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These muds also contained organics that were susceptible to
bacteria degradation.
Many thousands of wells have been drilled successfully with
proper use of quality lignosulfonates and chrome lignites. Proper
chemical treatment at the end of the well includes raising the pH,
adding a biocide and a dispersible organic amine packer fluid
inhibitor if a fresh-water-base fluid is used. We understand that the
casing had long, useful life when treated in this manner — while
documentation is not easily available; sources indicate this as the
trend. Relevant to the subject, Getty Oil Co. wrote a technical paper,
published by NACE International, based on South Louisiana field
case histories, mainly on high-strength tubulars in lignosulfonate
systems. The lignosulfonate was not necessarily deemed the culprit
from the field case histories as others had claimed. This operator
realized the need for high pH and bacteria control. And the report
showed that, with proper conditioning, water-based fluids were
more protective than some authors of this period realized. For
increased temperature stability of some water-base systems,
gypsum and salt muds were treated with a group of new additives
called "surfactants," including drilling mud surfactant (DMS) and
drilling mud emulsifier (DME). And as usual, during this period,
diesel was important for lubrication, inhibition and fluid loss
control. Oil was chemically emulsified into the water-based fluids
in the 10 - 12% by volume range. The resulting oil-wet film
probably played an important part in corrosion control in these
systems. These fluids were used in the deep drilling trend in South
Texas, with BHTs ranging over 450° to 500°F.

The 1970-1980 Period

In the early 1970s, the low-pH KC1 / Polymer muds emerged
as drilling fluids by choice. These fluids were found to minimize
hole problems in many areas, but the external fluid phase could
cause corrosion. Salt content is near that of seawater and it was

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