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fax 01-972-952-9435. AbstractFoams are of considerable interest for annular pressure management in many drilling applications. While foam rheology and hydraulics have been studied in the past, knowledge of cuttings transport with foam is very limited for vertical wells, and even less well understood for horizontal and inclined-well configurations. In this paper, cuttings transport with foam in horizontal and highly-inclined wells is analyzed.Using the principles of mass and linear momentum conservation, a model consisting of three layers (motionless bed -observed in most experiments, moving foam-cuttings mixture and foam free of cuttings) is presented. The model includes seven independent equations and seven unknowns. A computer simulator was developed to solve simultaneously the system of equations for flow velocities, cuttings bed height, slip velocity, the in-situ concentration of flowing cuttings and pressure drop.An extensive experimental program on cuttings transport was conducted using The University of Tulsa Drilling Research Projects' full-scale (8" by 4 ½") flow loop at 70° to 90° inclinations (from vertical). A broad range of annular velocities and cuttings injection rates was investigated using foam qualities of 70% to 90%. Results from the experiments are presented in the form of graphs showing the cuttings bed cross-sectional area and pressure losses vs. foam flow rate. In all experiments, the foam behaved as a pseudo-plastic fluid; foam qualities of 80% and 90% exhibited noticeable wall slip. At a given flow rate and rate of penetration, bed thickness increases with an increase in foam quality. There is little effect of inclination angles in the range of 70°-90°.The experimental data were used to verify results from the simulator. The simulator is capable of estimating bed thickness and pressure drop with an error of less than 20% in most cases.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractField experience has shown that inefficient transport of small cuttings is a main factor for excessive drag and torque during extended reach drilling; however, very little is known about the transport behavior of small cuttings. In this study, extensive experiments with three sizes of cuttings (0.45 mm-3.3 mm) were conducted in a field-scale flow loop (8 in.×4.5 in., 100-ft long) to identify the main factors affecting small cuttings transport. The effects of cuttings size, drill pipe rotation, fluid rheology, flow rate and hole inclination were investigated.The results show significant differences in cuttings transport based on cuttings size. Smaller cuttings result in a higher cuttings concentration than larger cuttings in a horizontal annulus when tested with water. However, a lower concentration was achieved for smaller cuttings when 0.25 ppb Polyanionic Cellulose (PAC) solutions were used. Unlike the transport of large cuttings, which is mainly dominated by fluid flow rate, the key factors controlling small cuttings transport were found to be pipe rotation and fluid rheology. Improvement by pipe rotation in the transport efficiency of small cuttings is up to twice as large as the improvement in large cuttings transport. Compared with water, PAC solutions significantly improve smaller cuttings transport, while the transport of larger cuttings is only slightly enhanced.Mathematical modeling was performed to develop correlations for cuttings concentration and bed height in an annulus for field applications. Predictions from a three-layer model previously developed for larger cuttings were also compared with experimental results. Differences (up to 80%) indicate the need for improving the frequently used three-layer model by including correlations specifically developed for small cuttings to get a better design of extended reach drilling. This study is also useful for horizontal or high-angle well drilling and completion through sand reservoirs.

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Borehole stability issues are always a spotlight in drilling activities because of their costly consequences, including borehole collapse, lost circulation, stuck pipe etc. Wellbore instability is primarily a function of how rocks respond to the induced stress concentration around the wellbore during various drilling activities. By considering different failure mechanisms between the formation and drilling fluid interaction, several major wellbore models have been presented over the last seventy years. Those models take into account the mechanical, chemical, hydraulic, or thermal effects between the drilling fluid and the formation, or couple two or more effects in a model. The time effect is also taken into account in some of the models. In most of the models,the rock is treated as a continuous materialborehole failure is normally based on single initial failure point. However, rocks are discontinuous materials formed under an environment of complex stresses. Also, it is likely an overstatement to say that instability occurs when only one point fails. Even if a small group of grains disconnects from wellbore, the well can still be stable. While somewhat irregular (noncircular) the wellbore can still accommodate casing and installation of down-hole equipment. Therefore, this paper also introduces a new approach based on grain-scale discrete element modeling (DEM) to mimic the realistic rock condition. The rock is modeled as an assembly of numerous grains bonded by cement-like materials, and pore spaces are formed between the small grains. The dynamics of rock grains is simulated and tracked on a computer. Micro cracks (because of tensile or shear failure) occurring at stress-concentrated zones and their coalescence to form macro fractures are tracked. The borehole shape and size are tracked with time. This paper is useful to those who wish to understand the main limitations of the conventional models and the potential usefulness of a new approach based on a discrete element method (DEM). The approach presented in this paper can also help engineers understand how wellbore instability (post-initial failure) develops with time. Introduction Subsurface rocks are under a balanced stress condition before a well is drilled. Such equilibrium will be disturbed when a well is drilled. Although drilling fluid can partially support the wellbore surface, the presence of a wellbore can cause the redistribution of stresses around the borehole. If the stress concentration exceeds the strength of the rock, failure in the nearwellbore region occurs. Wellbore stability is a major concern in drilling operations. It is the major cause of nonproductive time during drilling operation and costs the oil and gas industry more than $6 billion USD worldwide annually (SPE review, SPE-UK, 2005). With the increasing demand of energy (oil and gas), drilling operations move to the direction where more and more harsh environments are encountered. With more wells to be drilled under high pressure and high temperature conditions, the industry expects more severe wellbore stability problems to occur. Although wellbore stability has been studied (experimentally and theoretically) for many years, it remains one of the major challenges for the oil and gas industry due to the complex nature of the drilled formations. Therefore a better understanding of wellbore stability is of imperative importance for the oil and gas industry. In this paper, the discrete element method (DEM) is adopted in this study to get a better understanding of time-dependent transient wellbore instability that takes place in a realistic rock condition.

Compared to conventional (incompressible) drilling fluids, relatively little is known about the hydraulic and rheological properties of foamed drilling fluids. The complex flow mechanisms involved in compressible drilling fluid circulation make determination of the optimum combination of liquid and gas injection rates very difficult. Modelling of foam rheology is the key issue in hydraulic design, in order to predict the bottom-hole pressure accurately, and to optimize the different controllable variables for effective cutting transport performance.The University of Tulsa's low-pressure ambient temperature flow loop has been recently modified to accommodate foam flow. The flow loop permits foam flow through 0.0508 m (2 in.), 0.0762 m (3 in.), 0.1016 m (4 in.) diameter pipes, and a 0.2032 m (8 in.) by 0.1143 m (4 1 /2 in.) annular section. Preliminary experiments have been conducted, in which pressure losses were measured for different foam qualities. Measured parameters were gas/liquid flow rates, pressure, differential pressure loss, and temperature.Statistical analysis was carried out to see the degree of fit provided by Bingham plastic, power law, and yield power law models for the generalized foam flow curve data.A comparative study was conducted to investigate the predictive ability of the available foam hydraulic models. Models presented by Beyer et al. (1972), Reidenbach et al. (1986), Sanghani and Ikoku (1983), Gardiner et al. (1988 and Valko and Economides (1992) were used to estimate the frictional pressure losses during the flow of foam in horizontal pipes. Comparison of the model predictions with experimental pressure loss values show that model predictions of frictional pressure losses can be different from the actual values by 2 to 250 %. FIGURE 20: Error analysis of foam hydraulic models (70% quality). FIGURE 22: Error analysis of foam hydraulic models (90% quality).FIGURE 21: Error analysis of foam hydraulic models (80% quality).

sodium tetrazolate salts, 1,sand 2,s-disubstituted tetrazoles, bitetrazoles, and cobalt(II1) tetrazolate complexes of the type (PBu3")Co(DH),(5-R-tetrazolate), where DH is the monoanion of dimethylglyoxime.The "N chemical shifts have been analysed with respect to structure, substituent effects, electron density as determined by molecular orbital calculations, Brensted acidity, Lewis basicity and nucleophiiicity of the nitrogen atoms in the ambidentate tetrazoles.

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