Mr. Erik Milito - The House Committee on Natural Resources ...

ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 65
typically removed to install wellhead components. At these times, the barriers in the well have changed from fluids
and the BOP stack to fluids and cement. <strong>The</strong> plan should address when the cement properties are adequate to make
that change.
Plans for testing of barrier elements should be part of each well design. Barrier plans should address pressure
integrity through pressure testing, but may also require negative testing of a liner top prior to changing out the
wellbore fluid. If drilling is planned for an extended period of time (> 30 days), potential casing wear issues should be
reviewed, and casing size/tool joint facing material should be selected such that wear will not impair the casing’s
ability to withstand all potential loads.
B.2.8 Deepwater Barrier Planning
<strong>The</strong> column of fluid in the riser does not act as a barrier element when the marine riser has been disconnected.
Planned or accidental disconnect of the marine riser should be addressed in the well plan. Operators may be able to
maintain a drilling fluid density that will provide an overbalance condition with the marine riser disconnected. If this is
not possible, a weighted fluid may be displaced into a portion of the wellbore, so that zones with flow potential remain
under control in the absence of the hydrostatic pressure from fluid in the marine riser.
Deepwater operating plans should also address the following issues:
— detailed riser analysis should be performed to verify that the riser can withstand all anticipated environmental
(weather, current, and sea state) and operating loads;
— the riser disconnect system should be analyzed to verify the ability to safely disconnect under all anticipated
loads;
— riser stress should be measured or calculated to determine an optimum rig position to minimize the effects of
static and dynamic loads.
B.2.9 Contingency Planning
B.2.9.1 General
<strong>The</strong> potential for instability caused by unintended transfers of fluids or solids between the wellbore and the formation
should be identified in pre-drill analyses. Contingency plans should be developed to specify the procedures,
equipment, and personnel needed to avoid adverse situations or to suppress incipient dangers before they become
unmanageable. Contingency plans should consider events that fall into three categories: fluid influxes, lost circulation,
and formation failures such as breakouts and packoffs.
B.2.9.2 Well Control Planning for Fluid Influxes
Kicks—<strong>The</strong> following equipment and supplies for contending with kicks should be available at the rig site:
— adequate supplies of heavy drilling fluid—these should be kept ready for mixing in the reserve pit;
— a diverter when shallow formation flow hazards exist such as high pressure shallow gas or water zones; or
— properly selected and well-maintained well control equipment such as blowout preventers (BOPs), chokes, and
degassers.
Well control procedures vary depending upon whether surface or subsea BOPs are employed and whether a kick
occurs while tripping, drilling, or the bit is out of the hole; however, in general, such procedures include:
— the use of kill drilling fluid and circulating out the kick,