Seawater injection has demonstrated a successful and a well-established procedure for reservoir pressure maintaining and sweeping oil out of the reservoir. However, in most cases seawater by itself showed low incremental oil recovery, many research studies have shown that further dilution of the injected seawater is capable of altering the carbonate formation's wettability from mixed or oil-wet to more water-wet and therefore additional oil recovery. However, dilution requires massive volume of fresh water which is an expensive commodity and therefore it will not be practical in real applications. The following study provides for the first time a novel concept for boosting oil recovery with use of halides ions in very small concentrations without the need for seawater dilution. Halides ions (iodide ions) are added to the seawater with different concentrations (1000 ppm and 2000 ppm) to formulate what we call the "Dynamic Water". The efficiencies of the different prepared Dynamic Waters (with different iodide ions concentrations) were compared to seawater by performing IFT, contact angle, spontaneous imbibition and coreflooding experiments. Although all prepared Dynamic Water mixtures have higher salinity than seawater, they had insignificant impact on lowering the IFT, but they significantly alter the rock wettability to stronger water wet, which is an important oil recovery mechanism. The performance of the Dynamic Water on oil recovery was also investigated in this study by means of spontaneous imbibition and coreflooding experiments. Six samples were utilized for these experiments, three dolostones and three limestones. Initially, the three limestone samples were considered for spontaneous imbibition where Dynamic Water proved to be efficient in recovering oil from all the samples. After sample cleaning, the same three limestone samples in addition to the three dolostone samples were used for coreflooding under reservoir conditions of high pressure and high temperature. Good oil recoveries were achieved from almost all the samples by coreflooding, with maximum additional oil recovery of 16.9% from one of the limestone samples.
In formation evaluation and reservoir engineering, resistivity index, relative permeability, and capillary pressure are crucial parameters for estimating oil reserves and planning a production scenario. They can be determined in the laboratory using Special Core Analysis, or SCAL techniques. Since they are all functions of fluid saturation, correlations between them may exist; but the literature on their inter-relationships is lacking. In this paper, experimental relative permeabilities and relative permeabilities obtained from resistivity measurements using Li’s model (2007) are compared for different immiscible brine-oil displacements. An experimental study on a water-wet grainstone rock was initiated in order to measure its resistivity response during different ambient water-oil flow displacements. Three different flooding techniques were performed and compared. The most popular technique is the resistivity porous plate Pc-RI method where resistivity and capillary pressure are measured at equilibrium. The steady-state flooding method was also tested; resistivity and steady-state relative permeability were measured at the equilibrium state. Finally the fastest yet least reliable method is the transient technique or unsteady-state flooding method where resistivity and unsteady-state relative permeability are measured under transient conditions. A comparison between resistivity index obtained from the three flooding techniques showed that the unsteady-state technique cannot give reliable resistivity index curve, and so should be avoided to infer Kr from resistivity measurements. The Pc-RI method provides the most reliable resistivity index curve but relative permeability can only be derived from the capillary pressure curve. Finally, the steady-state displacement was found to be the best method to compare experimental relative permeability with relative permeability inferred from resistivity. In spite of an acceptable match between them, an improvemnent of Li’s model is proposed. Additional investigations such as effects of wettability and rock heterogeneities on these results will be necessary to validate the generality of the overall workflow.
Fully water saturated plugs were centrifuged in air using small capillary pressure steps. At each pressure step the low frequency (2 MHz) NMR and high frequency dielectric permittivity were measured. The centrifugal pressure steps were incremented at 1 psi so as to determine the water saturation at fine scale. These experiments are designed to replace water by air, which has no NMR signal. As a result NMR signal decreases as the centrifugal pressure increases. The NMR T2 distribution data show gradual depletion of free water from the pore space as the centrifugal pressure increases from zero to five psi. Above this pressure the rate of fluid production per pressure decreases suggesting the produced water is bound to the pore wall. A plot of water filled porosity vs centrifugal pressure shows at least two regimes. An initial fast production at low pressures has a larger slope compared with later slow production at higher pressures. Both smaller produced volume and higher pressures are consistent with the water being bound to the pore surface. The dielectric permittivity also shows a decrease in permittivity as the centrifugal pressure increases. This is because the dielectric permittivity is most sensitive to the water content as compared to air or solid matrix. The permittivity data plotted vs the centrifugal pressure also show at least two different slopes. The initial fast slope is attributed to the production of free water while the higher pressure slow slope is due to bound fluid.
As fluids move through a rock their flow path is controlled by the capillary forces from the local pore size distribution. The pore structure causes the fluid not to follow a simple path which is a familiar challenge in reservoir production and recovery. In this paper we examine this effect at a small, more manageable scale of a core plug in laboratory.Fully water saturated plugs were centrifuged in air using small capillary pressure steps. At each step the T 2 distribution of the core was measured. The capillary pressure steps were incremented at one psi steps for careful mapping of the evolution of fluid distribution.In this experiment the water was replaced by air which has no NMR signal, thus the results clearly showed gradual removal of free water from the larger pores with no reduction of bound water signal. Comparing T 2 distributions from different capillary pressure steps, we were able to pinpoint the pores contributing to fluid displacement at each pressure. These results, for the first time, reveal more detailed pore information that is apparent from normal T 2 distribution alone.The new approach enables deeper understanding of rock pore structure and how the fluid distribution is influenced by the pore sizes involved in conducting the fluid. These results, once up-scaled to reservoir level, will help optimize and improve oil recovery. The technical contribution of this paper includes pore size study at a finer scale by NMR than previously reported.
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