API RP 2RD PDF

You must also install flow couplings above and below the subsurface safety devices. For instances where the well at issue is incapable of natural flow, you may seek District Manager approval for using alternative procedures or equipment, if you propose to use a subsea safety system that is not capable of shutting off the flow from the well in the event of an emergency. The surface controls must be located on the host facility. You must design, install, and operate including repair, maintain, and test an SSSV to ensure its reliable operation. When warranted by conditions, such as unstable bottom conditions, permafrost, hydrate formation, or paraffin problems, the District Manager may approve an alternate setting depth on a case-by-case basis.

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You must also install flow couplings above and below the subsurface safety devices. For instances where the well at issue is incapable of natural flow, you may seek District Manager approval for using alternative procedures or equipment, if you propose to use a subsea safety system that is not capable of shutting off the flow from the well in the event of an emergency.

The surface controls must be located on the host facility. You must design, install, and operate including repair, maintain, and test an SSSV to ensure its reliable operation. When warranted by conditions, such as unstable bottom conditions, permafrost, hydrate formation, or paraffin problems, the District Manager may approve an alternate setting depth on a case-by-case basis.

For purposes of this section, a surface-controlled SSSV is considered inoperative if, for a direct hydraulic control system, you have bled the hydraulics from the control line and have isolated it from the hydraulic control pressure. If your controls employ an electro-hydraulic control umbilical and the hydraulic control pressure to the individual well cannot be isolated, a surface-controlled SSSV is considered inoperative if you perform the following: i Disable the control function of the surface-controlled SSSV within the logic of the programmable logic controller which controls the subsea well; ii Place a pressure alarm high on the control line to the surface-controlled SSSV of the subsea well; and iii Close the USV and at least one other tree valve on the subsea well.

You must install a surface-controlled SSSV or an injection valve capable of preventing backflow in all injection wells. This requirement is not applicable if the District Manager determines that the well is incapable of natural flow. You must verify the no-flow condition of the well annually. If a necessary alteration or disconnection of the pipeline or umbilical of any subsea well would affect your ability to monitor casing pressure or to test any subsea valves or equipment, you must contact the appropriate District Office at least 48 hours in advance and submit a repair or replacement plan to conduct the required monitoring and testing.

You must not alter or disconnect until the repair or replacement plan is approved. The USV1 must be located upstream of the choke valve.

You may equip your tree with two or more valves qualified to be designated as a USV, one of which may be designated as the USV2. The USV2 must be located upstream of the choke. You must install a BSDV on the pipeline boarding riser. In addition, you must: a Ensure that the internal design pressure s of the pipeline s , riser s , and BSDV s is fully rated for the maximum pressure of any input source and complies with the design requirements set forth in subpart J, unless BSEE approves an alternate design.

If an object is dropped, you must immediately secure the well directly under the MODU or other type of workover or intervention vessel while simultaneously communicating with the platform to shut-in all affected wells.

You must also maintain without disruption, and continuously verify, communication between the production facility and the MODU or other type of workover or intervention vessel. If communication is lost between the MODU or other type of workover or intervention vessel and the platform for 20 or more minutes, you must shut-in all wells that could be affected by a dropped object.

You may reopen the BSDV to blow down the pipeline to prevent hydrates, provided you have secured the well s and ensured adequate protection.

You must obtain approval from the appropriate District Manager to resume production in the unaffected pipeline s of a dual or multi pipeline system. If the PSHL sensor activation was a false alarm, you may return the wells to production without contacting the appropriate District Manager. You must notify the appropriate District Manager before resuming production. Your pipeline BSDV must.

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API RP 2RD (R2006)

The intent of this article is not to speculate why the latest version has not been universally adopted, but rather give an overview of the changes that will impact riser designs once it has been. The key differences are as follows: The design approach has changed from an allowable stress criteria to a load and resistance factor method. Exceedance of yield is allowed when stress is primary as opposed to displacement controlled secondary stress. For combined load, the Von Mises stress approach is replaced with a limit load approach. Explicit burst and collapse checks are required.

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