Summary
One important issue for drilling operations is control of downhole
pressures. When drilling with synthetic- or oil-based drilling fluids,
the ability to maintain all the weighting agents in suspension is particularly
difficult because these fluids are more vulnerable toward sag than water-based
drilling fluids.
In the current study, it will be shown that the ability to keep barite in
suspension also depends on the chemical composition of the water
phase. The sag tendency of a mineral-oil-based drilling fluid, a linear
paraffin-based drilling fluid, and both an ester- and a linear-alpha-olefin
(LAO) -based synthetic drilling fluid has been evaluated. For comparison,
all fluids were formulated with equivalent water activity in the internal brine
phase. The results show that for all these fluids, improved performance
was observed if the traditional calcium chloride (CaCl2) salt was replaced with
a selection of other salts. Formates as the internal salt gave generally
better performance than if calcium chloride was used. The best stability
in the tests was observed using an ammonium calcium nitrate [NH4Ca(NO3)] as the
internal salt phase, which also enhances the environmental performance of the
fluid.
This paper describes in detail the effect that different salts in the
internal brine phases in synthetic- and oil-based drilling fluids had on sag
performance in a series of tests.
Introduction
Settling of barite in drilling fluids may cause several problems during
drilling and completion of a well. While drilling, these problems range
from having insufficient drilling-fluid density for well control to fracturing
the formation when resuspending a barite bed. Additionally, the settling
of barite may hinder the running of casing as well as cause insufficient
displacement efficiency during cementing operations. Settled weight
material also may cause problems during completion operations.
Within the petroleum industry, the serious study of the sag phenomenon
started in the late 1980s. Hanson et al. (1990) and Jefferson (1991)
focused on practical guidelines to prevent sag. They emphasized the
importance of dynamic sag (i.e., sag occurring while slowly circulating the
drilling fluid). They recognized that preventing dynamic sag is more difficult
than preventing static sag. Furthermore, they discovered that the sag
tendency was significantly higher in deviated wells than in vertical
ones. This is because of a phenomenon first discovered by the American
physicist A.E. Boycott (1920) who noticed that blood corpuscles gravitate three
to five times faster in inclined tubes that in vertical ones. This Boycott
settling was found by all the early investigators to be a major contributor to
sag in drilling fluids. When the particles settle downward in the
inclined pipe or annulus, low-density fluid is forced upward, while
high-density fluid moves downward along the low side of the hole. This
creates a pressure imbalance, which accelerates the fluid movement and the
separation process
Jamison and Clements (1990) also used an inclined tube to study barite sag
in static drilling fluids. Their data showed a tendency for increased sag
potential with reduced viscosity or gel strength of the drilling
fluid. There was, however, a significant scatter in their sag vs.
viscosity data. On the basis of this scatter, they concluded that it was
not possible to relate the sag potential of a static drilling fluid to
parameters such as yield point, plastic viscosity, or 10-second or 10-minute
gel strength as measured by the standard American Petroleum Inst. (API) methods
(API RP 13B-1 1990).
© 2006. Society of Petroleum Engineers
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History
- Original manuscript received:
19 May 2004
- Revised manuscript received:
10 March 2005
- Manuscript approved:
10 November 2005
- Version of record:
20 June 2006
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