BAKER HUGHES - Drilling Fluids Reference Manual

TABLE OF CONTENTS
The DKD process blends specially formulated 16.0 ppg drilling fluid with seawater or calcium
chloride, or both components, to generate a fluid with a predetermined density and rheological
properties. This procedure is executed using specialized proprietary equipment and techniques.
Extensive pre-planning is required in order to determine the mud weight that will be used and the
volume of fluid that is required. A rig survey is carried out to ensure that all the necessary
components for a successful DKD process are present or identified for modification. Prior to
execution of the job, the DKD unit, which consists of a shearing device and flow control equipment,
is set up on-site. Once on the job, the unit has to be rigged up, and a diverse group of logistic issues
must be immediately addressed in order for the procedure to be effective.
A detailed description of the entire DKD Process can be found in the DKD Best Practices Manual.
SELECTING DRILLING FLUIDS FOR DEEPWATER
Drilling fluid selection for deepwater drilling operations can be an extremely complex matter due to
the many different considerations, including fluid compressibility/expansion as a function of wellbore
temperatures, hydrate suppression, possible evaporate sequences, well path, environmental
restrictions and perhaps most importantly, well costs. Deepwater technical challenges also include
shale reactivity, formation damage and drilling and completing in unconsolidated sands.
Environmental and safety issues are, as always, of paramount importance. Often, the most practical
result of the fluid selection process is compromise.
In deepwater drilling, the use of a fluid that delivers all the well-specific performance issues is
essential. Inhibitive fluids with low dilution and consumption rates are of considerable benefit in
minimizing rig logistics, cost and maximizing fluid performance. Typical riser volumes may range
from 1,000 to 3,000 bbl (160 to 500m 3 ) and circulating volumes from 2,500 to 5,000 bbl (400 to 800
m 3 ), depending on water depth, hole size and total depth of the well. As demonstrated by this
example, large fluid volumes are normally associated with deepwater wells. This is the result of
multiple casing string requirements and/or production requirements. Fluid volume needed to fill the
riser and pits should not be confused with dilution volume. Fluid dilution requirements are the direct
result of hole size (cuttings generated), Solids Removal Efficiency (SRE - cuttings removed) and the
desired drilled solids content of the fluid. The fluid type can enhance SRE and certain fluid types can
incorporate higher solids content without significantly degrading the fluid’s performance.
Nevertheless solids removal equipment deserves a great deal of focus in the planning and execution
of deepwater projects.
Solids removal efficiency is the vital factor in the control of low gravity solids (LGS) and minimizing
dilution volume and associated costs. Optimum solids control equipment would include four linear
motion shale shakers, ideally preceded by four scalping shakers. The deployment and use of
centrifuges should be considered in association with the mud weight, type of fluid system and
discharge requirements. A water base system may require one or more barite recovery centrifuges. A
synthetic invert emulsion may have an external phase that has more economical value than other fluid
components and therefore be most important to recover. Discharge of cuttings may require a host of
equipment, including a dryer and centrifuge for LGS and oil separation. Each project should be
evaluated on its economic merits. Whenever possible it is desirable to utilize a drilling fluid which is
environmentally acceptable for cuttings discharge and exhibits the required fluid characteristics.
BAKER HUGHES DRILLING FLUIDS
REFERENCE MANUAL
REVISION 2006 13-3