Page 127 - Shale Shakers Drilling Fluid Systems

110 SHALE SHAKERS AND DRILLING FLUID SYSTEMS

to be reduced to a 6% volume target concentra- many drilled solids are stored in the well-bore and
tion, they must be blended into 2400 bbl (-£j|) of do not reach the surface in the order in which they
slurry. To create the 2400 bbl of slurry, 2256 bbl are drilled. Frequently, in long stretches of open
of clean drilling fluid must be added to the 146 bbl hole, as many drilled solids enter the drilling fluid
of solids [146 bbl/2256 + 146 bbl)] = 6% volume. from the sides of the wellbore as are generated by
Not only would the cost of the clean drilling fluid a drill bit.
be prohibitive, but most drilling rigs do not have One proposed relationship shows that the maxi-
the necessary surface volume to build 2256 bbl of mum flow rate that can be handled by a shaker
clean drilling fluid for every 1,000 feet of hole (Q), is inversely proportional to the product of the
drilled. (See Chapter 8 for a more complete dis- plastic viscosity (PV), mud weight (MW), and pro-
cussion of dilution calculations.) portional to the screen conductance (K). This re-
As demonstrated, it is important to remove as lationship answers the question: If a linear motion
many drilled solids as possible with the shale shale shaker is handling 1250 gpm of a 10.3 ppg
shaker. Shakers are an important component of drilling fluid, with a PV of 10 cp on a 120-square
this process but they are only one portion of a MG mesh screen, what flow rate could be handled
complete drilled solids removal system. Careful at- on a 200-square MG mesh screen if the mud weight
tention to details is the key to developing the most is increased to 14.0 ppg and the PV becomes 26 cp?
efficient drilled solids removal operation. Complete
processing will decrease the cost of accumulating
excess drilling fluid, thereby contributing to the
ultimate goal of reducing the costs associated with
oil well drilling (Chapter 8).

Specific Factors

Specific factors that should be considered when The problem with this equation is that it fails
designing the shale shaker system include: flow rate, to account for other rheological variables. For ex-
fluid type, rig space, configuration/power, available ample, if the gel strength of the 10.3 ppg drilling
elevation, and discharge dryness (restrictions). fluid significantly increased, the shaker could no
Most programs extrapolate laboratory-generated longer handle the fluid. To further demonstrate,
performance curves to predict field performance. take a shaker that handles 750 gpm of an 11.0 ppg
Unfortunately, laboratory-manufactured drilling drilling fluid with a certain plastic viscosity (PV).
fluid does not duplicate properties of drilling fluid If the yield point is significantly increased, or ad-
that has been used in a well. High shear rates ditives such as PHPA or a high concentration of
through drill bit nozzles at elevated temperatures starch are added to this fluid, the shaker capacity
produce colloidal-size particles that are not dupli- might be only 350 gpm. In both these cases, the
cated in surface-processed drilling fluid. PV would change very little but there would be
a significant effect on the screening capability.
Flow rate. The flow rate that a particular shaker/ Therefore, the above equation should only be used
screen combination can handle greatly depends on to predict the flow rate if no other properties in
the flow properties of the drilling fluid. The lower the drilling fluid change other than the mud weight
the values of plastic viscosity, yield point, gel and plastic viscosity. The equation should be used
strength, and mud weight, the finer the mesh size with caution.
that can be used on a shale shaker. The conduc-
tance of the shaker screen provides a guide for the Rig configuration. On some drilling rigs, the
fluid capability but does not reveal how the screen derrick rig floor is not high enough to allow some
will actually perform. Screens with the same con- shale shakers to be used because the flow line is
ductance may not be able to handle the same flow not high enough. Whichever shaker is used, con-
rate if used on different shale shakers. sideration must be given to providing sufficient
Shaker screen selection programs have been safe power to the shaker motors. It is best to
developed to predict the quantity of solids that can check with the manufacturer concerning the elec-
be removed from a drilling fluid by various shaker trical requirements for individual shakers.
screens on specific commercial shakers. Many pro-
grams start by assuming that the flow rate of drilled Discharge dryness. In some areas, drilled sol-
solids reaching the surface is identical with the ids and drilling fluid cannot be discarded at the rig
generation rate of the drilled solids. Unfortunately, location. This applies to both land and offshore