.[1] We use first-principles molecular dynamics simulations to study the behavior of cation ordering in the non-equivalent octahedral sites of Mg-Fe olivine solid solutions. Our theoretical calculations confirm the previous experimental finding that Mg 2+ and Fe 2+ can invert their octahedral site occupancy at a critical temperature. Assuming that the site preference of Fe changes discontinuously between two states in which it is completely restricted to either M1 or M2 sites, we have calculated the transition temperature, T t , between the two extreme states. Under ambient pressure T t is calculated to be 520 C that agrees fairly with the experimental finding in which, however, the ordering state changed discontinuously over a much smaller range of the site occupancy of Fe. T t is found to be pressure sensitive, showing an increase by 30 to 100 C per unit GPa, depending upon the iron content. Using the Indian continental geotherm, we estimate a depth of around 75 Km corresponding to the calculated transition pressure and temperature of cation ordering, which matches well with the depth for the Hales discontinuity marked by a jump of shear wave velocity by $4%. For olivine solid solutions with 12.5% iron, the ordering transition increases V s from 4.5 to 4.7 Km/s. Both the inferences, viz. depth of discontinuity and magnitude of velocity increase find support from the modeling of teleseismic earthquake waveforms recorded over broadband seismographs on the Dharwar Craton. This leads us to infer that the cation ordering transition in ferromagnesian olivine might be a potential factor for the Hales discontinuity.Citation: Mandal, N., K. H. Chakravarty, K. Borah, and S. S. Rai (2012), Is a cation ordering transition of the Mg-Fe olivine phase in the mantle responsible for the shallow mantle seismic discontinuity beneath the Indian Craton?,

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Migration of fines has been observed during water flooding in chalk reservoirs and has been suggested to play a key role in enhanced oil recovery (EOR). But, the exact role of fines is not well studied for carbonate reservoirs. This study shows that addition of water and crude oil on calcite fines leads to formation of soluble oil micelles in the water phase. Formation of these micelles and its implication in EOR has been experimentally analyzed.To study this phenomenon different water insoluble salts were used as fines including, Li 2 CO 3 , MgCO 3 , CaCO 3 , CaSO 4 , SrSO 4 and BaSO 4 to which oil and water was added. To study conditions of oil micelles formation, design oil was used consisting of hexane and hexadecane. Heptanoic acid and stearic acid were doped in various compositions to mimic the acid number of the oil. Experiments were conducted for pure crude oil and doped oil to understand its implications in EOR. Composition of initial and final floating oil was obtained through gas chromatographic (GC) analysis. The two were thereafter compared to obtain the composition of micelles formed.The experiments showed that oil micelles are only formed when polar hydrocarbons are present in the oil. Different mixtures of alkanes did not produce any micelle. In oil containing stearic acid it was observed that around 95% of the initial stearic acid was accumulated in the micelles and only 5% was found in the floating oil. In oil samples containing heptanoic acid only 50-60% of its initial amount was accumulated in the micelles. This indicates heavier acids can form more stable micelles. Oil micelles were produced in all the different fines used, but the composition of these micelles where dependent on the salt anions. In all carbonates, lighter acids preferred micelles formation with lighter alkane, (indicated by intensification of heavier alkane in the floating oil compared to the initial oil) and vice versa for heavier acids. While no such selectivity in micelles formation was observed in any of the sulfates. Results obtained with crude oil and doped oil and designed oil were consistent. These results show that fines (of insoluble carbonate) released during core fracturing, or (sparingly soluble sulfates) formed during smart water flooding can form mixed wet water soluble oil micelles and help in mobilization of trapped oil along with increasing sweep efficiency.The results clearly show oil micelles formation in the water phase from the interactions of oil with fines, and also provide a detailed understanding of its composition under different conditions. The study highlights the significance of fines during smart water flooding in carbonate reservoirs and shows how its role in EOR can be mistakenly underestimated.

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New methods for enhanced oil recovery are typically developed using core flooding techniques. Establishing reservoir conditions is essential before the experimental campaign commences. The realistic oil-rock wettability can be obtained through optimum aging of the core. Aging time is affected by temperature, crude oil, formation brine, and coreplug lithology. Minimum time can significantly reduce the experimental cost while insufficient aging time can result in false conclusions. Real-time online resistivity measurements of coreplugs are presented and a novel method is introduced for determining the optimum aging time regardless of variations in crude oil, rock, and brine properties. State of the art core flooding equipment has been developed that can be used for consistently determining the resistivity of the coreplug during aging and waterflooding using advanced data acquisition software. In the proposed equipment, independent axial and sleeve pressure can be applied to mimic stresses at reservoir conditions. 10 coreplugs (four sandstones and six chalk samples) from the North Sea have been aged for more than 408 days in total and more than 29000 resistivity data points have been measured to consistently investigate the change of wettability during aging. At 60°C and 100 bars a homogeneous sandstone coreplug attained optimized wettability after 5 days, a heterogeneous coreplug required 30 days of aging. Chalk coreplugs needed 45 days of aging. This shows that coreplugs originating from the same field, when aged at equivalent conditions can have significantly different aging times because of minor variations in the coreplug properties. No fixed aging time can be recommended on the other hand a method is recommended which can determine the extent of aging. Coreplug aging patterns were studied for variation in pressure (20 to 130 bar) and temperature (60 to 130°C). Based on these experiments an algorithm has been developed which distinguishes the effect of wettability alteration, pressure, and temperature on coreplug resistivity. This study highlights the use of hydraulic oil to avoid release of fluids in the effluent pipes during the aging process. Furthermore, the described multiple monitoring devices are useful in detecting any experimental error that may have occurred during mounting of the coreplug in the core holder. Thus imperfect waterflooding which can otherwise produce misleading data can be avoided. The presented equipment can instantly and continuously calculate the mineral wettability throughout the aging process at any pressure, temperature condition and for any combination of rock and crude oil. Thus, using the stated core flooding equipment can not only decrease the cost and time of doing aging and waterflooding studies but can also significantly increase the accuracy in conducting core flooding experiments.