TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractNanotechnology application can revolutionalise the additive characteristics and behaviour by tuning particle properties to meet certain operational, environmental, and technical requirements. Hence, the nanotechnological research leading to create some tailored made nanoparticles could be a promising step change research for smart fluids development for different industrial applications. These particles are ultra fines in nature, usually larger than an atom cluster but smaller than ordinary micro particles and thus have very high specific surface area with enormous area of interactions. Due to nano-scale particle dimension, the nano-type fluid additives have both external as well as internal inhibition potential, require a very low additive concentration and thus expected to provide superior fluid properties at a drastically reduced additive concentration.Nano-particles with high thermal stability and affinity to acid gases such as H 2 S and CO 2 will help meet the technical challenges of sour gas environment, deep and geothermal drilling and thus expected to complete a well economically and safely with a drastic reduction in oil and gas exploration and exploitation risk. Identification, screening, selection, and/or development of nontoxic, environment friendly and biodegradable nano-particle-based drilling fluids are expected to meet the current as well as the future environmental norms and regulations for drilling and production in deep water and sensitive environments.This paper provides a detailed description of the likely benefits of emerging nano-particle-based additives in smart fluid design for oil and gas field application, especially for a new generation of drilling and drill-in, completion, stimulation, fracturing, etc fluids for trouble-free drilling, completion and production of oil and gas resources.

Successful fracturing treatment necessitates expensive completion assembly that provides some form of isolation to perform controlled fracturing treatments. Currently isolation is performed mechanically which dictates that isolated interval is very short. This in turn may require that the well is cased, cemented and perforated. This would increase the cost of completion significantly. Another option is to focus the fracturing energy via the use of hydrajetting. In this paper we present another approach that provides a high degree of control on where the transverse fractures will initiate and propagate.The various existing techniques for creating multiple hydraulic fractures along an openhole horizontal well are briefly summarized. Laboratory experiments shedding light on some of these techniques will be first presented. The new technique to precisely place a hydraulic fracture in an openhole horizontal well drilled in any direction relative to the in-situ stress field is presented. The new technique is based on rock mechanics understanding of an openhole horizontal well under a given insitu stress field; thus it accounts for the near wellbore stress field to ensure creating a planar hydraulic fracture. Additionally, the new technique does not require costly mechanical isolation to place a hydraulic fracture. Basically, the new technique aims to bypass the near wellbore stress field such that the fracture can be conveniently initiated independently of the stress direction.This new approach is validated using laboratory experiments which will be discussed in details. The experiments were performed on simulated wells casted in rock samples with dimensions of 6"x 6"x10". The samples were triaxially loaded simulating various arrangements of a given wellbore relative to the in-situ stress field. Then, the simulated wells were hydraulically fractured using water based gel. Fracturing pressure versus time was recorded and analyzed.The experiments were very successful in proving the new concept to fracture openhole horizontal wells. The developed technique is fairly easy to implement and the impact of precise placement of a hydraulic fracture across an openhole horizontal well is illustrated.

The rock mechanical poromechanics pressure property, or Biot's effective stress parameter, a, is an important rock matrix and grain characteristic. The Biot's parameter relates stress and pore pressure and weighs the effect of the pore pressure within the concept of the effective stress analysis, in the geomechanics disciplines, and in particular when applied to reservoir engineering and wellbore time-dependent drilling mechanics and stability. It measures the compressibility of the skeletal framework of the rock with respect to the solid material composing the rock. In addition, it also reflects the compressibility of the rock structure which is one of the most important parameters for predicting oil reserves. The poroelastic constant, a, is a complex function of the rock in-situ stress and porosity. The petroleum industry has historically calibrated empirical pore pressure relationships to the effective stress assuming a value of a to be unity or a constant value that may change as the reservoir is being depleted.A theoretical and experimental understanding of the measurements of the poroelastic constant, a, should improve the existing models in the areas lacking the data necessary for an accurate calibration. The paper discusses the various methods of measuring the rock poroelastic parameter, a. These methods include quasi-static and acoustic approaches. In the quasi-static approach, two experimental set-ups, known as the direct and indirect methods, were used in this study to determine a, compared simultaneously with the acoustic method which is based on the compressional and shear wave velocities measurements under hydrostatic loading. The direct method using the quasi-static approach utilizes the measurements of the change in pore volume and bulk volume of the sample for the calculation of a while the indirect method uses the bulk modulus of the fluid saturated rock sample and solid grains in the computation of a.The acoustic approach of measuring a utilizes the measurements of both compressional and shear wave velocities to compute bulk modulus which is then used to compute a; thus, very similar to the indirect technique. The measurements of a using these approaches were performed on fluid-saturated Berea cores, with mineral oil as the saturating fluid. The results obtained from these various techniques are discussed in this work. The indirect method reveals a higher magnitude of the poroelastic constant, a, compared with direct method measurements[1].This difference was found to be large for samples with high porosity, while for low porosity samples the magnitude for the poroelastic constant, a, measured using the two methods was comparable.This is due the fact that low porosity samples have high bulk modulus which tends to lower the magnitude of the poroelastic constant, a, when using the indirect method.The acoustic measurements showed the sensitivity of a to the stress level at which it was measured. The magnitude of the poroelastic constant, a, dropped by 20% for some samples when the pressure increased from 1000 to 9000 psi[2,3].The results of this work also indicate that the measurements of the poroelastic constant, a, using the direct method and acoustic method at early pressure are quite similar for the case of low porosity sample.For high porosity samples the magnitude of the poroelastic constant, a, measured from direct methods was found to fall in the range of acoustic measurements at high pressure. The quasi-static direct method showed a good prediction of a in the absence of the jacketing effect.

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The variability in mechanical properties measured on sands from the Jauf and Unayzah formations of Saudi Arabia is observed to be dependent upon cementation. Understanding the role of cementation in controlling the mechanical properties can improve the design of hydraulic-fracture treatments and, hence, improve reservoir performance.Strength measurements from triaxial-testing data and examination of core in thin sections were used to relate the detailed microstructure and cementation to the variation of mechanical properties. Strength and elastic moduli were determined for 65 samples cored from five different wells. Forty-seven samples were analyzed in thin sections and point counted to determine and quantify cementation. Cements in these two formations have variable composition and habits; both affect the mechanical properties and strength. It is not sufficient to know that cements exist; it is also necessary to know where the cement occurs.Pure quartz overgrowths play a major role in increasing strength, while clay coatings play a minor role. Simple linear correlations were found relating cement concentrations to strength.