closing unit

A closing unit is the hydraulic power system mounted on or adjacent to a drilling rig that stores pressurized hydraulic fluid in nitrogen-precharged accumulator bottles and delivers the high-pressure hydraulic flow required to close blowout preventer rams, annular preventers, and associated well control valves within the API-mandated response time during a well control emergency, providing BOP closure capability independent of rig electrical power or pneumatic supply; in Western Canada Sedimentary Basin drilling operations, the closing unit is a mandatory component of the well control equipment package for all wells drilled deeper than surface casing under AER Directive 036 (Drilling Blowout Prevention Requirements) and BC Energy Regulator requirements, with accumulator capacity, pre-charge pressure, pump redundancy, and function test frequency specified by API 53 (Blowout Prevention Equipment Systems for Drilling Wells) and by AER-mandated well-specific BOP test procedures that must be submitted to the AER in the Drilling Program before spud. The closing unit's fundamental design requirement is that it must be capable of closing all BOP components and maintaining sealing pressure with the hydraulic pumps isolated (not running), demonstrating through Boyle's Law calculation and function testing that the stored accumulator volume at the nitrogen pre-charge pressure of 6,900 kPa (1,000 psi) can supply all BOP closing volumes plus a 200 psi (1,380 kPa) reserve above pre-charge, as required by API 53 to confirm 1.5 times the calculated closing volume is stored; this stored-energy test requirement ensures that total loss of rig power or air supply during a kick, which may coincide with the well control event itself, does not prevent BOP activation. In WCSB surface BOP stacks used on land rigs, the closing unit operates at a system pressure of 20,700 kPa (3,000 psi) using water-glycol hydraulic fluid (fire-resistant per API 16D specifications) distributed to each BOP function through a manifold with individual pressure regulators that reduce annular preventer closing pressure to 10,300 to 13,800 kPa (1,500 to 2,000 psi) for stripping operations while maintaining full 20,700 kPa for ram closure during a kick.

• Accumulator bottle capacity calculation and API 53 compliance verification for WCSB BOP stacks: Accumulator bottle capacity for a WCSB closing unit is calculated by summing the hydraulic closing volumes of all BOP components on the stack (annular preventer, upper pipe rams, lower pipe rams, blind-shear rams, choke line valve, kill line valve) from the BOP manufacturer's data sheets, multiplying the total closing volume by 1.5 per API 53, then dividing by the usable volume per bottle calculated from Boyle's Law: usable volume per bottle equals total bottle volume times (system pressure minus pre-charge pressure) divided by system pressure. For a standard 10-litre accumulator bottle (2.64 US gallon) at 20,700 kPa system pressure and 6,900 kPa pre-charge, usable volume per bottle is 10 litres times (20,700 minus 6,900) divided by 20,700, equal to 6.67 litres; a WCSB 5-component BOP stack with total closing volume of 80 litres requires 80 times 1.5 divided by 6.67, or 18 bottles minimum. In practice, WCSB land rig closing units carry 16 to 24 accumulator bottles depending on stack configuration; offshore or deep HPHT wells with larger bore BOP stacks and additional valve functions may require 30 to 40 bottles. AER Directive 036 requires function testing of the closing unit before spud and after any BOP maintenance, with documented starting pressure, ending pressure after all closures with pumps isolated, and confirmation that the residual pressure exceeds pre-charge by at least 1,380 kPa.
• Hydraulic pump redundancy and power supply requirements for WCSB closing units: API 53 and AER Directive 036 require closing units to have at least two independent hydraulic pump sources: an electrically driven pump powered from the rig's electrical system and an air-driven (pneumatic) pump powered from the rig's compressed air supply, so that loss of either power source alone cannot disable BOP closure capability. In WCSB land drilling operations, the electric pump typically has a capacity of 30 to 60 L/min at 20,700 kPa and is the primary pump used to maintain accumulator pressure during normal drilling; the air pump (rated at 15 to 30 L/min at 20,700 kPa from 690 to 760 kPa rig air supply) serves as backup. A third pump option in modern WCSB closing units is a diesel-engine-driven pump on a dedicated closing unit skid that operates independently of both rig power and rig air, providing well control capability even during a total rig power failure coinciding with a well control event. Pump cut-in and cut-out pressures in WCSB closing units are typically set at 18,600 kPa (cut-in, pump starts) and 20,700 kPa (cut-out, pump stops) to maintain the system within operating range; if accumulator pressure drops below 18,600 kPa during normal operations, it indicates a hydraulic leak or excessive BOP cycling that must be investigated before drilling resumes.
• Control station requirements and remote panel locations for WCSB drilling and workover rigs: API 53 and AER Directive 036 require that the closing unit be controllable from at least three locations on a WCSB drilling rig: the primary accumulator panel at the closing unit skid (full control of all BOP functions, accumulator pressure gauges, and pump switches); the driller's panel at the driller's console on the rig floor (control of all critical BOP functions without requiring the driller to leave the rig floor during a kick); and a remote panel accessible without crossing the rotary table or traveling block (located on the opposite side of the rig floor or at the pipe rack for emergency use when the primary rig floor is inaccessible). On WCSB workover rigs performing tubing changes or well interventions on existing producing wells, a fourth remote panel is sometimes required at the wellhead by AER Directive 036 Appendix 5 for workover wells with SIWHP above 10,000 kPa. The driller's panel and remote panels communicate with the closing unit through hydraulic pilot lines (direct hydraulic signal from panel pilot valve to closing unit manifold valve actuator) rather than electrical solenoid control, ensuring that a rig electrical failure does not disable control station functionality; some modern WCSB closing units supplement hydraulic pilot control with electro-hydraulic solenoids for integration with rig automation systems, provided the hydraulic pilot backup path remains functional.
• AER Directive 036 function test procedures and documentation for WCSB BOP closing units: AER Directive 036 specifies the BOP function test procedure that must be performed before spud of every WCSB well, after any BOP repair or component replacement, and at intervals not exceeding 7 days during drilling operations. The pre-spud function test sequence for the closing unit involves: confirming accumulator pre-charge by isolating the nitrogen side of each bottle and recording the pre-charge pressure (must be 6,900 kPa plus or minus 350 kPa); charging the system to 20,700 kPa with pumps running; isolating the pumps (turning off both electric and air pumps); closing all BOP components in sequence while monitoring accumulator pressure; and confirming that residual pressure after all closures is at least 1,380 kPa above pre-charge (minimum 8,280 kPa). Pressure and volume data from each function test must be recorded on an AER-approved BOP test report form and retained at the wellsite for AER field inspection; closing units that fail the accumulator volume test (residual pressure below 8,280 kPa after all closures) cannot resume drilling until the deficiency is corrected by adding accumulator bottles or repairing the hydraulic leak that reduced stored volume. The function test also documents closure time for each BOP component, confirming that all preventers close within 30 seconds of actuation as required by API 16D; slow closure (above 45 seconds) indicates hydraulic line restriction, manifold valve fouling, or accumulator undersizing that must be investigated.
• Koomey unit field terminology and subsea closing unit variants in global and WCSB offshore contexts: The term "Koomey unit" is widely used in WCSB land drilling as a generic field term for the closing unit, derived from Koomey Engineering Inc., the original manufacturer of the dominant hydraulic accumulator system design that became the industry standard in the 1950s; while Koomey Inc. is now part of National Oilwell Varco, the brand name persists as colloquial terminology on WCSB rigs operated by experienced drilling crews. The subsea equivalent of the closing unit in offshore drilling is the hydraulic power unit (HPU), which is mounted directly on the subsea BOP stack at the seafloor rather than at the rig floor, because running hydraulic control lines from a surface vessel to a BOP stack at 300 to 3,000 m water depth would create unacceptable response delays due to fluid compressibility and line length. Subsea HPUs on WCSB Grand Banks (Hibernia, Terra Nova, White Rose) and Arctic offshore installations store full BOP closing volume locally at the seafloor, receive electrical power and pilot signals from the surface through an umbilical, and have deadman activation systems that automatically close critical BOP functions if the umbilical is severed or if rig communication is lost for a pre-set time period (typically 20 to 60 seconds).

Closing Unit Failure Investigation on WCSB Foothills Horizontal Well

A WCSB Foothills operator experienced a closing unit accumulator pressure drop from 20,700 kPa to 14,500 kPa overnight during a connection on a 4,200 m Cretaceous horizontal well with MASP of 18,000 kPa. Investigation found that the hydraulic pilot line to the annular preventer manifold valve had developed a 2 mm hairline crack in a compression fitting, leaking hydraulic fluid at 0.8 L/min. The electric pump had been compensating by cycling every 8 minutes rather than the normal 45-minute cycle time, masking the leak from the driller. The compression fitting was replaced, system was recharged to 20,700 kPa, and the accumulator function test (pumps isolated, all closures) was repeated, confirming residual pressure of 9,400 kPa (above the 8,280 kPa minimum). The AER field inspector noted the incident and required a documented hydraulic leak inspection procedure to be added to the rig's daily morning tour sheet. Had the leak continued undetected for another 12-hour tour, the accumulator could have depleted below pre-charge, disabling BOP closure during the next connection.

Related Terms

Blowout preventer is the well control equipment the closing unit actuates; in WCSB Directive 036 programs, the BOP stack configuration (annular, pipe rams, blind-shear rams) determines the total closing volume used to size the accumulator bottle count. Well control procedures in WCSB drilling require the closing unit to be pre-function-tested and fully charged before any WCSB well is drilled; the closing unit is the final mechanical barrier between a wellbore kick and a surface blowout. Accumulator bottles store the pressurized hydraulic energy in the closing unit; Boyle's Law governs the usable volume calculation from nitrogen pre-charge pressure and system operating pressure. Annular preventer requires reduced hydraulic closing pressure (10,300-13,800 kPa) for stripping operations versus full 20,700 kPa for emergency closure; the closing unit pressure regulator provides this separately from ram BOP circuits. BOP test documentation under AER Directive 036 records the closing unit function test results before spud and at 7-day intervals; failure to maintain test documentation is a regulatory violation that can result in AER rig shutdown order.