|dc.description.abstract||Dynamic tests were conducted to evaluate the feasibility of sequestering carbon dioxide (CO2) in a carbonate dolomite reservoir. Two injection rates, 5.696E-06 cubic feet/ min (0.1613 cc/min (20 pore volumes)) and 3.467E-05 cubic feet/min (0.982 cc/min (120 pore volumes)) were tested to observe changes in petrophysical parameters, particularly permeability and porosity at each rate. The low injection rate allowed the evaluation of the effect on the bulk of the reservoir. And the high injection rate to evaluate the effect of dissolution on the face of the formation. The tests were carried out at reservoir simulated conditions (2000 psia (140.64 atm) and 150°F (65.5°C)).
San Andres dolomite formation cores from wells 744 and 745 drilled in the Levelland Field were used for this study. The dolomite formation is cemented by calcite and it has a high content of anhydrite. The formation brine of the Permian Basin was used to inject the cores. This brine has sodium 18,000 mg/L, chlorine 46,200 mg/L, calcium 6000 mg/L, sulfate 4880 mg/L, magnesium 1820 mg/L and potassium 1510 mg/L.
The injection of low pore volumes was found to reduce the permeability by about 50%, and the pore volume and porosity by about 25%. The total equilibrium magnetization (Mo) from NMR T2 distribution is decreased by about 17%, indicating substantial reduction in porosity and permeability. The small pore sizes (bulk volume irreducible-BVI) increased on average by about 70% and the large pore sized (free fluid index-FFl) decreased by about 24%.
The injection of high pore volume CO2 showed a slight increase in the petrophysical properties, permeability and porosity. The total equilibrium magnetization, B VI, and FFI did not present remarkable change.
At the onset of this research, it was still uncertain how the interaction between CO2 and formation brine affects the geochemistry of the reservoir. Therefore, several static tests under supercritical conditions (1070 psia (78 atm) and 88°F (31.TC)) and under reservoir conditions with and without rock samples were carried out.
After running the static tests for seven days, a precipitate formed from the brine after reaction with CO2 was obtained. The precipitate was analyzed using scanning transmission electron microscopy (STEM) to identify the specimen structure and to obtain a chemical analysis using an energy-dispersive spectrometry (EDS). Also, X-ray diffraction method (XRD) was used to identify the new minerals formed as a consequence of the interaction between CO2 and formation brine. Observations indicate that the precipitated is formed primarily by calcite, gypsum, halite and other mineral salts.
On the basis of the previous observations, it can be concluded that at low pore volumes, a compact dissolution of anhydrite took place, followed by deposition of material dissolved from the rock and/or precipitation of the salt dissolved from brine. Consequently, the permeability and porosity were significantly reduced.
In contrast, these effects in high pore volumes injected were masked by high dissolution of the anhydrite, leading to the formation of new flow paths (similar to wormholing in acidizing operation), and an increase in permeability and porosity. However, the increase in petrophysical properties could be offset by a reduction caused by precipitation of material, either from the dissolved salts in the brine or from the dissolved rock.
Another objective of this investigation was to determine the amount of shale in a sandstone reservoir. This is an important issue for evaluating the storage capacity of given aquifer/ reservoir as a candidate for CO2 sequestration.
A non-linear relationship of gamma ray index to volume of shale has been derived in a self-consistent formulation of emission and attenuation of gamma rays within the shale-sand composite. The technique to produce the derivation includes the self-shielding attenuation effects that occur at higher volumes of the shale gamma ray emitters. The effects of porosity and grain density of the constituents are included in the relationship of shale volume to gamma ray index. The new approach is applied to log data from the San Jorge Basin in Argentina.||