Browsing by Subject "Oil well drilling"
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Item Chemical and thermal effects on wellbore stability of shale formations(2002) Yu, Mengjiao; Chenevert, Martin E.; Sharma, Mukul M.A new three-dimensional wellbore stability model is presented that takes into account thermal stresses and the flux of both water and solutes from drilling fluids (muds) into and out of shale formations. Mechanical stresses around a wellbore placed at any arbitrary orientation in a 3-dimensional stress field are coupled with changes in temperature and pore pressure due to water and solute fluxes. The radial and azimuthal variation in the stress distribution and the “failure index” are computed to check for wellbore failure. This model accounts for the hindered diffusion of solutes as well as the osmotically driven flow of water into the shale. The model for the first time allows a user to study the role of solute properties on wellbore stability. Results from the model show that a maximum or minimum in pore pressure can be obtained within a shale. This leads to wellbore failure not always at the wellbore wall as is most commonly assumed but to failure at some distance inside the shale. Since the fluxes of water and solute, and temperature, are time dependent, a clearly time dependent wellbore failure is observed. The time to wellbore failure is shown to be related to the rate of solute and water invasion. Comparisons with experiments conducted with a variety of solutes on different shales show excellent agreement with model results. It is shown in this study that the solutes present in the mud play an important role in determining not only the water activity but also in controlling the alteration of pore pressures in shales. To account for this phenomenon a model is presented to compute the flux of both water and solutes into or out of shales. The relative magnitudes of these fluxes control the changes in pore pressure in the shale when it is exposed to the mud. The effect of the molecular size of the solute, the permeability of the shale and its membrane efficiency are some of the key parameters that are shown to determine the magnitude of the osmotic contribution to pore pressure. A range of behavior is observed if the solute is changed while the water activity is maintained constant. This clearly indicates the importance of the solute flux in controlling the pore pressure in shales. Critical mud weights are obtained by inspecting the stability of the wellbore wall and the entire near wellbore region. Pore pressures at different time and position are investigated and presented to explain the model results. It is shown in this study that the critical mud weights are strongly time dependent. The effects of permeability, membrane efficiency of shale, solute diffusion coefficient, mud activity and temperature changes are presented in this work. The collapse and fracture effects of cooling and heating the formations are also presented. A powerful simulation tool has been developed which can be used to perform thorough investigations of the wellbore stability problem. A user-friendly interface has been developed to ease usage.Item Cleanup of internal filter cake during flowback(2005) Suri, Ajay; Sharma, Mukul M.The flow initiation pressure (FIP) is used as an estimate of the differential pressure (between the reservoir and the well) required to initiate production. The standard practice to measure FIP uses a constant flowback rate. This method is shown to be inadequate to measure the FIP. An improved flowback method, which uses a series of constant differential pressures, is used instead to measure the FIP. This method closely represents the constant drawdown experienced between the reservoir and the wellbore. In addition the permeability during flowback is measured at increasing differential pressures, resulting in a spectrum of return permeability values. Two types of drilling fluids (sized calcium carbonate and bentonite) are used for conducting the filtration and flowback experiments for porous media ranging in permeability from 4 to 1500 md. Both single-phase and two-phase experiments are conducted in lab-simulated open-hole and perforated completions to better understand the factors affecting the FIP and the return permeability spectra. vii We observe small values for FIP in all the experiments (considerably smaller than those measured using the constant flowback method). The values of FIP yield pressure gradients that are achievable in vertical wells but may not be easily achieved in horizontal wells. The FIP and the return permeability spectra are controlled by the cleanup of the internal filter cake. A Bingham fluid in a network of pores is used to model the cleanup of the internal filter cake during flowback. The results indicate that very large pressure gradients are required during flowback to cleanup the entire internal filter cake. However, a pressure gradient of 10 psi / inch is found to yield a skin factor < 1 for most open-hole completions. For perforated completions, pressure gradients up to 20 psi / inch and flow rates up to 0.3 bbl/day/perf yield skin factors < 2.Item Developing a Vaca Muerta shale play : an economic assessment approach(2016-05) Sierra, Diego Ernesto; Ikonnikova, Svetlana; Fisher, W. L. (William Lawrence), 1932-A total of 450 production wells are in operation in Argentina’s Vaca Muerta shale formation as of February 2016, of which 90% were drilled since 2013. In order to assess the economic value of the vertical, directional, and horizontal wells and understand the potential future shale play development, a data-driven approach is developed. First, historical production data are used to derive a 10-year production forecast, using decline curve analysis. Then, well profitability is assessed applying a discounted cash flow model for a sample of vertical, directional, and horizontal wells in the Loma Campana field. Initial oil and gas production rates reached 172.56 BBL/day and 309.42 Mcf/day for the median vertical well, 392.81 BBL/day and 587.76 Mcf/day for the median directional well, and 456.75 BBL/day and 571.46 Mcf/day for the median horizontal well. Based on the production histories, 10-year cumulative oil and gas production is expected to reach 76,389 BBL and 97,772 Mcf for the median vertical well, 174,701 BBL and 261,402 Mcf for the median directional well, and 203,134 BBL and 254,154 Mcf for the median horizontal well. The median vertical well is found to have a negative net present value (NPV) for any possible discount rate, while median directional and horizontal wells can be expected to give NPV (10%) values of $0.41 and $1.14 million, respectively, under the current fiscal and contractual conditions in the country. Internal rates of return for the median directional and horizontal wells were found to be 15.15% and 26%, respectively, while their break-even oil prices at a 10% discount rate were found to be $54.65 and $47.23 per BBL, respectively. Thus, the production profiles and well economics assessment allows to suggest that directional and horizontal wells could be economically viable under the country’s current economic environment, including oil and gas price subsidies.Item Simulation and interpretation of formation-tester measurements acquired in the presence of mud-filtrate invasion, multiphase flow, and deviated wellbores(2009-05) Angeles Boza, Renzo Moisés, 1978-; Torres-Verdín, CarlosThis 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.