When to Choose Blind Shear Rams for Your BOP

If you’re an oilfield operator, you need to choose the right blind shear ram BOP to keep everyone on the drilling site safe. That means you have to understand how this blowout preventer works and when exactly you should get a new blind shear ram. How does the blind shear ram BOP operate, and why do you need it in the oil field?

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How long do blind shear rams last on BOPs? Find out when they’re necessary here. Share on X

Fitted with hardened tool steel blades, blind shear rams can cut the drill pipe or tubing when the blowout preventer closes. It will fully close to isolate or seal off the wellbore. The blind shear ram serves as the last resort when other blowout preventers have failed. It helps to regain pressure control in an overflowing well.

Here are the circumstances under which you should choose new blind shear rams.

When They’re Past Expiration

Using outdated blowout preventers in the drilling sites poses significant risks to all your workers. If your blind shear rams are past the expiration date, you need to replace them with the latest and most efficient models. However, you need to ensure that the BOP standards match your needs and the general safety rules for drilling sites.

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When Another BOP Element is Changed

Making changes to a blowout preventer is a common practice in the oilfield. According to government regulations, BOP drawings should match the hardware to apply for drilling permits. That means you should choose the right blind shear rams for your blowout preventer system whenever you change any BOP elements.

Pro Tip: BOP changes can involve a vast range of subjects, including the materials, dimensions, surface finishes, and manufacturing methods. Design changes can result from material improvements and responses to service failures.

When Minor Issues Occur

Issues such as the use of outdated BOP elements can fail the BOP and SPM valves. Here are some of the other minor problems that can prompt you to get new blind shear rams for your BOP system.

• Broken internal flow control parts
• Contaminated hydraulic fluid
• Presence of excessive particulate matter
• Clip rings installed backward
• Incorrect OEM parts and incomplete rebuilds
• Hydraulic fluid incompatible with BOP materials

Choosing the Right Blind Shear Rams

Now that you know when and how to choose the right blind shear ram BOP, you can make informed decisions. Ensure that you select the latest shear rams for your BOP system to avoid inconveniences. It has to fulfill all your drilling needs.

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(1) Have at least five remote-controlled, hydraulically operated BOPs; You must have at least one annular BOP, two BOPs equipped with pipe rams, and two BOPs equipped with shear rams. For the dual ram requirement, you must comply with this requirement no later than April 29, . (i) Both BOPs equipped with pipe rams must be capable of closing and sealing on the tubular body of any drill pipe, workstring, and tubing under MASP, as defined for the operation, except tubing with exterior control lines and flat packs, a bottom hole assembly that includes heavy-weight pipe or collars, and bottom-hole tools. (ii) Both shear rams must be capable of shearing at any point along the tubular body of any drill pipe (excluding tool joints, bottom-hole tools, and bottom hole assemblies such as heavy-weight pipe or collars), workstring, tubing and associated exterior control lines, appropriate area for the liner or casing landing string, shear sub on subsea test tree, and any electric-, wire-, slick-line in the hole; under MASP. At least one shear ram must be capable of sealing the wellbore after shearing under MASP conditions as defined for the operation. Any non-sealing shear ram(s) must be installed below a sealing shear ram(s). (2) Have an operable redundant pod control system to ensure proper and independent operation of the BOP system; (3) Have the accumulator capacity, to provide fast closure of the BOP components and to operate all critical functions; The accumulator capacity must:
(i) Close each required shear ram, ram locks, one pipe ram, and disconnect the LMRP.
(ii) Have the capability to perform ROV functions within the required times outlined in API Standard 53 with ROV or flying leads.
(iii) Have bottles located subsea for the autoshear and deadman (which may be shared between those two systems) to secure the wellbore. These bottles may also be utilized to perform the secondary control system functions (e.g., ROV or acoustic functions).
(iv) Perform under MASP conditions as defined for the operation. (4) Have a subsea BOP stack equipped with remotely operated vehicle (ROV) intervention capability You must have the ROV intervention capability to open and close each shear ram, ram locks, one pipe ram, and disconnect the lower marine riser package (LMRP) under MASP conditions as defined for the operation. You must be capable of performing these functions in the response times outlined in API Standard 53 (as incorporated by reference in § 250.198). The ROV panels on the BOP and LMRP must be compliant with API RP 17H (as incorporated by reference in § 250.198). (5) Maintain an ROV and have a trained ROV crew on each rig unit on a continuous basis once BOP deployment has been initiated from the rig until recovered to the surface. The ROV crew must examine all ROV-related well-control equipment (both surface and subsea) to ensure that it is properly maintained and capable of carrying out appropriate tasks during emergency operations; The crew must be trained in the operation of the ROV. The training must include simulator training on stabbing into an ROV intervention panel on a subsea BOP stack. The ROV crew must be in communication with designated rig personnel who are knowledgeable about the BOP's capabilities. (6) Provide autoshear, deadman, and EDS systems for dynamically positioned rigs; provide autoshear and deadman systems for moored rigs; (i) Autoshear system means a safety system that is designed to automatically shut-in the wellbore in the event of a disconnect of the LMRP. This is considered a rapid discharge system. (ii) Deadman system means a safety system that is designed to automatically shut-in the wellbore in the event of a simultaneous absence of hydraulic supply and signal transmission capacity in both subsea control pods. This is considered a rapid discharge system. (iii) Emergency Disconnect Sequence (EDS) system means a safety system that is designed to be manually activated to shut-in the wellbore and disconnect the LMRP in the event of an emergency situation. This is considered a rapid discharge system. (iv) Autoshear/deadman functions and an EDS mode must close, at a minimum, two shear rams in sequence and be capable of performing their expected shearing and sealing action under MASP conditions as defined for the operation. (v) Your sequencing must allow a sufficient delay when closing your two shear rams in order to provide maximum sealing efficiency. (7) Demonstrate that any acoustic control system will function in the proposed environment and conditions; If you choose to use an acoustic control system in addition to the autoshear, deadman, and EDS requirements, you must demonstrate to the District Manager, as part of the information submitted under § 250.731, that the acoustic control system will function in the proposed environment and conditions. The District Manager may require additional information as appropriate to clarify or evaluate the acoustic control system information provided in your demonstration. (8) Have operational or physical barrier(s) on BOP control panels to prevent accidental disconnect functions; You must incorporate enable buttons, or a similar feature, on control panels to ensure two-handed operation for all critical functions. (9) Clearly label all control panels for the subsea BOP system; Label other BOP control panels, such as hydraulic control panel. (10) Develop and use a management system for operating the BOP system, including the prevention of accidental or unplanned disconnects of the system; The management system must include written procedures for operating the BOP stack and LMRP (including proper techniques to prevent accidental disconnection of these components) and minimum knowledge requirements for personnel authorized to operate and maintain BOP components. (11) Establish minimum requirements for personnel authorized to operate critical BOP equipment; Personnel must have:
(i) Training in deepwater well-control theory and practice according to the requirements of Subparts O and S; and
(ii) A comprehensive knowledge of BOP hardware and control systems. (12) Before removing the marine riser, displace the fluid in the riser with seawater; You must maintain sufficient hydrostatic pressure or take other suitable precautions to compensate for the reduction in pressure and to maintain a safe and controlled well condition. You must follow the requirements of § 250.720(b). (13) Install the BOP stack in a well cellar when in an ice-scour area; Your well cellar must be deep enough to ensure that the top of the stack is below the deepest probable ice-scour depth. (14) Install at least two side outlets for a choke line and two side outlets for a kill line; (i) If your stack does not have side outlets, you must install a drilling spool with side outlets.
(ii) Each side outlet must have two full-bore, full-opening valves.
(iii) The valves must hold pressure from both directions and must be remote-controlled.
iv) You must install a side outlet below the lowest sealing shear ram. You may have a pipe ram or rams between the shearing ram and side outlet. (15) Install a gas bleed line with two valves for the annular preventer no later than April 30, ; (i) The valves must hold pressure from both directions;
(ii) If you have dual annulars, you must install the gas bleed line below the upper annular. (16) Use a BOP system that has the following mechanisms and capabilities; (i) No later than May 1, , you must have the capability to position the entire pipe completely within the area of the shearing blade. This capability cannot be a separate ram BOP or annular preventer, but you may use those during a planned shear.
(ii) If your control pods contain a subsea electronic module with batteries, a mechanism for personnel on the rig to monitor the state of charge of the subsea electronic module batteries in the BOP control pods. (1) Follow the testing requirements of API Standard 53 (as incorporated in § 250.198) If there is a conflict between API Standard 53, testing requirements and this section, you must follow the requirements of this section. (2) Use water to test a surface BOP system on the initial test. You may use drilling/completion/workover fluids to conduct subsequent tests of a surface BOP system (i) You must submit test procedures with your APD or APM for District Manager approval. (ii) Contact the District Manager at least 72 hours prior to beginning the initial test to allow BSEE representative(s) to witness the testing. If BSEE representative(s) are unable to witness the testing, you must provide the initial test results to the appropriate District Manager within 72 hours after completion of the tests. (3) Stump test a subsea BOP system before installation (i) You must use water to conduct this test. You may use drilling/completion/workover fluids to conduct subsequent tests of a subsea BOP system. (ii) You must submit test procedures with your APD or APM for District Manager approval (iii) Contact the District Manager at least 72 hours prior to beginning the stump test to allow BSEE representative(s) to witness the testing. If BSEE representative(s) are unable to witness the testing, you must provide the test results to the appropriate District Manager within 72 hours after completion of the tests. (iv) You must verify closure of all ROV intervention functions on your subsea BOP stack during the stump test. (v) You must follow paragraphs (b) and (c) of this section. Pressure testing of each ram and annular component is only required once. (4) Perform an initial subsea BOP test (i) You must begin the initial subsea BOP test on the seafloor within 30 days of the stump test. (ii) You must submit test procedures with your APD or APM for District Manager approval. (iii) You must pressure test well-control rams and annulars according to paragraphs (b) and (c) of this section. (iv) You must notify the District Manager at least 72 hours prior to beginning the initial subsea test for the BOP system to allow BSEE representative(s) to witness testing. (v) You must test and verify closure of at least one set of rams during the initial subsea test through a ROV hot stab. You must confirm closure of the selected ram through the ROV hot stab with a 1,000 psi pressure test for 5 minutes. (5) Alternate tests between control stations (i) For two complete BOP control stations you must:
(A) Designate a primary and secondary station;
(B) Alternate testing between the primary and secondary control stations on a weekly basis; and
(C) For a subsea BOP, develop an alternating testing schedule to ensure the primary and secondary control stations will function each pod. (ii) Remote panels where all BOP functions are not included (e.g., life boat panels) must be function-tested upon the initial BOP tests. (6) Pressure test variable bore-pipe ram BOPs against pipe sizes according to API Standard 53, excluding the bottom hole assembly that includes heavy-weight pipe or collars and bottom-hole tools (7) Pressure test annular type BOPs against pipe sizes according to API Standard 53 (8) Pressure test affected BOP components following the disconnection or repair of any well-pressure containment seal in the wellhead or BOP stack assembly (9) Function test annular and pipe/variable bore ram BOPs every 7 days between pressure tests (10) Function test shear ram(s) BOPs every 14 days If BSEE approves your request to utilize a 21-day BOP test frequency pursuant to § 250.737(a)(4), you may function test shear ram(s) BOPs every 21 days in accordance with the terms of that approval. (11) Actuate safety valves assembled with proper casing connections before running casing (12) Function test autoshear/deadman, and EDS systems separately on your subsea BOP stack during the stump test. The District Manager may require additional testing of the emergency systems. You must also test the deadman system and verify closure of the shearing rams during the initial test on the seafloor (i) You must submit test procedures with your APD or APM for District Manager approval. The procedures for these function tests must include the schematics of the actual controls and circuitry of the system that will be used during an actual autoshear or deadman event.
(ii) The procedures must also include the actions and sequence of events that take place on the approved schematics of the BOP control system and describe specifically how the ROV will be utilized during this operation.
(iii) When you conduct the initial deadman system test on the seafloor, you must ensure the well is secure and, if hydrocarbons have been present, appropriate barriers are in place to isolate hydrocarbons from the wellhead. You must also have an ROV on bottom during the test.
(iv) Following the deadman system test on the seafloor you must document the final remaining pressure of the subsea accumulator system.
(v) For the function test of the deadman system during the initial test on the seafloor, you must have the ability to quickly disconnect the LMRP should the rig experience a loss of station-keeping event. You must include your quick-disconnect procedures with your deadman test procedures.
(vi) You must confirm closure of the BSR(s) with a 1,000 psi pressure test for 5 minutes.
(vii) If a casing shear ram is installed, you must describe how you will verify closure of the ram.
(viii) You must document all your test results and make them available to BSEE upon request. (13) Pressure test the choke and kill side outlet valves According to paragraph (b) of this section, except as follows:
(i) Test the wellbore side of the choke and kill side outlet valves above the uppermost pipe ram to the approved annular test pressure. Choke and kill side outlet valves below the uppermost pipe ram must be tested to MASP plus 500 psi for the applicable hole section.
(ii) For the 30 day BSR testing, test the wellbore side of the choke and kill side outlet valves between the upper most pipe ram and the upper most ram, to the casing/liner test pressure or annular test pressure, whichever is greater.
(iii) For BOPs with only one choke and kill side outlet valve, you are only required to pressure test the choke and kill side outlet valves from the wellbore side.