North Sea wells drilled in high-pressure, high-temperature (HPHT) areas are known for presenting barite sag challenges. Fluid densities in the 17.5-18.0 lbm/gal range require a high percentage of barite, and 400°F temperatures can adversely impact the rheological properties needed for reliable suspension. Further, horizontal and extended reach drilling (ERD) wells can require specific hydraulic parameters for hole cleaning that may entail comparatively high pump rates which can contribute to excessive equivalent circulating densities (ECD).Drilling fluid companies initially responded to these challenges by utilizing modified barite and alternative weighting agents. Micronized barite has been used to help lower ECD values for years. However, a non-barite manganese tetraoxide weighting agent has proven to provide equivalent anti-sag at a lower cost. The sub-micron sized material has a specific gravity (sg) of 4.8, which is higher than barite. Per Stokes' law, small particles settle more slowly so that sag resistance improves which is important during extended static periods like during extensive coring operations. Manganese tetraoxide is also acid-soluble. These parameters provide more operational flexibility.The manganese tetraoxide weight material has now been tested successfully in a clay-free and economical paraffin/mineral oil-based fluid (OBF) for use in North Sea HPHT applications. The low-solids, clay-free system has a long history of reducing ECD and minimizing downhole losses while drilling, running casing and cementing. The 17.9 lbm/gal fluid weighted with manganese tetraoxide material exhibits effective hole cleaning properties at lower viscosities than conventional OBFs and shows no detectable sag tendency. Clay-free fluids also demonstrate excellent return permeability values in a wide range of well types. This paper details the design and testing of the clay-free ERD system, including extreme HPHT static aging and sag testing and modifications to the emulsifier package. The economics of implementing the commercial system are also discussed.
Proposal Since the introduction of invert emulsion fluids in the 1960s, oil-based fluids (OBF) and synthetic-based fluids (SBF) have been formulated with a similar group of components: base oil, organophilic clay and lignite, lime, CaCl2 brine, and emulsifier. The family of invert emulsion fluids has remained closely related in terms of mud properties and performance expectations. In 2001, an SBF formulated entirely without commercial clays or lignites was introduced in the Gulf of Mexico (GOM). Rheological properties are controlled through the emulsion characteristics, a radical departure from accepted solids suspension mechanisms. The behavior of this unique fluid has changed perceptions about what constitutes "good mud." The clay-free, emulsion-based fluid (System) has consistently prevented detectable barite sag on 80+ wells drilled with it to date. Based on observed fluid densities after long static periods (an 8-day logging run in one case) and verified by modular dynamic test (MDT) log data on numerous high-angle wells, the fluid's unique emulsion structure and wetting characteristics prevent settling of barite and other solids. Attempts to control barite sag with conventional clay-based SBFs have produced mixed results. A 14.0-lb/gal SBF treated with sag-prevention organophilic clay showed a 0.3-lb/gal density reduction in the initial return flow and a 0.3-lb/gal density increase in the tail flow after a 52-hr logging run. This 0.6-lb/gal variation in density was deemed "manageable." However, the treatment resulted in a 20% increase in the funnel viscosity at 75°F, demonstrating an adverse effect on the rheology after increasing the clay concentration by only 0.2 lb/bbl. At lower temperatures encountered at the sea floor, this effect would be amplified. In addition to preventing barite sag, the System has provided other important field-documented performance advantages:Whole mud losses reduced by an average of 60% while drilling, running casing, and cementing (with 80% reductions reported on several deepwater wells).Significantly lower ECDs, validated by pressure-while-drilling (PWD) data.High, flat gel strengths that break with minimal initiation pressure, validated by PWD data.Highest standard of compliance with environmental regulations governing GOM operations. The System is currently under consideration for use offshore West Africa, offshore Brazil, and the Asia-Pacific region. Introduction Since the introduction of invert emulsion fluids in the 1960s, OBFs and SBFs have been formulated with a similar group of components: base oil, organophilic clay and lignite, lime, CaCl2 brine, and emulsifier.1 The family of invert emulsion fluids has remained closely related in terms of mud properties and performance expectations. The invert emulsion fluids were developed to help maximize rates of penetration (ROP), increase lubricity in directional and horizontal wells, and minimize wellbore stability problems such as those caused by reactive shales.2 Until operators began drilling in deepwater locations, where the pore pressure / fracture gradient (PP/FG) margin is often very narrow, the standard formulations provided satisfactory performance. However, the issues raised by deepwater drilling and changing environmental regulations led to a closer examination of several seemingly essential additives. Organophilic Clay The most widely used primary viscosifier for OBFs and SBFs is organophilic clay. Organophilic clay is bentonite that has been treated with an amine to make it yield in oil. However, organophilic clay requires significant shear and circulating time to yield fully. Overtreatment resulting from this delayed response often causes excessive viscosity, and the problem is compounded when the fluid is at ambient temperature or worse, is exposed to cold temperatures at the seabed in deepwater locations.
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