Gas hydrate research in the last two decades has taken various directions ranging from ways to understand the safe and economical production of this enormous resource to drilling problems. as more rigs and production platforms move into deeper waters to its environmental impact on global warming and cooling. Gas hydrates are ice-like structures of a water lattice with cavities, which contain guest gases. Gas hydrates are stable at low temperatures and high pressures. The amount of energy trapped in gas hydrates all over the world is about twice the amount found in all recoverable fossil fuels today. This research identifies the problems facing the oil and gas industry as it drills in deeper waters where gas hydrates are present and suggests solutions to some of the problems. The problems considered in this research have been approached from a drilling point of view. Hence, the parameters investigated and discussed are drilling controlled parameters. They include rate of penetration, circulation rate and drilling fluid density. The rate of penetration in offshore wells contributes largely to the final cost of the drilling process. These 3 parameters have been linked in the course of this research in order to suggest an optimum rate of penetration. The results show the rate of penetration is directly proportional to the amount of gas released when drilling through gas hydrate. As the volume of gas released increases, the problems facing the drilling rigs, drilling crew and environment is seen to increase. The results also show the extent of risk to be expected while drilling through gas hydrate formations. A chart relating the rate of penetration, circulation rate and effective mud weight was used to select the optimum drilling rate within the drilling safety window. Finally, future considerations and recommendations in order to improve the analyses presented in this work are presented. Other drilling parameters proposed for future analysis include drill bit analysis with respect to heat transfer and the impact of dissociation of gas hydrate around the wellbore and seafloor stability.

published_or_final_version / abstract / Civil Engineering / Doctoral / Doctor of Philosophy

Thesis (Ph. D.)--University of Hong Kong, 2002. / Includes bibliographical references (leaves 117-120).

published_or_final_version / Civil Engineering / Doctoral / Doctor of Philosophy

This study presents a simplified and accurate procedure for selecting the rheological model which best fits the rheological properties of a given non- Newtonian fluid and introduces five new approaches to correct for tool joint losses from expansion and contraction when hydraulics is calculated. The new approaches are enlargement and contraction (E&C), equivalent diameter (ED), two different (2IDs), enlargement and contraction plus equivalent diameter (E&C+ED), and enlargement and contraction plus two different IDs (E&C+2IDs). In addition to the Newtonian model, seven major non-Newtonian rheological models (Bingham plastic, Power law, API, Herschel-Bulkley, Unified, Robertson and Stiff, and Casson) provide alternatives for selecting the model that most accurately represents the shear-stress/shear-rate relationship for a given non- Newtonian fluid. The project assumes that the model which gives the lowest absolute average percent error (EAAP) between the measured and calculated shear stresses is the best one for a given non-Newtonian fluid. The results are of great importance in achieving correct results for pressure drop and hydraulics calculations and the results are that the API rheological model (RP 13D) provides, in general, the best prediction of rheological behavior for the mud samples considered (EAAP=1.51), followed by the Herschel-Bulkley, Robertson and Stiff, and Unified models. Results also show that corrections with E&C+2IDs and API hydraulics calculation give a good approximation to measured pump pressure with 9% of difference between measured and calculated data.

Wireline formation testers (WFT) are widely used to measure fluid pressure, to perform downhole fluid analysis in real-time, and for estimating permeability through pressure transient testing. Formation testers can measure a range of fluid properties such as color, viscosity, density, composition, pH, optical refractive index, pressure, salinity, fractional flow, and gas-oil ratio (GOR). However, WFT measurements are influenced by the process of mud-filtrate invasion because overbalanced drilling promotes radial displacement of in-situ fluids by mud filtrate. Oil-base mud (OBM) is first-contact miscible with native oil and can lead to contaminated fluid samples, erroneous estimates of petrophysical properties, and changes of composition, viscosity, compressibility, GOR, and fluid density. The objective of this dissertation is three-fold: (1) to quantify the effect of OBMfiltrate invasion on WFT measurements, (2) to estimate in-situ petrophysical properties concomitantly from transient measurements of pressure, flow rate and GOR acquired with formation testers, and (3) to quantify petrophysical, geometrical, and fluid properties that can minimize the time of withdrawal of uncontaminated fluid samples. In order to quantify the effect OBM-filtrate invasion on WFT measurements, we develop a two-dimensional axial-symmetric compositional simulator and subsequently use a commercial adaptive-implicit compositional simulator, CMG-GEM1. History matching of three field data sets acquired with probe-type formation testers in light-oil formations accurately reproduces measurements of sandface pressure, observation-probe pressure, GOR, and flow rate. Further, we demonstrate that history matching enables the detection and diagnosis of adverse data-acquisition conditions such as plugging, noisy data, and presence of OBM-filtrate invasion. We introduce a dimensionless fluid contamination function that relates GOR to fluid-sample quality. Sensitivity analysis of simulated fluid-sample quality to petrophysical properties clearly indicates that sample quality improves in the presence of anisotropy and impermeable shale boundaries. A computationally efficient dual-grid inversion algorithm is developed and tested on both synthetic and field data sets to estimate in-situ petrophysical properties from WFT measurements. These tests confirm the reliability and accuracy of the inversion technique. Results indicate that permeability estimates can be biased by noisy measurements as well as by uncertainty in flow rate, relative permeability, radial invasion length, formation damage, and location of bed boundaries. To quantify petrophysical and geometrical factors that can optimize the time of withdrawal of uncontaminated fluid samples, we compare the performance of focused and conventional probe-type WFT in the presence of mud-filtrate invasion. Simulations indicate a significant reduction in fluid-cleanup time when using a focused probe. The specific amount of improvement depends on probe geometry, fluid composition, and petrophysical properties of the probed formation. Finally, we develop an inversion method to estimate Brooks-Corey parametric saturation-dependent functions jointly from transient measurements of fractional flow and probe pressure. Results show that estimating Brooks-Corey parameters can be nonunique if the a-priori information about fluid and petrophysical properties is uncertain. However, we show that focused fluid sampling consistently improves both the accuracy and reliability of the estimated relative permeability and capillary pressure parametric functions with respect to estimates obtained with conventional-probe measurements. / text

Zugl.: Bielefeld, Univ., Diss., 2006 u.d.T.: Disselkamp, Christine: Drillingsstudie zur Entwicklung der Geschwistergruppen im Vorschul- und Schulalter

Thesis (Ph. D.)--University of Hong Kong, 2009. / Includes bibliographical references (p. 321-330) Also available in print.

Thesis (Ph. D.)--University of Texas at Austin, 2008. / Vita. Includes bibliographical references.

Thesis (M.S.)--University of Wisconsin--Madison, 1964. / eContent provider-neutral record in process. Description based on print version record. Bibliography: 2 l. at end.