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One role of the petrophysicist is to characterize the fluids encountered in the reservoir. Detection of a change in fluid type in the rocks while drilling is usually straightforward with the use of gas and chromatographic measurements. Gas shows and oil shows while drilling are time-honored indicators of zones that need further investigation through logs, testers, and cores. In the rare case of gas-bearing, high-permeability rock drilled with high overbalance, gas will be flushed from the rock ahead of the bit, will not be circulated to the surface in the mud, and will not produce a gas show. Because hydrocarbons are not always part of a water-based-mud formulation, sophisticated analytical chemical techniques can be used on the oil and gas samples circulated to the surface and captured to determine the properties of hydrocarbons in a given zone penetrated by the drill bit.
Acoustic logs provide the primary means for evaluating the mechanical integrity and quality of the cement bond. Acoustic logs do not measure cement quality directly, rather, this value is inferred from the degree of acoustic coupling of the cement to the casing and to the formation. Properly run and interpreted, cement-bond logs (CBL) provide highly reliable estimates of well integrity and zone isolation. Just as filtrate invasion and formation alteration may produce changes in formation acoustic properties, and thus variation in acoustic logs over time, so too, cement-bond logs may vary over time as the cement cures and its properties change. Modern acoustic cement-evaluation (bond) devices are comprised of monopole (axisymmetric) transmitters (one or more) and receivers (two or more). They operate on the principle that acoustic amplitude is rapidly attenuated in good cement bond but not in partial bond or free pipe. Conventional CBL tools provide omnidirectional measurements, while the newer radial cement-evaluation tools provide azimuthally sensitive measurements for channel evaluation. Tool response depends on the acoustic impedance of the cement, which, in turn is function of density and velocity.
In contrast to monopole logging tools, dipole acoustic devices can excite a low-frequency flexural wave in the borehole at shear velocity. Low-frequency ( 1 kHz) dipole sources allow for shear-velocity determination that is much closer to seismic shear waves and permits acquisition of direct-shear velocities in slow and fast formations. However, increased noise (i.e., a lower signal-to-noise ratio) is one limitation of low-frequency operation. Noise has been reduced through improved acquisition electronics, the use of semi-rigid tool designs, and by choosing the operational mode of the dipole source. A semi-rigid tool body not only reduces the influence of the tool body on the measurement but also permits operation in deviated wells.
Stoneley-wave velocity and attenuation are sensitive to formation and fracture permeability, particularly at low frequencies. Initial efforts (begun in the 1970s) to derive permeability information from Stoneley data were unsuccessful because neither the necessary low-frequency tools nor the appropriate processing methods had been developed. The parallel development of modern multipole array tools and sophisticated semblance- and inversion-processing methods enable computation of continuous profiles of formation permeability from monopole Stoneley-wave data. Typically, these methods first model the nonpermeability effects using the elastic-wave theory and then relate differences between the modeled and the measured data to formation permeability. Both traces have been shown to correlate well with permeability changes and compare well with core data, when it is available.
Locating fractures, recognizing fracture morphology, and identifying fluid-flow properties in the fracture system are important criteria in characterizing reservoirs that produce predominantly from fracture systems. Acoustic techniques can provide insight. Fracture identification and evaluation using conventional resistivity and compressional-wave acoustic logs is difficult, in part because fracture recognition is very dependent on the dip angle of fractures with respect to the borehole. Fractures are physical discontinuities that generate acoustic reflection, refraction, and mode conversion--all of which contribute to a loss of transmitted acoustic energy. In particular, compressional- and shear-wave amplitude and attenuation and Stoneley-wave attenuation are significantly affected by the presence of fractures.
These methods use the crossed-dipole shear to derive azimuthal anisotropy and the Stoneley wave to derive TI anisotropy in slow formations, or a combination of these modes in deviated wells. A reasonable shear velocity can be derived using inversion techniques with low-frequency Stoneley-wave dispersion which is sensitive to the horizontal shear (in contrast to the dipole's sensitivity to the vertical shear).
The pdf file of this paper is in Russian. To purchase the paper in English, order SPE-117423-MS.
While FMI-logged wells are quite scarce at the field under investigation, the standard log complex is normally present in all the wells. This paper tackles the task of retrieving vuggy-fractured porosity using standard log data with the end of further transferring the synthetic vuggy-fractured porosity (VFP) data across all the field's wells having standard log data.
Zhang, Zhiyi (Shell International E &P Inc ) | Akinsanmi, Olumide (Shell ) | Ha, Kwong Tak (Shell ) | Bourgeois, Timothy (Shell Exploration & Production Company ) | Jock, Shannon (Shell Exploration & Production Company ) | Blumhagen, Conrad (Shell Petroleum Development ) | Stromberg, Simon (Shell Petroleum Development )
The fact that triaxial/multi-component induction logging tools can detect different components of the induced magnetic fields has resulted in several important applications. The first application is the detection of resistivity anisotropy of the formation, which may lead to a better quantification of hydrocarbon in place and hydrocarbon recovery. This capability is important, for instance, in evaluating thinly laminated sand-shale sequences encountered in deepwater turbidites. Another important application of these new tools is formation dip and azimuth angle detection. Pad based dip meter tools have higher vertical resolution but much shallower depths of investigation. Thus dipmeter data are sensitive to near hole variations such as borehole rugosity and eccentricity. On the other hand, triaxial induction logging tools have deeper depths of investigation, and are thus less affected by near borehole variations such as rugosity. This is especially important in wells where image logs are either unavailable or unreliable. Careful analysis of the structural formation dip and azimuth angle information derived from triaxial induction logging tools together with dip-meter data may provide a better understanding of the subsurface architecture. Because of their ability to determine directionality, triaxial induction logging tools may also provide vital information about fracture orientation and lengths. Effort is being made to retrieve fracture information from these new induction logging data.
In this paper we first examine the similarities and differences on the hardware design, processing software, and field procedures of the two commercially available triaxial induction tools. We will also offer our perspective as an operator about triaxial induction logging tools and share the learnings from our operating units. We will specifically describe an offshore case study where we have run both types of tools back to back. We examine the performance of these two tools compare the field and processed results, and make recommendations and suggestions as how to best utilize these tools.
The first patent about the concept of triaxial induction logging tool was from Shell (Hungerford and Fay, 1957). It was filed as a dipmeter rather than an induction logging tool. Moran and Gianzero (1979) then published a paper on Geophysics to explore the theoretical aspect of triaxial induction logging. They found that the bottleneck for the triaxial tool to become a practical and useful tool would be the severe borehole effects on the transverse transmitters and receivers. A group of Shell researchers has proposed an idea for better saturation determination in thinly laminated sandshale reservoirs using triaxial induction logging data (de Waal et al., 1992). In 1993, Shell had teamed up with Baker Atlas to develop the first generation of multi-component induction logging tools. The tool was field tested in 1998 and now is officially named as 3DEXA. Initially, the 3DEX tool only output 5 components of the measured magnetic field (Kriegshauser et al. 2000). In 2004, the tool has been upgraded to output all 9 components of the magnetic tensor field. Schlumberger started their own triaxial induction logging program around the beginning of the century, and has developed a full tensor field triaxial array induction logging tool (Rosthal et al. 2003, Barber et al., 2004).
Porosity from Compressional wave slowness can be estimated using the known Wyllie Time average equation: DTC = Ø DTCfluid + (1 - Ø )DTCmatrix. Similar equations have been proposed for Shear wave slowness but they are not widely accepted. Theoretically, el