Browsing by Subject "Hydrocarbon reservoirs--Mathematical models"
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Item A coupled wellbore/reservoir simulator to model multiphase flow and temperature distribution(2007-12) Pourafshary, Peyman, 1979-; Sepehrnoori, Kamy, 1951-; Podio, A. L.Hydrocarbon reserves are generally produced through wells drilled into reservoir pay zones. During production, gas liberation from the oil phase occurs due to pressure decline in the wellbore. Thus, we expect multiphase flow in some sections of the wellbore. As a multi-phase/multi-component gas-oil mixture flows from the reservoir to the surface, pressure, temperature, composition, and liquid holdup distributions are interrelated. Modeling these multiphase flow parameters is important to design production strategies such as artificial lift procedures. A wellbore fluid flow model can also be used for pressure transient test analysis and interpretation. Considering heat exchange in the wellbore is important to compute fluid flow parameters accurately. Modeling multiphase fluid flow in the wellbore becomes more complicated due to heat transfer between the wellbore fluids and the surrounding formations. Due to mass, momentum, and energy exchange between the wellbore and the reservoir, the wellbore model should be coupled with a numerical reservoir model to simulate fluid flow accurately. This model should be non-isothermal to consider the effect of temperature. Our research shows that, in some cases, ignoring compositional effects may lead to errors in pressure profile prediction for the wellbore. Nearly all multiphase wellbore simulations are currently performed using the "black oil" approach. The primary objective of this study was to develop a non-isothermal wellbore simulator to model transient fluid flow and temperature and couple the model to a reservoir simulator called General Purpose Adaptive Simulator (GPAS). The coupled wellbore/reservoir simulator can be applied to steady state problems, such as production from, or injection to a reservoir as well as during transient phenomena such as well tests to accurately model wellbore effects. Fluid flow in the wellbore may be modeled either using the blackoil approach or the compositional approach, as required by the complexity of the fluids. The simulation results of the new model were compared with field data for pressure gradients and temperature distribution obtained from wireline conveyed pressure recorder and acoustic fluid level measurements for a gas/oil producer well during a buildup test. The model results are in good agreement with the field data. Our simulator gave us further insights into the wellbore dynamics that occur during transient problems such as phase segregation and counter-current multiphase flow. We show that neglecting these multiphase flow dynamics would lead to unreliable results in well testing analysis.Item A field study to assess the value of 3D post-stack seismic data in forecasting fluid production from a deepwater Gulf-of-Mexico reservoir(2005) Gambús Ordaz, Maika Karen; Torres-Verdín, CarlosThis dissertation describes a study undertaken to appraise the reliability of spatially complex hydrocarbon reservoir models constructed with the use of 3D post-stack seismic amplitude data and well logs. Developments center about the interpretation of data acquired in an active hydrocarbon field in the deepwater Gulf of Mexico. The availability of measured time records of fluid production and pressure depletion provides an independent way to quantify the accuracy and reliability of several methods commonly employed to construct static reservoir models. We make use of geostatistical inversion to construct spatial distributions of porosity and permeability that simultaneously honor well logs and 3D poststack seismic amplitude data. The constructed reservoir models are compared against models constructed with standard geostatistical procedures that do not make use of seismic amplitude data or else that use a simple statistical correlation between reservoir properties and seismic - inverted acoustic impedances. We perform multi-phase fluid-flow simulations to assess the consistency of the constructed reservoir models against the measured time record of flow rates of gas/water and shut-in well pressures. For the hydrocarbon field under consideration, the joint stochastic inversion of well logs and 3D post-stack seismic amplitude data consistently yields the closest match to dynamic measurements of fluid production and pressure depletion. Our study also compares the influence of petrophysical and rock-fluid parameters on the reliability and accuracy of the predicted fluid production against the influence of spatial variability of porosity and permeability.