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However, they are suitable only for relatively low temperature and pressure drilling operations. For high temperature and high pressure (HTHP) drilling operations, the requirements for the drilling fluids are more severe, and usually oil-based fluids or muds (OBM) are employed. According to the US Department of Energy Deep Trek program [2], a 2009 NATIONAL TECHNICAL CONFERENCE & EXHIBITION, HTHP drilling operation is defined as one where the bore hole static NEW ORLEANS, LOUISIANA temperature (BHST) exceeds 177oC (350oF) and the pressure is in excess of 25,000 psi. However, as the depth of the drilling wells keeps increasing, o AADE 2009NTCE-18-05 more severe drilling conditions can be expected which may exceed 315 C (600oF) temperature and 40,000 psi pressure [3]. In such extreme Using Nanoparticles and Nanofluids to Tailor Transport conditions, oil-based drilling fluids are preferred because of their better Properties of Drilling Fluids for HTHP stability [1, 4, 5]. However, at HTHP conditions, drilling fluids are also Operations likely to experience gelation, degradation of weighting materials and the Author(s) & Affiliations: breakdown of polymeric additives which act as viscosifiers, surfactants Sushant Agarwal, Department of Chemical Engineering, West and fluid-loss additives [6]. Note that the thermal degradation of polymeric Virginia University, Morgantown, WV. additives leads to loss in rheological properties which can cause serious Lynn M. Walker, Department of Chemical Engineering, Carnegie- operational problems such as barite sag. OBMs, in particular, are more Mellon University, Pittsburgh, PA. susceptible to barite sag [5] at HTHP conditions. Thus, developing OBMs Dennis C. Prieve, Department of Chemical Engineering, for HTHP operations which maintain their rheological properties remains Carnegie-Mellon University, Pittsburgh, PA.Yee Soong, National a desirable task. Energy Technology Laboratory, Pittsburgh, PA. Rakesh K. Gupta, Department of Chemical Engineering, West Virginia The objective of this research was to use nanoparticles and nanofluids in University, Morgantown, WV. OBMs to tailor their functionality at HTHP drilling conditions. Nanomaterials and nanofluids can potentially be utilized in several ways in this regard. For example, they can be used to enhance gel forming ability of these fluids in place of polymers. In water-based drilling fluids, Abstract nanoparticles of mixed metal hydroxides (MMH) have already been used to replace polymers as viscosity modifying agents [7]. Nanoparticles of Many polymeric components are added to drilling fluids in order to MMH work as a bridging material between the platelets of modify their rheology and enhance stability; these additives function as bentonite/montmorillonite clay to form a gel structure which breaks down viscosifiers, surfactants, emulsion stabilizers and filtration agents in the easily under shear. On adding only very small amount, say 0.2 wt%, of drilling fluids. For high temperature and high pressure (HTHP) deep MMH, the yield point changes significantly but the plastic viscosity does drilling operations, where temperatures can approach 316oC (600oF) and not increase very much [7]. Another potential application of nanoparticles pressures can reach 40,000 psi, drilling fluids can undergo loss in is to use them to stabilize water-in-oil emulsions in place of polymeric properties and functionality due to degradation of polymeric additives. surfactants. Depending on the hydrophobic and hydrophilic nature of the Thus, it is desirable to replace some of these polymeric additives with nanoparticle surface, the nanoparticles can be used to stabilize oil-in-water materials that can withstand HTHP operating conditions over an extended or water-in-oil emulsions. [8-10]. Nanoparticles of various shapes, sizes period of time. In this paper, we examine the ability of nanoparticles of and surface characteristics are available, and these can be employed for alumina and copper oxide to manage rheological properties of HTHP this purpose. In this paper, preliminary data are presented on oil-based drilling fluids. These nanoparticles were added to model oil-based drilling fluids containing nanoparticles, and the effect of aging at high temperature fluids, and their properties were measured at room temperature both before is examined. and after aging at 175oC (347oF) for up to 96hrs. It was found that these fluids maintained their flow properties upon aging, and this work provides Materials and Sample Preparation preliminary evidence that nanoparticles may potentially be used to manage properties of drilling fluids for HTHP operations. Poly 1-decene synthetic oil was purchased from Sigma-Aldrich, while organically-modified nanoclay Cloiste® 20A was obtained from Southern Introduction Clay Products. This clay is a montmorillonite clay which has been treated with dimethyl dehydrogenated tallow quarternary ammonium ion to Drilling fluids are essential in rotary drilling operations for oil or natural render its surface hydrophobic for easy dispersion in a non-polar medium. gas wells. Drilling fluids serve many purposes in a drilling operation; these Nanodur® nano alumina powder and Nanoarc® nano copper oxide (CuO) include the removal of cuttings, lubricating the drill bits, maintaining the were obtained from Alfa-Aesar, and all the materials were used as stability of the hole and preventing the inflow-outflow of fluids between received. The average particle size of the nanoalumina powder is reported borehole and the shale formation [1]. Many different kinds of drilling to be 40-50 nm; however dynamic light scattering (DLS) measurements in fluids are available, and which one is used depends on the drilling aqueous dispersions showed the average size to be ~200 nm, which requirements. Depending on the characteristics of the base fluid, the suggests the presence of agglomerates. Similarly, for nano CuO, the drilling fluids are classified as water-based (brines or muds), oil-based (oil- reported size was 23-37 nm, but DLS measurements showed dispersions or invert-emulsions) or gaseous fluids (foams, aerated muds or agglomerated structures of about 800nm in size. aphrons). Water-based fluids or muds (WBM) are the most common.

Page 1 of 3, 04f81b7237d72e86e06f82d6dfbfbcd5.doc To prepare samples of the fluids, the appropriate amount of nanoclay was Clearly a shear thinning behavior is observed. Though there is very little first added to the polydecene oil. This dispersion was ultrasonicated with a increase in viscosity at the 0.4wt% level, a significant increase is observed high intensity 750 watt ultrasonic horn for 30 seconds. It was then stirred at the 2wt% nano alumina loading level. Figure 2 shows the viscosity as a by a magnetic stirrer for 24hrs. Following this, the appropriate amount of function of time of aging at 175oC for fluids containing 0.4wt% deionized water was added, and the dispersion was ultrasonicated again nanoalumina and also for the base fluid. for 30 seconds. At this point, the dispersion became an invert emulsion with a white gel-like appearance. To prepare samples containing nanoparticles, the appropriate amount of nanoparticles were added to the 100000 4wt%Cloisite (base) deionized water which was ultrasonicated to break the agglomerates. This 4wt%Cloisite(base)-96hrs High T dispersion was then added to the nanoclay-oil dispersion with 10000 nanoAl2O3-fresh ultrasonication to obtain an invert emulsion containing nanoparticles. nano Al2O3-24hr HighT ) e

s 1000 i nanoAl2O3-96hr HighT o P

Rheology Measurements and High Temperature Aging (

y t i s o

c 100 s i The rheological properties of the different fluids were measured using a v Carri-Med CSL100 controlled stress rheometer. Parallel plate fixture with 4cm diameter flat plates and a 1mm gap was employed to make the 10 measurements. After loading the samples and adjusting the gap, the fluids

2 1 were sheared at a constant shear stress of 2000 dynes/cm for 1 hr to 1.00E-03 1.00E-02 1.00E-01 1.00E+00 1.00E+01 1.00E+02 1.00E+03 impart a uniform shear history to all samples. After this pre-shearing step, shear rate (1/s) the samples were allowed to rest for 10 minutes. Finally, stress ramp up and ramp down measurements were made. All measurements were carried Figure 2. Effect of aging at 175oC on the viscosity of the base fluid and o o out at 25 C (77 F). on the fluid containing 0.4wt% nano alumina.

To study the effect of high temperature aging, these drilling fluids were In order to better understand the effect of adding nanoparticles and thermal placed in a tightly sealed tubing reactor. The reactor was then kept in an aging on the rheological properties, especially the plastic viscosity and the o o oven at 175 C (347 F) for periods of up to 96 hours for static aging. After yield point, of the base fluid, various models, such as Bingham, Casson this, the reactor was quench cooled in a water bath, and the aged drilling and Herschel Bulkeley models, were fitted to these data. It was found that fluid sample was withdrawn for rheology measurements. the Casson model provided the best fit to the data; this model is given by

Results and Discussion    y   p ˙ (1) For this study, the various drilling fluids were prepared using poly1- 2 decene as the oil base (viscosity = 0.69 poise, density = 0.833 gm/cc). where,  is the shear stress (dynes/cm ), y is the yield strength Other components were 4wt% Cloisite20A, an organically-modified clay, 2 (dynes/cm ), p is the plastic viscosity (poise) and ˙ is the shear rate (1/s). and 20%v deionized water. This formed the benchmark fluid for By fitting experimental results for the flow curves to the model, the yield comparison with nanoparticle-containing fluids. Figure 1 shows the strength and the plastic viscosity were obtained for these fluids. These viscosity versus shear rate curve for the base fluid and for the fluids results are displayed in Table 1. containing nanoparticles. Presented in this figure are the effects of adding 0.4wt% nanoalumina or nano CuO or 2wt% nano alumina to the base Table 1. Effect of adding nanoparticles on rheological properties of fluid. base fluid.

Polydecene+4wt%Cloisite20A+20%v Plastic Yield strength 100000 2 4wt%Cloisite (base) water + viscosity (dyne/cm ) nanoCuO (0.4wt%) (poise) 10000 nanoAl2O3 (0.4wt%)

nanoAl2O3(2wt%) 0 wt% nano particles 1.47 86.5 ) e

s 1000 i o P (

y t i 0.4wt% nano alumina 1.65 111.79 s o

c 100 s i v 0.4wt% nano CuO 1.58 126.5

10 2wt % nano alumina 1.73 194.3

1 1.00E-03 1.00E-02 1.00E-01 1.00E+00 1.00E+01 1.00E+02 1.00E+03 shear rate (1/s)

Both the viscosity and yield strength increase on adding nanoparticles. Figure 1. Shear viscosity versus shear rate for the base fluid and with However, there seems to be a larger enhancement in yield strength than in the addition of nanoparticles. the viscosity, and this is actually desirable. Table 2 shows the effect of 3. Gusler, W., M. Pless, J. Maxey, P. Grover, J. Perez, J. Moon high temperature aging on these properties. and T. Baaz, “A New Extreme HPHT Viscometer for New Drilling Fluid Challenge”, SPE Drilling and Completion, 81, June, (2007).

4. Chilingarian, G. V. and P. Vorabutr, Drilling and Drilling Fluids, Elsevier, 1983. Table 2. Effect of aging at 175oC on rheological properties of various fluids 5. Taugbol, K., G. Fimreite, O. I. Prebensen, M. I. Sweco, K. Svanes, T. H. Omland, P. E. Svela and D. H. Breivik, 0.4wt% nano alumina 0.4wt% nano CuO “Development and Field Testing of a Unique High Temperature/High Pressure Oil-Based Drilling Fluid with Hours at Plastic Yield strength Plastic Yield strength Minimum Rheology and Maximum Sag Stability”, Journal Of 175oC viscosity (dyne/cm2) viscosity (dyne/cm2) Offshore Technology, 13, 46 (2005). (347oF) (poise) (poise) 6. Oakley, D. J., K. Morton, A. Eunson, A. Gilmour, D. Pritchard, 0 1.65 111.8 1.58 126.5 A. Valentine, “Innovative Drilling Fluid Design and Rigorous Pre-wall planning Enable Success in Extreme HTHP well”, 24 1.75 134.0 1.85 272.6 IADC/SPE62729, 2000 IADC/SPE Asia Pacific drilling technology, Malaysia, 11-13 September, 2000. 96 1.76 125.9 7. Plank, J., Keilhofer, G. and Lange, P., MMH-Bentonite Fluids Provide Outstanding Performance in Oil Field Drilling, Oil & Gas Journal, 39, March 13, (2000). From the table above, it can be seen that viscosity and yield strength both increase slightly on aging. This may be due to better dispersion of 8. Aveyard, R., B. P. Binks and J. H. Clint, “Emulsions Stabilized nanoclays and nanoparticles upon high temperature aging. It is also seen Solely by Colloid Particles”, Advances in Colloid and Interface that samples with nano CuO show a much larger enhancement in flow Science, 100-102, 503, (2003). properties, but the reason for this behavior is not clear. Nonetheless, we can conclude that the addition of nanoparticles to drilling fluids has a 9. Binks, B. P., John H. Clint and Catherine P. Whitby, positive effect on the properties. Work is continuing to further study the “Rheological Behavior of Water-in-Oil Emulsions Stabilized by effect of adding nanomaterials at more severe HTHP conditions. Hydrophobic Bentonite Particles”, Langmuir, 21, 5307, (2005).

Conclusions 10. Torres, L.G., R. Iturbe, M.J. Snowden, B.Z. Chowdhry, S.A. Leharne, “Preparation of O/W Emulsions Stabilized by Solid It is proposed that nanomaterials can be added to drilling fluids to replace Particles and Their Characterization by Oscillatory Rheology”, some of the polymeric additives which may degrade at HTHP drilling Colloids and Surfaces A: Physicochem. Eng. Aspects, 302, 439 conditions. To verify this hypothesis, oil-based drilling fluids containing (2007). nanomaterials were prepared, and these were subjected to high temperature (175oC) aging for up to 96 hours. Their rheological properties were measured which showed that drilling fluids maintain their properties after aging. These results demonstrate that a potential exists for using nanomaterials and nanofluids to tailor drilling fluids for HTHP operations.

Acknowledgements

This technical effort was performed in support of the National Energy Technology Laboratory’s on-going research in “Nanofluids for oil and gas deep hole drilling” under the RDS contract DE-AC26-04NT41817.

References

1. Darley, H. C. H. and G. R. Gray, “Composition and Properties of Drilling and Completion Fluids”, Gulf Publishing Company, Houston, TX, 1988.

2. Drilling and Completion Gaps for HPHT Wells in Deep Water- Final Report, Department of Interior, prepared by T. Proehl and F. Sabins, 2006.

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