In some complex reservoirs, low-resistivity/low-contrast pay, low-porosity/low-permeability, and medium-to-heavy oil, nuclear magnetic resonance (NMR) log data--independently or in combination with other log data--provide the best and/or only means of accurate formation and fluid evaluation. Because NMR-log data acquisition is complex, job preplanning is essential to ensure optimal selection of acquisition parameters that will result in reliable and accurate data and in the maximum information possible in any given reservoir and logging environment. A clear understanding of the logging job objectives is necessary for optimizing the NMR acquisition parameters to best achieve these objectives. This process must take place before the actual logging. In addition to job objectives, determination of the appropriate NMR-acquisition parameters is also influenced by operational considerations and the anticipated in-situ reservoir properties (Fig.1).
Compared to laboratory or clinical nuclear magnetic resonance (NMR), the dimensions of a typical borehole and the nature of continuous logging impose severe constraints on the physics, equipment, and operation of NMR logging tools. The NML tool--the first generation of NMR logging (1960–1994)--was an Earth's field device that measured the free-induction decay in the Earth's magnetic field. Proton polarization (alignment) was achieved using a magnetic field produced by a coil energized with a strong direct current. Each experiment required several seconds to allow complete polarization. The power was turned off, and the same coil was used to receive the free-induction signal.
Figure 1E.1 – NMR logging-tool response compared to conventional logging tools. NMR porosity is independent of matrix minerals, and the total response is very sensitive to fluid properties. Differences in relaxation times and/or fluid diffusivity allow NMR data to be used to differentiate clay-bound water, capillary-bound water, movable water, gas, light oil, and viscous oils. NMR-log data also provide information concerning pore size, permeability, hydrocarbon properties, vugs, fractures, and grain size. Within a few years after the first successful observations of NMR in 1946, and the demonstration of free-precession NMR in the earth's magnetic field in 1948, the petroleum industry recognized the potential of NMR measurements for evaluating reservoir rocks, pore fluids, and fluid displacement (flow). In the early 1950s, several companies--particularly California Research (Chevron), Magnolia (Mobil), Texaco, Schlumberger, and Shell--began extensive investigations to understand the ...
Evaluating porosity is an important petrophysical task as part of formation evaluation. This article provides an overview of techniques used in determining porosity by nuclear magnetic resonance (NMR) logging techniques. The initial amplitude of the spin-echo train is proportional to the number of hydrogen nuclei associated with the fluids in the pores within the sensitive volume. This amplitude is calibrated in porosity units (see Eq.1). Porosity was one of the earliest NMR measurements and is still an important one.
Hydrocarbon typing and prediction of fluid properties by nuclear magnetic resonance (NMR) logs is predicated on reliable laboratory correlations between NMR measurements (i.e., relaxation times and diffusion) and fluid properties, for example: Early studies were limited to investigations at ambient conditions;  however, using the standard correlations derived from these studies may result in seriously underestimating viscosity. More-recent studies have expanded these correlations to oils and mud filtrates at reservoir conditions. The NMR T2-porosity relationship in which T2 is a function of pore size (i.e., S/V ratio, see Eq.1) holds for water-saturated rocks. Despite the variability in the NMR properties of fluids, the locations of signals from different types of fluids in the T2 distribution can often be predicted or, if measured data are available, identified (Figure 1). The position and spread of the oil component in the T2 distribution depends on oil viscosity and formation wettability.
The acquisition of bottomhole pressure and temperature data can be planned and executed in a cost-effective manner with a minimum disruption to normal operating routines. In many cases, early on-site interpretation is useful in guiding decisions about continuing the acquisition program. Measurements can be transmitted to the surface, usually via an electric cable, or recorded in downhole memory powered by batteries. SRO has the obvious advantage of providing data in real time. Real-time readouts are especially beneficial for transient measurements that require time for the pressure to stabilize and radial flow to develop.
Fiber-optic distributed acoustic sensing (DAS) offers advantages in time-lapse VSP seismic monitoring of an unconventional reservoir. Petrophysical changes to the reservoir due to hydraulic fracturing of the rocks change the character of seismic waves. Repeatable DAS VSP measurements within the stimulated zone can reveal the areas affected by the fracturing. The goal of this study is to assess how these changes affect DAS seismic data acquired before and after stimulation. One of the main advantages of DAS VSP seismic is that receivers cover the entire well including the deviated and horizontal sections. This provides not only velocity/image control in the overburden and target, but also high-resolution images within the frac zone from the horizontal receivers. Another advantage of DAS VSP, if the fiber is permanently installed behind casing, is that the receiver locations are fixed, allowing for high repeatability between surveys.
A fiber-optic cable was installed in a treatment well in the Meramec Shale covering the entire length of the well from surface to target depth, resulting in approximately 1000 recorded channels. The large number of channels, combined with the wide aperture, allowed us to record and locate seismic events from both vertical and horizontal portions of the well. Seismic processing consisted of time-lapse cross-equalization (XEQ) of data using receivers within the vertical portion of the well, where no changes are expected, as proxies to assess the validity of responses observed in the horizontal portion of the well. The XEQ data was then imaged with respect to the monitoring well in order to assess the changes to the reservoir. Complex arrivals within the deviated well were modeled in order to calibrate the wavefield separation prior to prestack Kirchhoff depth migration (PSKDM). The resulting amplitude anomalies in the vicinity of the fibered well have been analyzed in tandem with traditional DAS diagnostic measurements such as crosswell strain and microseismic.
The analysis of this DAS data set demonstrates that current fiber-optic technology can provide enough sensitivity to map seismic anomalies which we can integrate with temperature and strain data for an improved reservoir description. It further demonstrates the value of having DAS receivers within the stimulated zone as they provide in-situ information about the subsurface changes. The importance of the DAS measurements is that they reduce acquisition costs while providing additional monitoring tools from the same hardware.
Nuclear magnetic resonance (NMR) imaging has long been applied in the laboratory, and over the past few decades, downhole NMR tools have been developed. The latest entries into NMR logging are logging while drilling (LWD) tools. The development of LWD-NMR is ongoing and significant changes in hardware design, as well as significant changes and improvements in data acquisition and processing, can be expected in the next few years. The general benefits of LWD have been discussed elsewhere--in particular, NMR-LWD offers a nonradioactive alternative for porosity measurement, an NMR alternative to wireline in high-risk and high-cost wells, and enables high-resolution fluid analysis in thin beds and laminated reservoirs. By definition, logging tools operating in the drilling environment are built into drill collars and are, therefore, mandrel devices.
Geophysics is a broad subject that encompasses potential field theory (gravity and electromagnetic fields) and seismic technology. Potential field data are valuable in many studies, but seismic data are used in more reservoir characterization and reservoir management applications. Seismic data have been used for many years to guide exploration. More recently, seismic data have been used to support reservoir characterization in field development planning and subsequent reservoir management. As the technology in equipment and interpretation techniques has advanced, so has the ability to define the size, shape, fluid content, and variation of some petrophysical properties of reservoirs.