American Oil and Gas Reporter - November 2016 - 71

SpecialReport: Drilling Fluids Update
tion/properties and wellbore geometry/conditions. Modeled predictions, especially
mud weight variations in the fluid collected
at the surface after a sag event, were validated successfully on several wells and
fluid systems.
Figure 2 is an example output from
the mathematical model showing a fluid
mud weight profile after a 50-hour trip.
In this example, the sag model estimates
the surface mud weight of the fluid at
bottoms-up (i.e., a lighter portion averaging
16 pounds/gallon followed by a heavier
portion of 17.6 pounds/gallon).
NAFs typically contain high levels of
salts in the internal phase of the emulsion
to provide wellbore stabilization/osmotic
control. Environmental concerns with
disposing of oil-wet cuttings are well
known, but chloride residue on cuttings
resulting from calcium chloride or sodium
chloride also pose cutting disposal issues.
The salts do not biodegrade and high
concentrations can accumulate in soils.
Accordingly, another Halliburton research initiative developed a salt-free
NAF with the performance of a conventional NAF. It uses a biodegradable
organic in place of chlorides to provide
an internal phase with equivalent water
activity to traditional salt-containing
systems. The salt-free system was field
validated in multiple wells in the Western
Canadian Sedimentary Basin.
Jonathan Walker and his colleagues
at Halliburton presented the results of
this work at the IADC/SPE drilling conference. The salt-free NAF was initially
laboratory tested. Two major components
of the fluid are the biodegradable organic
as the internal phase and a proprietary
oil-based mud stabilizer. The stabilizer
provides both suspension and filtration
control in the fluid, and is necessary at
higher temperatures to prevent sagging.
Table 1 shows the properties of the
salt-free formulation used in the lab study
compared with a traditional NAF containing chlorides.
The lab testing was followed by field

trials on a seven-well pad in Alberta.
Three of the wells were drilled with the
salt-free NAF and the other four with a
conventional invert emulsion fluid. The
salt-free system performed the same as
or better than the conventional fluids.
Observed improvements over conventional
NAFs included less fluid maintenance,
greater inhibition of the formation, and

less fluid loss (in part, resulting from reduced oil on cuttings).
Moreover, a bioremediation study to
analyze cuttings from each well for electrical conductivity and plant growth
showed that when mixed with topsoil,
the salt-free cuttings allowed for viable
plant growth while the conventional cuttings did not. The system ultimately re-

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NOVEMBER 2016 71
American Oil and Gas Reporter - November 2016

Table of Contents for the Digital Edition of American Oil and Gas Reporter - November 2016
