back-pressure valve

A back-pressure valve (BPV) in the context of tubing running operations and well workover programs serves as the critical well control barrier that allows the workover crew to run, retrieve, and service the production tubing string in a live well without killing the well with kill fluid, preserving reservoir energy that would otherwise be consumed by the weight of a kill fluid column and avoiding the formation damage associated with overbalanced fluid invasion into the producing zone during conventional kill-and-workover operations, making the BPV-equipped tubing running system the standard approach for WCSB Montney and Duvernay horizontal well workovers where well kill fluid costs and re-stimulation costs after kill-fluid damage can each exceed $100,000 per workover event. The BPV used in tubing running operations is mechanically distinct from the production BPV installed permanently in the tubing hanger for static isolation: the tubing running BPV is a retrievable tool that is set in the tubing string during running-in or pulling operations and removed once the tubing is landed and the wellhead is connected, rather than being permanently installed; it provides the lower pressure barrier below the pipe rams of the blowout preventer stack while the tubing is being run through the wellhead, replacing the static barrier function that the kill fluid column would provide in a conventional workover operation. In WCSB live well tubing operations, the BPV is typically set inside the tubing string at a depth of 100 to 300 m below the wellhead before the tubing is nippled up into the wellhead, using one of three setting methods that differ in equipment requirement and depth capability: wireline-set BPVs are run inside the tubing string on a slickline unit and anchored to a polished bore receptacle (PBR) or nipple profile machined into the tubing at the design setting depth, allowing retrieval by the same wireline unit after the wellhead is secured; pump-down BPVs are pumped into position through the tubing string on a seat and can be set without wireline equipment at reduced cost, but require the tubing to be filled with fluid to provide the hydraulic driving force, limiting their use to wells where partial kill fluid is acceptable; and integral tubing string BPVs are installed as a nipple-and-valve assembly incorporated into the tubing string at a predetermined joint position during surface make-up, eliminating the setting step but requiring the tubing design to accommodate the BPV joint location before running. Understanding BPV setting method selection for WCSB workover programs (wireline for maximum control, pump-down for cost efficiency, integral for planned tubing designs), the pressure rating and temperature requirements for the BPV in WCSB high-pressure Montney wells (BPV differential pressure ratings of 70 to 105 MPa for Montney tubing operations at 28 to 45 MPa shut-in tubing pressures), the BOP configuration required below the BPV while running tubing in a live well, and the AER Directive 036 well control requirements for live tubing operations gives WCSB drilling and completions engineers, workover supervisors, and well service crews the equipment and procedural knowledge to execute live tubing operations safely without the cost and formation damage penalties of conventional kill-and-workover programs.

• Wireline-set BPV for WCSB live tubing operations on high-pressure Montney wells: The wireline-set BPV for WCSB Montney live tubing operations is run on slickline after the tubing string has been made up on surface and the lowermost tubing joints are stabbed through the wellhead; the BPV is pumped or lowered to the PBR nipple profile at the design setting depth (typically 200 to 400 m below the wellhead for Montney wells with 28 to 38 MPa shut-in tubing pressure) and set by applied weight or jarring to engage the lock mandrel in the nipple profile. Once the BPV is set and tested to full shut-in tubing pressure, the tubing running operation can proceed with the BPV providing the lower well control barrier while the pipe rams of the BOP serve as the upper barrier; on every connection during tubing running, the pipe rams are closed, the BOP space between the rams and the BPV is bled to zero pressure, the connection is made, and the pipe rams are reopened. This double-barrier procedure meets AER Directive 036 requirements for two independent well control barriers during tubing running in wells with shut-in tubing pressure above 10 MPa.
• Pump-down BPV setting for WCSB lower-pressure workover programs: Pump-down BPVs are used in WCSB Cardium and Viking oil well workover programs where shut-in tubing pressure is 3 to 10 MPa and the cost of a slickline unit (approximately $3,000 to $5,000 per day) represents a significant fraction of the total workover cost. The pump-down BPV is a self-orienting valve body that is dropped into the tubing string at surface and pumped down by light kill fluid to a seating nipple or restriction at the design depth; once seated, the BPV is pressure-tested from above (using the fill-up line) to confirm it is holding the shut-in wellbore pressure from below. The partial kill fluid required to pump the BPV (typically 2 to 5 m3 to reach the seating nipple) contacts only the upper portion of the completion above the seating depth and causes minimal formation damage compared to a full wellbore kill; after the workover is complete and the new tubing is landed, the BPV is retrieved by a fishing neck on the top of the valve body using a slickline or tubing-conveyed overshot.
• BPV pressure and temperature ratings for WCSB deep high-pressure service: BPVs for WCSB Montney horizontal well tubing operations must be rated for the maximum anticipated differential pressure (MAADP) equal to the maximum shut-in tubing pressure (SITP) from below plus a safety factor; for WCSB Montney wells with SITP of 28 to 40 MPa, BPVs rated at 70 MPa (10,000 psi) to 105 MPa (15,000 psi) differential are specified. Temperature rating for WCSB Montney programs is typically 150 degrees C (300 degrees F) working temperature at the BPV setting depth, met by standard elastomeric seal materials (Viton, HNBR); for WCSB geothermal or deep Devonian workover programs above 150 degrees C, metal-to-metal seat BPVs without elastomeric seals are specified. The BPV is pressure-tested to 1.25 times the MAADP after setting and before the pipe rams are opened for tubing running to commence; failure of the pressure test requires retrieving and replacing the BPV before continuing.
• BOP configuration and crew procedures during WCSB live tubing running with BPV: AER Directive 036 requires that live tubing running operations in WCSB wells with shut-in tubing pressure above 10 MPa be conducted with a BOP stack configured with pipe rams sized for the tubing OD, blind rams or shear-blind rams, and annular preventer; the BPV provides the lower barrier and the closed pipe rams provide the upper barrier during each connection. The WCSB workover crew procedure requires: (1) close pipe rams before breaking the previous connection; (2) bleed pressure from the BOP space between pipe rams and the top of the BPV through a bleed valve to confirm zero differential pressure before breaking the connection; (3) make the new connection and function-test the new joint stab before opening the pipe rams. Any failure to confirm zero pressure in the BOP space before breaking a connection risks exposing the crew to wellbore pressure if the BPV has leaked; WCSB operators require a signed step-by-step BOP procedure checklist for every live tubing running job exceeding 10 MPa SITP.
• BPV retrieval and well control after tubing is landed in WCSB live well workover: After the tubing is fully landed in the wellhead and the tubing hanger is set, the production BPV (permanent, installed in the tubing hanger) takes over as the lower well control barrier; the temporary tubing running BPV is then retrieved by wireline while the production BPV and the wellhead gate valve provide the two required independent barriers. For WCSB wells where the production BPV is a pump-down type installed in the tubing hanger during the workover, the temporary BPV is retrieved first, the tubing hanger production BPV is then installed through the wellhead while the gate valve provides the barrier, and finally the Christmas tree is nippled up and function-tested before the well is returned to production. Failure to properly sequence the BPV retrieval and production valve installation can leave the well with only one barrier (the wellhead gate valve) during the transition, which is a regulatory violation under AER Directive 036 and requires the crew to stop work until the second barrier is restored.

Wireline BPV Enabling Live Tubing Replacement on a WCSB Montney Well

A northeast British Columbia Montney horizontal well required replacement of its production tubing string after a corrosion failure was identified at 1,240 m depth by tubing inspection logging. The well had a shut-in tubing pressure of 32 MPa, making a conventional kill operation impractical without a $145,000 kill fluid program and estimated $220,000 in re-stimulation costs to remove kill fluid damage from the hydraulically fractured Montney pay. The operator elected to conduct a live tubing workover using a wireline-set BPV rated at 70 MPa differential. The BPV was set on slickline in a polished bore receptacle at 310 m depth, pressure-tested to 40 MPa (1.25 times the 32 MPa SITP), and confirmed seating on the first attempt. The tubing was pulled and new tubing run with full BOP double-barrier procedure over 3.5 days; the wireline BPV was retrieved after the tubing hanger was set and the production tree nippled up. Total workover cost was $385,000 versus an estimated $750,000 for kill-and-workover including re-stimulation, and the well returned to pre-workover production rate within 2 days of completion.

Related Terms

Back-pressure valve is the primary entry covering the BPV's function as a one-way check valve in the production tubing hanger for static well isolation during normal operations; this companion entry covers the tubing running BPV, a retrievable tool providing the lower well control barrier during live tubing running and workover operations in WCSB wells where kill fluid operations are impractical or prohibitively costly. Blowout preventer (BOP) provides the upper well control barrier during live tubing running when the BPV provides the lower barrier; the WCSB Directive 036 two-barrier requirement is satisfied by the combination of closed pipe rams (BOP upper barrier) and the set BPV (lower barrier) at every connection during tubing running in wells above 10 MPa shut-in tubing pressure. Live well workover is the WCSB operational category that BPV-equipped tubing running enables, avoiding the cost of kill fluid (typically $50,000 to $200,000 per event for Montney wells) and the formation damage from overbalanced fluid invasion that reduces post-workover production rates and requires re-stimulation. Polished bore receptacle (PBR) is the tubing nipple profile that the wireline-set BPV locks into during WCSB live tubing operations; the PBR must be incorporated into the tubing string design before running so that it is located at the correct depth (100 to 400 m below the wellhead) to position the BPV within the BOP stack reach during connection-making. Well control is the engineering discipline governing BPV selection, pressure rating, setting procedure, and BOP configuration for WCSB live tubing workover operations; AER Directive 036 well control requirements for live tubing operations above 10 MPa specify the two-barrier standard, BOP test frequency, and crew competency requirements that WCSB workover supervisors must meet before beginning any live tubing running program.