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

64 API STANDARD 65-2
these problems. ECD increase in high-angle and horizontal wellbore sections should be addressed in the plan, as the
formation fracture gradient will remain constant in the horizontal section of the well while fluid friction pressure will
increase.
Numerous well design parameters can impact ECD including the use of casing strings with increased annular
clearances, use of liners rather than full casing strings, selecting fluids that reduce frictional losses, expandable
tubulars to preserve hole size, and controlling ROP to avoid overloading the annulus with cuttings. Critical circulating
and swab pressures should be documented in the plan. A wellbore hydraulics simulator should be used on each well.
B.2.6.2 Wellbore Cleaning
Cuttings transport to the surface is primarily controlled by annular velocity and fluid rheology, so care should be taken
when selecting components that impact these parameters. Surface drilling equipment (drilling fluid pumps, flow lines,
and shakers) should be sized to accommodate the maximum rate of cuttings generated. Hole deviation should be
considered when designing higher annular velocities for proper hole cleaning. Ensure chemical compatibility of the
formation and the drilling fluid system to avoid swelling problems. <strong>The</strong> bit nozzle selection should be based on
optimizing ROP, bit cleaning, and annular velocity for transport of solids to the surface. It is recommended that a
wellbore hydraulics/hole cleaning simulation model be run on each well to determine minimum and maximum flow
rates. Maximum pipe-tripping speed should be controlled to avoid creation of excess swab/surge pressure during
hole cleaning operations. Wells drilled from floating vessels should consider the use of a booster line when high solids
loading is expected in the riser.
Conventional hole cleaning tactics may have to be supplemented with hole cleaning pills under certain conditions.
Viscous pills and high weight pills can be effective at removing cuttings. However, the use of some pills can
contaminate the drilling fluid system.
B.2.7 Barrier Design
<strong>The</strong> operational goal of any well design is to provide sufficient barriers between formations and between those
formations and the surface. A well’s barrier plan should include maintaining well control via hydrostatic pressure from
fluids, selection and use of well control equipment, and the placement of cement or other mechanical barriers in the
well. <strong>The</strong> well design (i.e. wellhead, BOP equipment, riser, etc.) should consider including a minimum of two barriers
available during any operation to prevent uncontrolled flow from the well to the environment. If an operation is
performed with fewer than two physical barriers in place, then operational barriers become critical. See industry well
design documents for more information. <strong>The</strong> barrier design should consider incorporating the following elements:
— ability to withstand the maximum anticipated wellbore pressure,
— ability to be tested for function or leaks,
— failure of a single barrier will not result in uncontrolled flow from the well,
— the operating environment is within the design specifications of the barrier element.
In addition, at least one of the barriers should have the capability to do the following.
— Shear any device that passes through the barrier and seal the wellbore after shearing. If this is not possible, an
alternative pressure control plan should be considered.
— Seal the wellbore with any size device penetrating the barrier element. If this is not possible, an alternative
pressure control plan should be considered.
Evaluation of the viability of each barrier should be considered in the planning process. Plans should address well
control issues each time a barrier is removed or replaced. For example, after a cement job, the BOP system is