In 2013, a technology-development project began that digitized, automated, and applied analytics to blowout preventer (BOP) pressure testing. At the time, BOP testing was considered a neglected process that could benefit from a technology-development project.
As a result of the deployment of automated BOP testing, significant improvements have been achieved in process safety, personal safety, and rig-time savings. Rig-time savings of up to 50% of the BOP testing time have been achieved.
Analog circular pressure chart recorders were replaced with personal-computer-based digital pressure-recording software. An automated valve-actuation device was developed that can retrofit any API 6A-style gate valve. An acoustic detection system for leaking valve identification was developed. A novel method of directly measuring a leak using a linear press pump was trialed that, after additional development work, may supersede the indirect leak measurement of pressure-decay leak testing.
Future enhancements and development are under way to go beyond BOP testing. These are being developed to cover casing-pressure tests, casing-inflow tests, and completions pressure tests. Also, field trials will begin soon to apply this technology to completion and hydraulic-fracturing domains.
Why BOP Tests Are Needed
At the most basic level, BOP systems must be maintained and inspected to ensure that the equipment will function properly. Regulators, operators, and drilling contractors have put in place the requirement to test BOP systems as a method of inspection and assurance. BOP testing is a process-safety-critical step in the drilling, completion, workover, and plug-and-abandonment phases of well operations.
A BOP test is a sequence of pressure tests of portions of the well-control equipment conducted until the entire well-control system is tested. Tests can be either offline (not part of the critical path of well-construction activities) or online (a so-called “flat-line” activity that is part of the critical path). The cost for online testing is the time required for it multiplied by the full-spread day rate of all the time-based drilling contracts.
Pressure-Decay Leak Testing
BOP testing uses pressure-decay leak testing. Well-control equipment is pressurized to a predetermined target, the pressurized volume is isolated from the pump with a valve, and the pressure is observed. A passing result is determined if the steady-state pressure-decline rate is less than a specified rate for a given period of time. Otherwise, the result is a failure.
One shortcoming of pressure-decay leak testing is that it is an indirect leak-flow measurement. Any correlation between the leak-flow rate and pressure decay must be performed with the same volume and fluid compressibility. The consequence is that a small-volume test (e.g., a stump test) and a large-volume test (e.g., a subsea BOP test through the choke line) will have different leak-flow rates for the same pressure-decline rates (likewise two differently sized test volumes will have different pressure-decline rates for the same leak-flow rate). A similar phenomenon occurs when tests are conducted on systems with different fluid compressibilities, for example when a different amount of air is trapped in a system of the same volume.
Typically, a one-size-fits-all pressure-decline criterion is specified for all tests regardless of the volume or fluid compressibility.
Analog Circular Pressure Chart Recorder
When the automated BOP testing technology development project began in 2013, analog circular pressure chart recorders were being used widely. A test’s pass/fail determination relied on human interpretation of the analog data plotted by the circular chart recorder. Reports of the tests were generated by hand. Digital pressure-recording devices, with automated pass/fail determination, had entered the market only a few years earlier and were just beginning to displace circular pressure chart recorders, primarily in high-day-rate markets such as offshore.
Manual Valve Position Verification and Actuation
BOP testing consists of several pressure tests with different valve line-ups in order to test all the components of the BOP system. Changing a valve’s position was a manual process. In this method, verification of valve position also relied on humans. Anecdotal evidence suggests that, during a testing sequence, valves were not always in the intended position and, thus, testing was not conducted according to plan. No data exists on how often this occurred.
When large offshore stacks are pressure tested, valves often require an individual in a man-riding harness being lifted by a tugger winch to open or close a valve. This operation created notable health and safety exposures, such as working at heights.
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