Water-based drilling fluids are an economical and environmentally appealing option for wellbore construction. Both conventional and high-performance varieties of water-based systems typically use biopolymers to provide viscosity, suspend solids, and control fluid loss in the wellbore. Some examples include both naturally occurring biomaterials produced by plants or bacteria (e.g., starch, guar, xanthan) as well as their chemically modified analogues. However, new materials that could help improve efficiency, rate of penetration (ROP), or high-pressure/high-temperature (HP/HT) performance are necessary to expand the use of economical water-based systems in increasingly demanding conditions. Recently identified nanostructured biomaterials, such as nanocellulose, have been observed to have outstanding mechanical, structuring, and thermal properties and are known to be potent viscosifiers at low concentrations. This paper discusses a study that investigates the performance of water-based fluids by either replacing or augmenting their common oilfield biopolymers with cellulose nanofibrils (CNFs). In this study, CNFs produced from technical-grade kraft pulp were mixed in aqueous dispersions with commercial biopolymer viscosifiers, such as xanthan and guar gum. Measurements were made of rheology, dispersion stability, CNF/biopolymer interaction, and filtration behavior as they relate to desirable fluid properties. Unexpected synergies were discovered when the CNFs were blended with secondary biopolymers. Increases or decreases observed in system viscosity were dependent upon the type of biopolymer mixed with nanocellulose but independent of the mass balance of the ingredients. In some mixtures, lower biopolymer concentrations increased viscosity within mixed systems while other mixtures decreased viscosity with increased concentrations. The implications of these unusual findings suggest that performance efficiency can be tailored simply by mixing CNFs with biopolymers that are already used extensively in water-based fluids, allowing an operation to use less material. This discovery can enable a new method to maintain drilling fluid properties during drilling operations with the added benefit of increased temperature stability. By modifying the surface of CNFs with secondary biopolymers, a wide range of fluid behaviors were achieved through changes in surface chemistry, surface morphology, and gel-network formation. Such nanocellulose fluid systems could serve as a renewable, nontoxic, and potentially cheaper alternative to synthetic polymers in high-performance, water-based fluids with the added benefit of controlling and helping to improve fluid properties using a mixture with common oilfield biopolymers.

Drilling activity has increased dramatically in unconventional shale gas reservoirs. The drilling fluid of choice in these shale plays is often nonaqueous-based fluid (NAF). While NAFs can provide advantages such as shale stabilization, lubricity, and contamination tolerance, environmental consequences and associated costs are an issue. These disadvantages cause operators to seek water-based muds (WBMs) for drilling many of these gas reservoirs.Despite some operational similarities, a wide variety of unique downhole conditions can be found in the shale plays. Shale mineralogy and bottomhole temperature (BHT) represent just two highly variable critical factors in unconventional gas reservoirs. Therefore, a single water-based solution for addressing shale plays globally is not a realistic option. Instead, a customized approach that delivers WBMs formulated specifically for a given shale play has been pursued.Customization relies on detailed analysis of the well parameters of a given shale play. This analysis includes not only the shale morphology and lithology but also well drilling program plans, environmental factors, and other reservoir-specific considerations. Applying appropriate drilling-fluid chemistries on the basis of this detailed analysis has led to the successful field deployment of a number of new shale fluids.Details of the process used for customizing a WBM for a shale play, as well as specific examples of new fluids developed for the Barnett, Fayetteville, and Haynesville shales, are presented in this paper. Full laboratory development and testing are described. Additionally, field-trial results are presented that show that specially designed WBMs can provide performance comparable to that of NAFs, but with enhanced environmental and economic benefits. Application of the customization process to develop WBMs for other shale plays around the globe is also discussed.

An efficient synthesis of the ABCD-ring system of lactonamycin (1) is reported in this Letter. The key step is the tandem cyanide conjugate addition-Dieckmann condensation of alkyne 17 to afford a fully functionalized anthracene. Selective reduction of the cyano group with subsequent lactam formation affords the tetracyclic core of lactonamycin 19. [reaction: see text]

Water-based drilling fluids provide an economical and environmentally attractive option for wellbore construction. Despite the development of high performance water-based fluids, consistent demonstration of drilling performance comparable to oil-based fluids has proven to be elusive. Both traditional and high-performance water-based systems typically use biopolymers to provide filtration control, viscosity, and suspension properties. These biopolymers include naturally occurring materials, such as celluloses, starches, hydrocolloids, and bacterially engineered polymers, such as xanthan gum. Although several options exist, new materials are always desired to improve efficiency or enhance high pressure, high temperature (HPHT) performance. Recently identified nano-structured biomaterials, such as nanocelluloses, have been used in the development of advanced materials systems because of their outstanding mechanical, structuring, and thermal properties; they are also potent viscosifiers at relatively low concentrations (~0.5 wt %). This paper explores the rheological, thermal, and fluid loss properties of as-produced and covalently modified cellulose nanofibers in saline water-based fluids. Results are compared to a commercial xanthan gum viscosifier as used in saline water-based drilling fluids. Cellulose nanofibrils were produced from kraft pulp wood fibers by using known methods based on mechanical shearing. Using a standard concentration in water, measurements were made of complex rheology, filtration (API LPLT test), and equivalent and total surface charge. The nanocellulose materials were then modified by means of simple chemical reactions to tailor the surface properties, and then compared to the original material. The same battery of tests was run in control experiments performed with a commercial xanthan gum-based viscosifier. By modifying the surface of nanocellulose with new covalently bound functional groups, a wide range of fluid behaviors was achieved through the control of the resulting changes in surface chemistry. Unlike nanomaterials based on graphitic carbon, such as nanotubes and graphene, cellulose features a natural polymer backbone chemistry having three available hydroxyl sites on each cellulose repeat unit. The secondary alcohol group at position 6 on the β-D-glucopyranose ring is especially well-suited for site-selective reactions, such as oxidation. The new surfaces created with each new functional group provide different modes of interaction with salt ions, water molecules, and other biopolymers in the fluid to change fluid properties. This work introduces a new renewable, non-toxic, and potentially less expensive alternative to synthetic polymers for viscosity and filtration control in high-performance water-based drilling and completion fluids. Furthermore, nanocellulose materials can be modified through simple chemical reactions to provide improved performance or to tailor their effects and interactions with other components.

Drill-in fluids, also known as reservoir drilling fluids, are specifically designed to help minimize formation damage and facilitate wellbore cleanup. Typical water-based drill-in fluids use brines to achieve a desired fluid density and rely on acid-soluble solids, such as calcium carbonate, for bridging of pore spaces. Biopolymers, such as xanthan gum and crosslinked starch, are generally used as viscosifiers and fluid-loss additives for the drill-in fluids. Unfortunately, these biopolymers begin to degrade at temperatures greater than 275°F. As a result, conventional water-based drill-in fluids are generally limited to wells with temperatures below 300°F. Clay-free, brine-based drill-in fluids for temperatures greater than 300°F still pose challenges in high-pressure/high-temperature (HP/HT) conditions. Novel high density brine-based drill-in fluids have been developed using a specifically designed dual-functional polymer as a thermally stable viscosifier and fluid-loss additive. Divalent brines, such as CaBr2 (14.2 lbm/gal) and CaCl2 (11.6 lbm/gal), were used as the base fluids. The drill-in fluids show similar thixotropic behavior to those biopolymer-based, yet exhibit excellent thermal stability up to 450°F, which is at least 150°F higher than typical drill-in fluids. After static aging at 450°F for 16 hours, the fluids exhibited only slight color change, and no stratification or solid settling was observed. Rheological properties of the aged samples increased slightly compared to samples before aging. The samples still provided excellent fluid-loss control, even after aging, with a measured HP/HT fluid loss less than 10 mL after 30 minutes at 350°F. Core flow testing showed that the drill-in fluid is nondamaging after acid breaker treatment, with a return permeability of 100%.