Nuclear Magnetic Resonance as a Tool for Evaluating Reservoir Wettability

Predicting reservoir wettability and its effect on fluid distribution and hydrocarbon recovery remains one of the major challenges in reservoir evaluation and engineering. In theory in should be possible to determine the wettability of reservoir rock/fluid systems by Nuclear Magnetic Resonance (NMR) due to the surface-sensitive nature of NMR relaxation measurements, although currently there is no proven model to relate reservoir wettability to NMR measurements. Laboratory NMR measurements in representative and well-characterised rock/fluid systems are crucial to interpret NMR log data. Adam Moss (adam@artuk.demon.co.uk) of ResLab-ART based in East Grinstead, UK reports on NMR results for cleaned and aged reservoir core plugs, containing oil and water, and shows that fluid distribution and wettability can be deduced from such measurements. The results suggest that NMR T 2 relaxation has the potential to be a valuable new technique in the evaluation of rock wettability both in the laboratory and in the reservoir.

Wettability

Wettability has a significant effect on the redistribution of fluids in the pore space as pressures in the oil and water phases alter. At several scales wettability influences capillary pressure-saturation and resistivity-saturation relationships as it controls the distribution of fluid in the pore space. It is experimentally intensive to determine the wettability of reservoir core plug samples. In preferentially water-wet rock, the brine occupies the small pores and forms a continuous film on the grain surfaces throughout the desaturation process. In contrast, in an oil-wet rock, brine tends to be located in the centre of the larger pores, with an oil film contacting the grain surfaces (Figure 1). An extensive review of the effects of wettability on petrophysical properties can be found in [1-4].

Figure 1: Schematic of Water Wet (left) and Oil Wet (right) Pores (Click for larger view)

Nuclear Magnetic Resonance

Nuclear Magnetic Resonance (NMR) measurements utilise the relaxation properties of hydrogen nuclei, present in reservoir fluids, after application of a magnetic pulse. NMR measurements can be performed on reservoir core samples or within the wellbore. The estimation of petrophysical properties using NMR data is significantly improved if the NMR logs are calibrated with NMR measurements on representative and well-characterised core samples. The laboratory measurements can also be used to obtain porosity and correlate pore size distribution, bound water and permeability with NMR spectra.

For fluids within a rock three independent NMR relaxation mechanisms occur:

• bulk relaxation which is an intrinsic property of the fluid,
• surface relaxation at the fluid-solid interface, and
• diffusion induced relaxation in a gradient field.

The nuclei diffuse randomly in a fluid and in a porous system some will come in contact with the pore surfaces, allowing them to relax faster (by energy transfer to the pore wall). In the fast diffusion regime the rates of relaxation are generally related to surface relaxivity and the surface to volume ratio (S/V) of the pore. The surface relaxivity is a function of the interactions between the wetting fluid and the surface. Thus NMR measurements should allow an evaluation of sample surface wettability.

NMR T 2 relaxation is usually measured using the Carr-Purcell-Meiboom-Gill (CPMG) pulse sequence. The CPMG pulse sequence takes only a few seconds to run, which makes it practical both in the laboratory and for well logging applications. In a porous rock system, there will be a continuous range of pore sizes, rather than several discrete sizes. This means that the CPMG echo-train for a single phase within a pore system contains a continuous range of relaxation times. Each pore-size has a distinctive T 2 value. The resulting echo-train therefore consists of a continuous distribution of T 2 values each with different signal amplitudes proportional to the amount of fluid contained in pores of that size.

NMR in Two Phase Systems

The NMR response from an oil/brine-saturated rock is dependent on the rock surface properties and the fluid-solid interactions inducing relaxation (magnetic decay). The relaxation of bulk brine or oil is slower than the relaxation from any fluid in contact with the pore walls. In strongly water-wet rocks the wetting films prevent the oil from interacting with the pore surfaces. The T 2 relaxation for this non-wetting oil is governed by the interaction between the oil hydrogen nuclei, so it produces a relaxation distribution close to the bulk oil response. Any water present will be in contact with the pore walls and its T 2 relaxation will be related to the size of the pores or water in pendular rings and pore crevices. In a strongly oil-wet rock, the signal for oil and water will be reversed (i.e. water relaxes at bulk, and oil relaxes according to pore sizes). Additionally, the bulk relaxation times for oil and water usually have different values. Thus by analysing the location of peaks within the T 2 distribution at different saturations the wettability of the sample surface should be evident. The magnitude of the T 2 response from oil and water are dependant on the volume present and the proton density or "hydrogen index" of each fluid. Any attempt at calculating saturations of each fluid needs to take account of this effect.

Howard [5] studied the influence of wettability on the NMR response for chalk samples. NMR measurements were performed on cleaned, preserved and treated samples at residual saturations and during waterflooding tests. Due to the small and uniform pore size distribution of the chalk samples and the use of light hydrocarbons a distinct separation between oil and water response was observed. He concluded that relaxation time distributions and their shifts effectively reflects the distribution of oil and water in chalks, while the intensity of the peaks are in quantitative agreement with water saturation. Zhang et al . [6] studied the effect of oil type (refined and crude oil) on residual oil saturation, Amott wettability index and NMR measurements for three types of sandstones. Two sandstones showed water-wet characteristics with refined oil, but became mixed-wet after ageing them in crude oil. They concluded that NMR measurements are an effective tool for analysing wettability alteration - see also [7].

Results of NMR Analyses

NMR analyses were performed using a 2 MHz low field Maran Ultra NMR spectrometer. The spectrometer operates at a magnet strength of 0.046 Tesla and can accommodate plug samples up to 38 mm diameter and 6cm long. Two-phase, oil and water, NMR T 2 measurements were performed at irreducible/residual saturations and after spontaneous imbibition/drainage during Amott wettability measurements - see Al-Mahrooqi et al. [8]. An example of T 2 distributions at different saturations and wettability states for a sandstone sample are shown in Figure 2.

Figure 2: T 2 Distributions for a Sandstone Sample at Different Water Saturations (The shadowed area is the T 2 distribution for bulk oil. All the measurements were performed after aging with the exception of Sw=1.0, which was performed after cleaning.) (Click for larger view)

Two main distributions (components) can be observed after ageing in crude. The distribution at shorter times corresponds to water contained in the smaller pores, as the ageing process does not change the wettability of the microporous, water-filled regions within the sample. The other component of the distribution corresponds to oil and it is close to the bulk oil response. When comparing the distributions after spontaneous and forced imbibition (Figure 2 - right) it can be noted that the long time peak decreases, it becomes wider and it is displaced to longer times. After spontaneous imbibition the water entered the smaller pores or increased the size of the water films. The water introduced during flooding is located in the centre of the larger pores and shielded from the surface by the wetting oil. As the T 2 peak for bulk water is around 1600 ms the wider peak is the result of overlapping of wetting oil and non-wetting water in the larger pores. This indicates that this sample is mixed-wet. The microporous regions remain water-wet while the larger pores are oil-wet. This is confirmed by the high resistivity saturation exponents obtained after ageing (2.52-3.38). On the other hand, according to the Amott-Harvey wettability index after ageing the sample is strongly oil-wet (-0.97).

Conclusions

The wettability of the rock surface affects the distribution of fluids within the pore space. Information regarding oil and water distribution can be obtained by comparing the NMR relaxation data at different saturations. The NMR measurements on cleaned and aged cores suggest that it could be used in the laboratory to determine rock wettability. The development of this technique could provide a faster and reliable method for wettability determination.

References

1. Anderson, W.G. 1986-1987 Wettability literature survey - Parts 2-4, JPT.
2. Morrow, N.R. 1990. Wettability and its effect on oil recovery. JPT, Dec: 1476-1484
3. Cuiec, L.E. 1990. Evaluation of reservoir wettability and its effects on reservoir recovery. In : Interfacial Phenomena in Oil Recovery, N.R. Morrow (ed), Marcell Dekker , New York .
4. Buckley, J.S., 2001. Effective wettability of minerals exposed to crude oil. Current Opinion in Colloid and Interface Science 6, 191-196.
5. Howard, J.J., 1994. Wettability and fluid saturations determined from NMR T 1 distributions. Mag. Reson. Imaging 12, 197-200.
6. Zhang, G.Q., Huang, C.C., Hirasaki, G.J., 2000. Interpretation of wettability in sandstones with NMR analysis. Petrophysics 41, 223-233.
7. Freedman, R., Lo, S., Flaum, M., Hirasaki, G.J., Matteson, A., Sezginer, A., 2001. A new NMR method of fluid characterization in reservoir rocks: Experimental confirmation and simulation results. SPE Journal 6, 452-464.
8. Al-Mahrooqi, S.H., Grattoni , C.A. , Moss, A.K. and Jing, X.D., 2003. An Investigation of the effects of wettability on NMR characteristics of sandstone rock and fluid systems. J. Pet. Sci. Eng. 39, 389-398.

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