The feasibility of time-domain NMR curve-fitting methodology for the quantitative determination of TG blend phase compositions was investigated. By studying a range of TG in their different crystal forms, it was shown that the transverse NMR relaxation characteristics of TG differ for the respective crystal polymorphs {α,β,β′}. This enables the TG polymorphism in fat blends to be quantitatively determined by curve fitting. If a liquid phase is present in the blend, curve fitting is able to determine the solid fat content, and the results compare well with those of the accepted NMR methods. The curve-fit method is less hindered by some of the disadvantages of these accepted methods, such as the use of a calibration factor.Paper no. J10095 in JAOCS 79, 383-388 (April 2002).In food technology, the phase composition of fats and oils is an important parameter in process control (1), fat blending properties, and assessments of the quality of various products (2,3). Dilatometry, which is based on the difference in density between the solid and liquid phases, has for a long time been the dominant method to measure the solid fat index (SFI) (4), but this method is laborious and time consuming. Time-domain nuclear magnetic resonance (TD-NMR) has now become the dominant technique, as it offers many advantages regarding speed and ease of operation (2,5,6) and accurate information on the solid-liquid ratio (7,8).The current TD-NMR methods for SFC determination of fat blends have been successfully applied in fat technology for several decades. On one hand, the indirect method (2,7) is considered accurate but not precise, whereas, on the other hand, the "direct" method (2,5) is precise but not accurate and needs a calibration factor (derived from plastic-in-oil samples). In the hands of a skilled operator, the solid-echo (8) method is considered to be both accurate and precise but has never caught on in routine laboratories. Despite its obvious limitation, the direct method has become the most widespread method for SFC determination due to its ease of use and its high precision. However, since the introduction of this direct SFC method in the 1970s, the specifications of commercial TD-NMR equipment have improved dramatically. Also, there is a belief that the current methods do not fully exploit the potential of modern technology.In the detergent area, several applications have been described that show how the phase behavior of surfactants can be assessed by curve fitting of the time-domain data (9). So far, only a few examples are known where the phase behavior of lipids has been assessed (10,11). In recent reports (12,13), it was demonstrated that curve fitting of rapidly sampled transverse NMR relaxation decay curves enabled the quantitative determination of the mesomorphic state of polysaccharides. As the curve-fitting method is not fraught with some of the disadvantages of the current SFC NMR methods, we have embarked on a study to investigate the feasibility of curve fitting for quantification of MG and TG phase compositio...
The JAPEX/JNOC/GSC et al. Mallik 5L-38 gas hydrate research well was an integral part of a field experiment to test the physical response of a gas hydrate deposit to various advanced production methods. Iterative forward modelling of Cased Hole Formation Resistivity tool (CHFRTM) logs was used to determine the annular radius of gas hydrate dissociation that occurred around the wellbore during the thermal test in the Mallik 5L-38 well. Modelled results demonstrated that the radius of gas hydrate dissociation exhibited large local variations and was far from uniform. The comparison of the CHFR modelled results with the gas volumes measured at the surface indicate that most of the gas produced during the thermal test in the Mallik 5L-38 well was accurately measured at the surface. The CHFR modelling procedure shows promise for use in future single-well evaluation of gas hydrate dissociation.
The presence of fractures in reservoirs can have a large impact on short and long term production. Electrical imaging tools have a long history in the identification and quantification of fractures in boreholes drilled with water base muds. These tools are particularly sensitive to conductive fractures. The width (also known as aperture) of open fractures is calculated by a well-established equation, relating the fracture width to the excess current measured by the imaging tool (Luthi and Souhaité, 1990). Both mud resistivity and background resistivity of the formation need to be known or measured. The equation was derived from 3-D finite element modeling of the borehole imaging tools of the time. Recent work has revisited the fracture aperture calculations. The work has verified the approach for electrical imaging from modern wireline tools and extended the principle to Logging While Drilling (LWD) tools. A twofold approach has been taken for the work. Firstly 3-D finite element modeling had been carried out. This includes detailed modeling of the tool sensors' geometry and the analysis of the electromagnetic responses when the sensors are passed in front of a range of fracture widths. The modeling is complemented by a series of physical experiments carried out at Delft University. Setups utilized either a wireline pad or an LWD sensor from the relevant imaging tools. The sensors were traversed across two blocks separated by a precisely measured gap. Measured excess current relates to the fracture apertures and verifies the theoretical modeling work. This combined work confirms the equation for the fracture aperture calculation. In addition the coefficients for both the modern wireline and LWD electrical imaging tools are determined. Workflows for the quantification of conductive fractures identified on borehole images have been refined and implemented. Fractures are commonly not continuous across the borehole. The workflow includes a fast automatic extraction of both discontinuous and continuous fracture segments. Fractures are grouped into sets based on relevant criteria (such as orientation). Apertures are calculated using the relevant tool coefficients. The fracture density and porosity are then accurately computed along the well. This enables quantification and characterization of the fracture network, including a fast and easy recognition of intervals with specific aperture or porosity ranges. The workflow is demonstrated by examples.
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