The Effect of the Synthetic- and Oil-Based Drilling Fluid's Internal Water-Phase Composition on Barite Sag
- Tor Henry Omland (Statoil ASA) | Tron Albertsen (M-I Norge AS) | Knut Taugbol (Statoil) | Arild Saasen (Statoil ASA) | Kare Svanes (Statoil Norway) | Per Amund Amundsen (U. of Stavanger)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- June 2006
- Document Type
- Journal Paper
- 91 - 98
- 2006. Society of Petroleum Engineers
- 2 Well Completion, 2.7.1 Completion Fluids, 4.1.2 Separation and Treating, 4.1.5 Processing Equipment, 1.11.2 Drilling Fluid Selection and Formulation (Chemistry, Properties), 2.2.3 Fluid Loss Control, 1.11 Drilling Fluids and Materials, 1.6 Drilling Operations, 1.14 Casing and Cementing, 6.2.4 Industrial Hygiene, 1.7.5 Well Control
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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.
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).
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