Influencia de la permeabilidad vertical en el flujo de petróleo hacia un pozo productor

Se describe el flujo bidimensional de petróleo a través de un reservorio heterogéneo mediante una ecuación parabólica en derivadas parciales, que es una extensión de la denominada ecuación de difusividad. Este modelo tiene interés práctico en ingeniería de reservorios: se utiliza para predecir la producción de un pozo de petróleo y también en la interpretación de ensayos de presión en pozos. La solución numérica de dicha ecuación se obtiene mediante una familia de esquemas de diferencias finitas que dependen de un parámetro 8, O 5 8 5 1. Una técnica basada en la expansión en serie de Taylor de funciones matriciales (TSMF) es usada para resolver el sistema de ecuaciones lineales resultante. El simulador numérico descrito se aplica para estudiar el comportamiento de reservorios de dos capas con valores típicos de permeabilidad vertical iguales o menores que los de permeabilidad horizontal. Específicamente, para un pozo de petróleo que produce a caudal constante, se analiza la influencia de la permeabilidad vertical en las respuestas de presión y caudal de cada capa. Se concluye que la permeabilidad vertical influye en las respuestas de presión y caudal a tiempos cortos e intermedios, por lo que debería ser tenida en cuenta tanto en el diseño como en la interpretación de los ensayos de presión en pozos.Peer Reviewe

A Comprehensive Statistically-Based Method to Interpret Real-Time Flowing Measurements

With the recent development of temperature measurement systems, continuous temperature profiles can be obtained with high precision. Small temperature changes can be detected by modern temperature measuring instruments such as fiber optic distributed temperature sensor (DTS) in intelligent completions and will potentially aid the diagnosis of downhole flow conditions. In vertical wells, since elevational geothermal changes make the wellbore temperature sensitive to the amount and the type of fluids produced, temperature logs can be used successfully to diagnose the downhole flow conditions. However, geothermal temperature changes along the wellbore being small for horizontal wells, interpretations of a temperature log become difficult. The primary temperature differences for each phase (oil, water, and gas) are caused by frictional effects. Therefore, in developing a thermal model for horizontal wellbore, subtle temperature changes must be accounted for. In this project, we have rigorously derived governing equations for a producing horizontal wellbore and developed a prediction model of the temperature and pressure by coupling the wellbore and reservoir equations. Also, we applied Ramey's model (1962) to the build section and used an energy balance to infer the temperature profile at the junction. The multilateral wellbore temperature model was applied to a wide range of cases at varying fluid thermal properties, absolute values of temperature and pressure, geothermal gradients, flow rates from each lateral, and the trajectories of each build section. With the prediction models developed, we present inversion studies of synthetic and field examples. These results are essential to identify water or gas entry, to guide flow control devices in intelligent completions, and to decide if reservoir stimulation is needed in particular horizontal sections. This study will complete and validate these inversion studies

Using Microstructure Observations to Quantify Fracture Properties and Improve Reservoir Simulations

The research for this project, funded by the U.S. Department of Energy, provides new technology to understand and successfully characterize, predict, and simulate reservoir-scale fractures. Such fractures have worldwide importance because of their influence on successful extraction of resources. For example, many conventional U.S. reservoirs yield about one-third of the oil originally in place, but some estimates suggest that reservoirs with naturally occurring fractures yield only about 10 percent of their reserves. This is a serious technical and financial challenge for producers of reservoirs containing natural fractures. Most fractures are below the limits of seismic resolution or detection and are difficult or impossible to characterize adequately using currently available well test, full-diameter core, or geophysical well log technology; this is because large fractures are intrinsically difficult to sample with conventional wellbore sampling methods owing to their wide spacing. Consequently, fractured reservoirs have been intractable to describe and interpret effectively, impeding accurate reservoir description and simulation. Accurate characterization of reservoir fractures, however, still holds great potential for improving production by increasing the efficiency of exploration and recovery processes.Bureau of Economic Geolog

Interwell Connectivity and Diagnosis Using Correlation of Production and Injection Rate Data in Hydrocarbon Production

This report details progress and results on inferring interwell communication from well rate fluctuations. Starting with the procedure of Albertoni and Lake (2003) as a foundation, the goal of the project was to develop further procedures to infer reservoir properties through weights derived from correlations between injection and production rates. A modified method, described in Yousef and others (2006a,b), and herein referred to as the 'capacitance model', is the primary product of this research project. The capacitance model (CM) produces two quantities, {lambda} and {tau}, for each injector-producer well pair. For the CM, we have focused on the following items: (1) Methods to estimate {lambda} and {tau} from simulated and field well rates. The original method uses both non-linear and linear regression and lacks the ability to include constraints on {lambda} and {tau}. The revised method uses only non-linear regression, permitting constraints to be included as well as accelerating the solution so that problems with large numbers of wells are more tractable. (2) Approaches to integrate {lambda} and {tau} to improve connectivity evaluations. Interpretations have been developed using Lorenz-style and log-log plots to assess heterogeneity. Testing shows the interpretations can identify whether interwell connectivity is controlled by flow through fractures, high-permeability layers, or due to partial completion of wells. Applications to the South Wasson and North Buck Draw Fields show promising results. (3) Optimization of waterflood injection rates using the CM and a power law relationship for watercut to maximize economic return. Tests using simulated data and a range of oil prices show the approach is working. (4) Investigation of methods to increase the robustness of {lambda} and {tau} estimates. Human interventions, such as workovers, also cause rate fluctuations and can be misinterpreted by the model if bottom hole pressure data are not available. A revised method, called the 'segmented capacitance model', identifies times when production changes might not be caused strictly by water injection changes. Application to data from Monument Butte Field shows encouraging results. Our results show the CM and its modified forms can be an important tool for waterflood management. We have moved beyond the proof of principle stage to show it can actually be applied to assess connectivity in field situations. Several shortcomings, however, remain to be addressed before the CM can be routinely applied by field operators. The CM and its modifications analyze well rates in the time domain. We also explored the assessment of interwell connectivity in the spectral domain. We applied conventional methods, based on analyzing passive linear electrical networks, to the analysis of injection and production data. In particular, we assessed the effects of near-wellbore gas on the apparent connectivity. With only oil and water in the system, the results were as expected, giving good connectivity estimates. In the presence of gas, however, the methods could not produce useful estimates of connectivity

Domestic elites and external actors in post-conflict democratisation: mapping interactions and their impact

Following the end of the Cold War, post-conflict democratisation has rarely occurred without a significant international involvement. This contribution argues that an explanation of the outcomes of post-conflict democratisation requires more than an examination of external actors, their mission mandates or their capabilities and deficiencies. In addition, there is a need to study domestic elites, their preferences and motivations, as well as their perceptions of and their reactions to external interference. Moreover, the patterns of external–internal interactions may explain the trajectory of state-building and democracy promotion efforts. These issues deserve more attention from both scholars and practitioners in the fields of peace- and state-building, democracy promotion, regime transition and elite research. Analyses of external actors and domestic elites in post-conflict democratisation should therefore address three principal issues: (1) the identification of relevant domestic elites in externally induced or monitored state-building and democratisation processes, (2) the dynamics of external–domestic interactions and (3) the impact of these interactions on the outcomes of post-conflict democratisation