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API RP 53 Document Information:
Title
Blowout Prevention Equipment Systems for Drilling Wells
American Petroleum Institute
Publication Date:
Mar 1, 1997
Scope:
PURPOSE
The purpose of these recommended practices is to provide information
that can serve as a guide for
installation and testing of blowout prevention equipment systems on
land and marine drilling rigs
(barge, platform, bottom-supported, and floating). Blowout prevention
equipment systems are
composed of all systems required to operate the blowout preventers
(BOPs) under varying rig and
well conditions. These systems are: blowout preventers (BOPs), choke
and kill lines, choke
manifold, hydraulic control system, marine riser, and auxiliary
equipment. The primary functions of
these systems are to confine well fluids to the wellbore, provide
means to add fluid to the
wellbore, and allow controlled volumes to be withdrawn from the
wellbore. In addition, diverter
systems are addressed in this Recommended Practice, though their
primary purpose is to safely
divert flow rather than to confine fluids to the wellbore. Refer to
API Recommended Practice 64 for
additional information on diverter systems. Marine risers are not
dealt with in detail in this
document. Refer to API Recommended Practice 16Q for additional
information on marine drilling
risers.
WELL CONTROL
Procedures and techniques for well control are not included in this
publication since they are
beyond the scope of equipment systems contained herein (refer to API
Recommended Practice 59).
BOP INSTALLATIONS
In some instances, this publication contains a section pertaining to
surface BOP installations
followed by a section on subsea BOP installations. A delineation was
made between surface and
subsea equipment installations so these recommended practices would
also have utility in floating
drilling operations. Statements concerning surface equipment
installations also generally apply to
subsea equipment installations.
EQUIPMENT ARRANGEMENTS
Recommended equipment arrangements, as set forth in this publication,
are adequate to meet
specified well conditions. It is recognized that other arrangements
may be equally effective and
can be used in meeting well requirements and promoting safety and
efficiency.
LOW TEMPERATURE OPERATIONS
Although operations are being conducted in areas of extremely low
temperatures, a section
specifically applicable to this service was not included since current
practice generally results
in protecting existing BOP equipment from this environment.
IN-THE-FIELD CONTROL SYSTEM ACCUMULATOR CAPACITY
It is important to distinguish between the standards for in-the-field
control system accumulator
capacity established here in Recommended Practice 53 and the design
standards established in API
Specification 16D.
API Specification 16D provides sizing guidelines for designers and
manufacturers of control
systems. In the factory, it is not possible to exactly simulate the
volumetric demands of the
control system piping, hoses, fittings, valves, BOPs, etc. On the rig,
efficiency losses in the
operation of fluid functions result from causes such as friction, hose
expansion, control valve
interflow as well as heat energy losses. Therefore, the establishment
by the manufacturer of the
design accumulator capacity provides a safety factor. This safety
factor is a margin of additional
fluid capacity which is not actually intended to be usable to operate
well control functions on the
rig.
For this reason, the control system design accumulator capacity
formulas established in
Specification 16D are different from the demonstrable capacity
guidelines provided here in
Recommended Practice 53.
The original control system manufacturer shall be consulted in the
event that the field
calculations or field testing should indicate insufficient capacity or
in the event that the
volumetric requirements of equipment being controlled are changed,
such as by the modification or
changeout of the BOP stack.
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