Thesis (M.S.)--West Virginia University, 2007. / Title from document title page. Document formatted into pages; contains x, 65 p. : ill. (some col.). Includes abstract. Includes bibliographical references (p. 58-60).

Thesis (M.A.)--Florida State University, 2003. / Advisor: Dr. Dennis D. Moore, Florida State University, College of Arts and Sciences, Program in American and Florida Studies. Title and description from dissertation home page (viewed Mar. 2, 2004). Includes bibliographical references.

Thesis (Ph.D.)--University of Tulsa, 1994. / Includes bibliographical references (leaves 87-92).

The first main goal of this research is to develop comprehensive analytical and numerical models for the stress distribution around an inclined cased wellbore by considering all wellbore processes and to amend erroneous models of most previous work. The second main goal is to apply the developed models to explain near wellbore phenomena such as cement failure and sand production. To achieve these goals, this work checked the eligibility of using simple elastic approaches for the system by using a poroelastic undrained condition and a steady state condition for stresses induced by wellbore temperature variation. It utilized the generalized plane strain to compensate for the limitation of the plane strain which most previous work had used. In addition, this research developed comprehensive models to improve previous work by using superposing principles. For applying the developed models to cement failure, Mogi-Coulomb criterion for shear failure instead of Mohr-Coulomb and Drucker-Prager criteria was used to properly consider the intermediate stress. Additionally, ABAQUSr was utilized for numerical models with the "model change" option to simulate and combine all individual wellbore processes while MATLABr was used for analytical models. For predicting sand production, fully coupled poroelastic solutions for an inclined open wellbore were modified to obtain the stress distribution around a perforation tunnel after perforating. Then, modified Lade failure criterion was used to calculate the critical drawdown when sand production occurs, that is, when the perforation tunnel starts failure. This research obtained the following results. For developing models, the analytical models improved the previous research. However, the numerical results under a vertical tectonic stress showed discrepancies because of the difference between the generalized plane strain and numerical models. For cement failure, Young's modulus of cement, wellbore pressure and wellbore temperature variation could affect shear failure more significantly than the other factors. The numerical results showed closer to the failure envelopes than the analytical results. For predicting sand production, well completion affected sand production near wellbore and the critical drawdown converged to asymptotic values. In addition, perforating along the minimum horizontal stress direction was most preferable in a vertical cased wellbore under a normal stress regime. / text

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The annular cement sheath plays a crucial role in ensuring well integrity by providing adequate zonal isolation, stabilizing the formation, and protecting the casing from corrosion. A majority of well integrity problems originate from oil well cement shrinkage and shrinkage-induced cracking, as well as cracking induced by other external stresses. The addition of expansive additives is a commonly used way to compensate for shrinkage. Compared to conventional ettringite-based and CaO-based expansive additives, MgO has many advantages including a thermally stable hydration product, relatively low water requirements for hydration, and designable expansion properties. These make MgO a promising candidate for delivering the desired expansion under the complex and variable underground wellbore environment. Self-healing materials which have the capability for autonomous crack repair are an attractive solution for addressing cracking problems in oil well cement. Engineered additions of healing agents for autonomic self-healing via a delivery system have been reported as effective ways to promote self-healing in cementitious materials. Microcapsules that can be easily added to cement pastes and dispersed through the cement matrix are considered particularly suitable for use in oil well cement. This research project investigates the efficacy of reactive MgO expansive additives to reduce shrinkage, and of sodium silicate microcapsules to improve the self-healing properties of oil well cement, and explores the feasibility of their combined use in a high temperature oil well environment. Three types of reactive MgOs from different reactivity grades, high reactivity N50, medium reactivity MAG-R, and low reactivity 92/200, were characterised in terms of their expansion characteristics in cement paste prisms cured in water, and further tested on their autogenous shrinkage reduction at 80oC. The highly reactive N50 could only partially compensate for autogenous shrinkage, while the less reactive MAG-R and 92/200 completely compensated for autogenous shrinkage. MAG-R and 92/200 also showed effective drying shrinkage reduction at 90% RH. The restrained expansion of MAG-R and 92/200 during an early age was found to significantly improve the cracking resistance of oil well cement. The free expansion of 92/200, with low reactivity, caused significant strength reduction, but under restrained conditions the effect was mitigated as its compressive strength was enhanced by confined expansion. The addition of MAG-R increased compressive strength under both free and restrained conditions. Two groups of sodium silicate microcapsules, T1 with rigid polyurea shells and T2 with rubbery polyurea shells, were characterised in terms of their thermal stability, alkalinity resistance and survivability during cement mixing, and the results verified their suitability for use in oil well cement at the high temperature of 80 oC. The effects of the two types of microcapsules on the self-healing performance of oil well cement at 80 oC were monitored using a variety of techniques. Oil well cement itself showed very little healing capability when cured at 80 oC, but the addition of microcapsules significantly promoted its self-healing performance, showing reduced crack width and crack depth, enhanced tightness recovery against gas permeability and water sorptivity, as well as strength recovery. Microstructure analyses of the cracking surface further verified the successful release of the sodium silicate core and its reaction with the cement matrix to form C-S-H healing products. Both groups of microcapsules showed comparable self-healing efficiency. Their different shell properties mainly influenced the strength of oil well cement, with rigid shell microcapsules causing less strength reduction than rubbery shell microcapsules. The overall performance of oil well cement containing both reactive MgO and microcapsules were evaluated. The combined addition of MgO MAG-R and T1 microcapsules showed similar expansion performance and self-healing efficiency compared to their individual use. The use of MgO MAG-R compensated for the strength reduction caused by the addition of microcapsules, achieving an overall improvement in the cement strength.

The study of coning in oil production is important because of huge water production associated with oil production around the world each year. Estimation of critical coning rate has been the subject of numerous studies and a number of correlations have been reported. This study presents a review of the current available methods for estimating critical coning rate for both vertical and horizontal wells. The various methods and correlations are compared and the assumptions on which they are based evaluated. Following comparison made between the correlations, the most reliable theories are identified for both vertical and horizontal wells separately. Among the correlations for vertical wells, this study recommends two implicit methods presented by Wheatley and Azar Nejad et al. They determined the oil potential distribution influenced by water cone with a remarkable accuracy. For horizontal wells, two methods, Joshi???s equation and Rechem et al formula, are considered to be the most reliable. Joshi???s equation provides lower estimates than Chaperon???s correlation in which the water cone effect on oil potential was neglected. The Recham et al formula also gives a similar result. On the whole, the Rechem et al method is preferred.

This dissertation implements three-dimensional numerical simulation models to interpret formation-tester measurements acquired at arbitrary angles of wellbore deviation. Simulations include the dynamic effects of mud-filtrate invasion and multi-phase flow. Likewise, they explicitly consider the asymmetric spatial distribution of water-base and oil-base mud filtrate in the near-wellbore region due to the interplay of viscous, gravity, and capillary forces. Specific problems considered by the dissertation are: (a) estimation of permeability from formation-tester measurements (pressure and fractional flow) affected by multi-phase flow and mud-filtrate invasion, (b) quantification of the spatial zone of response of transient measurements of pressure and fractional flow rate, (c) prediction of fluid-cleanup times during sampling operations in vertical and deviated wells, (d) joint inversion of formation-tester and resistivity measurements to estimate initial water saturation and permeability of multi-layer models, and (e) estimation of saturation-dependent relative permeability and capillary pressure using selective measurement weighting and Design-of-Experiment (DoE) methods to secure a reliable initial guess for nonlinear inversion. Using realistic tool and formation configurations, field measurements validate the reliability of the proposed methods. In one example, multi-layer rock formations are modeled using electrofacies derived from nuclear magnetic resonance logs, thereby reducing the number of unknown layer permeability values from 22 to 6. In the same example, non-uniqueness in the estimation of permeability is reduced with the quantitative integration of resistivity and formation-tester measurements. A second field example undertakes the estimation of permeability by history matching both pressure and gas-oil ratio (GOR) measurements acquired with a focused-sampling probe in a 27° deviated well. Because the latter measurements are affected by partial miscibility between oil-base mud and in-situ oil, Equation-of-State (EOS) simulations are used to account for variations of fluid viscosity, fluid compressibility, fluid density, and GOR during the processes of invasion and fluid pumpout. Results indicate that gravity-segregation and capillary-pressure effects become significant with increasing angles of wellbore deviation. If not accounted for, such effects could substantially degrade the estimation of permeability. Synthetic and field examples confirm that standard formation-tester interpretation techniques based on single-phase analytical solutions lead to biased estimations of permeability, especially in deviated wells or when complete fluid cleanup is not achieved during sampling. In addition, it is found that gravity-segregated invaded formations strongly affect predictions of fluid sampling time. Reliable and accurate estimations of petrophysical properties are only possible when both the angle of wellbore deviation and the process of mud-filtrate invasion are included in the interpretation methods. / text

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The study of coning in oil production is important because of huge water production associated with oil production around the world each year. Estimation of critical coning rate has been the subject of numerous studies and a number of correlations have been reported. This study presents a review of the current available methods for estimating critical coning rate for both vertical and horizontal wells. The various methods and correlations are compared and the assumptions on which they are based evaluated. Following comparison made between the correlations, the most reliable theories are identified for both vertical and horizontal wells separately. Among the correlations for vertical wells, this study recommends two implicit methods presented by Wheatley and Azar Nejad et al. They determined the oil potential distribution influenced by water cone with a remarkable accuracy. For horizontal wells, two methods, Joshi???s equation and Rechem et al formula, are considered to be the most reliable. Joshi???s equation provides lower estimates than Chaperon???s correlation in which the water cone effect on oil potential was neglected. The Recham et al formula also gives a similar result. On the whole, the Rechem et al method is preferred.