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Fluid capacitance logging is used to distinguish the mix of water and hydrocarbons in the wellbore fluid. The fluid-capacitance-logging tool includes an inside dielectric probe located on the tool's axis. The probe is surrounded by an outside housing that is open to the wellbore fluid. Together, the probe, the housing, and the fluid constitute an electrical capacitor, the capacitance level of which depends on the particular fluid, or fluids, within the capacitor. Circuitry within the tool is connected to the electrical capacitor, with the result that the circuitry generates an oscillating signal that varies inversely with the capacitance level.
The following sections describe operating principles for each of the tools listed in Table 4.1. The text will indicate applications for which a tool is best suited, those for which it is only partially suited and, when possible, those for which a tool is not suitable. Some interpretive principles and recommended logging procedures will be presented in examples. However, the reader should refer to the Appendix for detailed information of this type. Oxygen-activation, cement-bond, and casing-inspection tools are not treated. These tools are, however, included in the application tables of the Appendix.
This paper focuses on simulation modeling of a gas injection pilot operated in the Eagle Ford Shale play. The main objective of this case study is to understand the flow mechanisms in the reservoir due to hydraulic fracturing of multiple wells and gas injection operations.
A dual porosity numerical reservoir simulation model coupled with geo-mechanics was built to investigate the hydraulic fracturing and flow dynamics of the pilot area using a sophisticated numerical reservoir simulator. The methodology used in this study integrates the hydraulic fracturing process, multi-phase flow and geo-mechanics within the reservoir simulation. In this approach, the change in mean stress for each grid block is implicitly solved together with pressure and the other flow variables using poro-elastic information. Geologic, geo-mechanical and reservoir properties were gathered from the static geo-model. The actual stage-by-stage hydraulic fracture treatment jobs were simulated to investigate the stimulated rock volume (SRV) characteristics of the study wells. The simulation model was calibrated to match the hydraulic fracturing, flow back, depletion and multiple huff and puff cycles. Oil, water and gas production/injection data together with pressure data were matched during calibration. Additional sensitivity runs were performed to examine the potential benefits of gas injection under different operational scenarios.
The results show that the Eagle Ford pilot area is quiet in terms of natural fractures. There is an indication of weak zones that provide preferential connectivity paths for water and gas flow. These weakness points could be related to the lithology or natural fractures. They were defined as easily breakable planar zones in the model. The most important knowledge gained from the calibration of the gas injection period is the establishment of connectivity paths and their poro-elastic behavior during gas injection. The results showed that oil swelling and vaporization of oil into gas are the two mechanisms that impact the huff-n-puff performance. Maintaining most of the injected gas around the huff-n-puff pattern also improves the performance.
In most exploration and reservoir seismic surveys, the main objectives are, first, to correctly image the structure in time and depth and, second, to correctly characterize the amplitudes of the reflections. Assuming that the amplitudes are accurately rendered, a host of additional features can be derived and used in interpretation. Collectively, these features are referred to as seismic attributes. The simplest attribute, and the one most widely used, is seismic amplitude, and it is usually reported as the maximum (positive or negative) amplitude value at each sample along a horizon picked from a 3D volume. It is fortunate that, in many cases, the amplitude of reflection corresponds directly to the porosity or to the saturation of the underlying formation.
In some reservoir applications, seismic data are acquired with downhole sources and receivers. If the receiver is stationed at various depth levels in a well and the source remains on the surface, the measurement is called vertical seismic profiling (VSP). This technique produces a high-resolution, 2D image that begins at the receiver well and extends a short distance (a few tens of meters or a few hundred meters, depending on the source offset distance) toward the source station. This image, a 2D profile restricted to the vertical plane passing through the source and receiver coordinates, is useful in tying seismic responses to subsurface geologic and engineering control. If the source is deployed at various depth levels in one well and the receiver is placed at several depth stations in a second well, the measurement is called crosswell seismic profiling (CSP). Images made from CSP data have the best spatial resolution of any seismic measurement used in reservoir characterization because a wide range of frequencies is recorded.
In the same way that laboratory measurements require representative samples to be meaningful, reservoir fluid samples themselves must be supported by accurate data to provide a unique identification and to record all important production and sampling parameters that will be used in checking the sample and (in many cases) in determining the exact measurements that will be performed. This article reviews the importance of data measurement and provides guidelines for recording and validating the necessary data. Provided that flowmeters and pressure gauges are properly sized for a measurement, so that readings are not made at the low end of the measurement range, random errors are generally small. Although systematic errors are comparatively rare, their magnitude can be significant. In fact, on some occasions, errors are identified only when measured values are so large that the values become ridiculous.
Introduction Reservoir geophysics, in contrast to exploration and development geophysics, is a relatively new field. Rather than being limited to assisting in the identification and delineation of prospects, geophysics is now increasingly being used for the characterization of the internal geometry and quality of reservoirs themselves and is often used as a means of monitoring reservoir changes between wells during production. Advances in the reliability of seismic observations and in methods for interpreting these observations in terms of reservoir properties have, together with economic considerations, provided the driving forces for the development of reservoir geophysics. The chapter on Fundamentals of Geophysics in the Reservoir Engineering and Petrophysics section of this Handbook addresses the concepts used in seismic studies and is a useful introduction to the general topic. This chapter expands on the applications of geophysical technologies to reservoir characterization and monitoring for improved production. There are several specific differences between exploration geophysics and reservoir geophysics, as the term is usually intended. The differences include: the assumption that well control is available within the area of the geophysical survey; a carefully designed geophysical survey can be conducted at a level of detail that will be useful; some understanding of the rock physics is available for interpretation; 3D seismic (or other geophysical) data can be collected; and geostatistical techniques can be applied to it. The reservoir geophysicist should be familiar with the usefulness and limitations of petrophysical and reservoir-engineering studies and should be able to ask intelligent questions of the experts in those fields. However, the reservoir geophysicist typically is not an expert in those areas and works with the appropriate specialists to interpret the data or to design a new experiment to solve reservoir problems.
Drilling engineers require estimates of the fluid pressures that they are likely to encounter in any given well to anticipate mud weights required to maintain optimal drilling rates and safety. Because seismic velocities correlate with effective pressure in the formation, sufficiently precise estimates of velocity obtained from seismic observations can be used to determine pore pressure. In the absence of dense well control, interval velocities derived from stacking velocities are used to estimate pore pressure. These interval velocities are compared with a general trend of velocities in the region (Figure 1), and a pore pressure volume is developed for use by drilling engineers, as shown in Figure 1. Acoustic impedance volumes obtained from seismic trace inversion can also be used to identify and detect anomalous pore pressure regions.
Metrology is the science and process of ensuring that a measurement meets specified degrees of accuracy and precision. Bottomhole pressure-gauge and temperature-gauge performance depends on the static and dynamic metrological parameters described here. The pressure measurement equipment consists of the pressure transducer, associated electronics, and telemetry. Each component uniquely influences the measurement quality. Accuracy is the maximum pressure error exhibited by the pressure transducer under the following applied conditions: fitting error, pressure hysteresis, and repeatability.