1.0 Testing Periods

Pressure test on the well control equipment should be conducted at least once every 21 days.

After setting, CSG
Prior to entering a known transition zone
After B.O.P repairs or change

NB: In addition to this, prior to spud and upon installation. Also after the disconnection or repair of any pressure containment seal in the BOP stack, choke line or choke manifold but limited to the affected component.
Initial test should be the lesser of the rated working pressure of the stack wellhead upper part of the CSG.
Low Pressure Testing i.e. Diverter System = 200 – 300 psi

https://www.youtube.com/watch?v=Rknp7tIPCuc

1.1 Testing During Operations

Stack should be tested to at least 70% of its rated working pressure but limited to the lesser of the rated working pressure of the wellhead or 70% of the minimum internal yield of the upper part of the CSG string.
Annular – Tested to 70% API RP 53 of its rated working pressure.
Company policy might dictate that annular be tested to 50% of working rate to prevent excessive wear.
Choke Manifold, V/VS safety etc, same as stack test.
On stump tested to rated working pressure.
Factory tested to 150% of rated working pressure.

1.2 A.P.I. Regulations on Closing Units

Surface:

Minimum Requirements: All surface closing units should be equipped w / sufficient volumetric capacity to provide the useable fluid volume (w / pumps isolated) to close 1 Pipe Ram, 1 Annular & open the Hyd. Choke valve.
Accumulator Response Time: Response time between activation and complete operation of a function is based on BOP or valve closure and seal off.For surface installations, the BOP control system should be capable of closing each ram BOP within 30 seconds. Closing time should not exceed 30 seconds for annular BOPs smaller than 18 ¾ inches nominal bore and 45 seconds for annular preventers of 18 ¾ nominal bore and larger. Response time for choke and kill valves (either open or close) should not exceed the minimum observed ram close response time.For subsea installations, the BOP control system should be capable of closing each Ram preventer within 45 secs and Subsea closing unit for annular preventer should not exceed 60 secs for Annular Preventer.
Pump Capacity: with the accumulator isolated, the pump should be capable of closing annular & opening choke valves & obtain a minimum of 200 psi above pre-charged within 2 minutes or less.
Reservoir Capacity: 2 X times useable fluid capacity of the system.
Pump Coming In Time: NB: Usable fluid is the volume of fluid recoverable between accumulator operating pressure & 200 psi above pre – charge.

1.3 A.P.I. Definations

Every installed Ram BOP should have as a minimum a working pressure equal to the Maximum Anticipated Surface Pressure (MASP) to be encountered.

Rated Working Pressure: The maximum internal pressure that equipment is designed to contain or control.Note: Rated Working Pressure should not be confused with test pressure.
Closing Ratio: The ratio of the wellhead pressure to the pressure required to close the BOP.
Drill Pipe Safety Valve: An essentially full – opening valve located on the drill floor with threads to match the drill pipe connection in use. This valve is used to close of or secure the drill pipe to prevent flow.
Usable Fluid Volume: The volume of fluid recoverable from an accumulator between accumulator operating pressure and 200 psi above the pre-charge pressure.
Accumulator Pre-charge: The precharge pressure on each accumulator bottle should be measured prior to each BOP stack installation on each well and adjusted if necessary.The minimum precharge pressure for a 3000 psi working pressure accumulator should be 1000 psi. The minimum precharge pressure for a 5000 psi working pressure should be 1500 psi. Only nitrogen gas should be used for accumulator precharge. The precharge pressure should be checked and adjusted to within 100 psi of the selected precharge pressure at the start of drilling each well.For subsea installation the precharge pressure shall compensate for the water depth the BOP’s will be operating in. The subsea accumulator bottle calculations should compensate hydrostatic pressure gradient at a rate of 0.445 psi / ft of water depth.
Accumulator Response Time: Response time between activation and complete operation of function is based on BOP or valve closure and seal off. For surface installations, the BOP control system should be capable of closing each RAM BOP in 30 seconds or less. Closing time should not exceed 30 seconds for annular BOP’s (18 ¾ ) and 45 seconds for annular preventers 18 ¾ and larger.

For subsea installations, the BOP control system should be capable of closing each RAM BOP in 45 seconds or less, closing time should not exceed 60 seconds for annular BOPs. Operating response time for choke and kill valve (either open or close) should not exceed the minimum observed RAM ROP close response time. Time to unlatch the lower marine riser package should not exceed 45 seconds.

2.0 Types of Tests

Test programmes incorporate:

Visual inspections
Functional operations
Pressure tests
Maintenance practices
Drills

2.1 Inspection Test

The inspection test is aimed to examine the flaws that may influence equipment performance. These tests may include but not limited to visual, dimensional, audible, hardness, functional and pressure tests.

2.2 Pressure Tests:

Periodic application of pressure to a piece of equipment or system to verify the pressure containment capability for the equipment or system. Wellbore test is another descriptive term frequently used synonymously for pressure testing.
All blowout preventer components that may be exposed to well pressure should be tested first to a low pressure of 200 to 300 psi and then to a high pressure.

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