An NMR Study of Shale Wettability and Effective Surface Relaxivity Ismail Sulucarnain, Carl H. Sondergeld and Chandra S. Rai, University of Oklahoma

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1 SPE An NMR Study of Shale Wettability and Effective Surface Relaxivity Ismail Sulucarnain, Carl H. Sondergeld and Chandra S. Rai, University of Oklahoma Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Canadian Unconventional Resources Conference held in Calgary, Alberta, Canada, 30 October 1 November This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohi bited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Traditional methods of determining wettability such as the Amott and the U.S. Bureau of Mines (USBM) test for an oil/brine/rock system are difficult to apply to shales due to their extremely low permeability, usually in the nanodarcy range. Earlier Nuclear Magnetic Resonance (NMR) studies on Berea sandstone showed consistency with standard wettablity measurements and served as a calibration standard. A total of 10 core plugs from an Ordovician organic rich shale were analyzed. The T 2 NMR signature of the imbibed dodecane and brine occurred mostly at relaxation times faster than their measured bulk relaxation of 1 and 3 second, respectively, indicating that surface relaxation is dominant. The Ordovician organic rich shale display mixed wettability. Three of the samples had a high affinity for dodecane, as a result of the organic pores present in the samples. This result was consistent with the NMR spectra in both sequences as well as the gravimetric analysis. The main advantage NMR has over the traditional methods is that we are able to see where the fluids are being imbibed. Mercury injection capillary pressure (MICP) characterizes the distribution of pore throats while NMR responds to the pore bodies. Assuming the throats and bodeies are equivalent, a scaling factor was used to match the NMR spectra and the MICP curves to estimate the effective surface relaxivity for the shale samples. The range of the effective surface relaxivities ranged between 0.5µm/sec to 3.1µm/sec with an average of 1.7 ± 1.0 µm/sec. Mineralogy variations were observed across the 10 shale samples but showed a correlation which suggests that the effective surface relaxivity is dependent on mineralogy. Introduction Unconventional shale oil and gas plays are now recognized globally to be a potential source of environmentally friendlier natural gas. Wettability affects hydrocarbon recovery. In an oil/brine/rock system, wettability is a measure of the affinity of the rock to either oil or brine. Wettability affects relative permeability, capillary pressure and ultimate recovery. Traditional methods of determining wettability such as the Amott and the U.S. Bureau of Mines (USBM) tests are time consuming and difficult to apply to shales due to their very low permeability, usually in the nanodarcies range. Systems can exhibit oil, water, fractional or mixed wettability. Fractional wettability refers to a situation where strongly oil-wet and strongly water wet can coexist in a rock (Hsu et al., 1992). Mixed wettability is a different type of fractional wettability in which the smaller pores are water filled and water wet (Looyestijn and Hofman, 2006) and the oil-wet surfaces form continuous paths through the larger pores (Anderson, 1986). The wettability of shales has been assumed by different authors to range from strongly water wet, intermediate, or neutral to strongly oil wet. Irreversible reservoir damage can occur if the wrong assumption is made about the wettability of a reservoir. Shale reservoirs are presumed to have originated as organic rich mud deposited in marine environments, suggesting they were initially water wet (Passey et al., 2010). Boult et al., (1997) suggests that shales become oil-wet through the maturation of organic matter. NMR measurements were performed by Brown and Fatt (1956) on water saturated unconsolidated sand packs containing mixtures of preferentially oil and water wet surfaces. They found that water relaxed faster in the water-wet system than in the oil-wet system and observed a linear relationship between relaxation rate of water and the percentage of oil wet samples present in the sand packs. NMR can be used to distinguish wetting and non-wetting fluids. Later, similar behavior was observed by Saraf et al (1970) of spin-lattice relaxation times for water saturated glass beads (water-wet) and polymer beads (oil-wet). Hsu et al., (1992) used NMR T 1 and T 1ρ relaxation experiments to investigate wettability of water

2 2 SPE saturated bead packs (glass beads and polymer beads) and carbonate core samples (limestones and dolomites). They treated their carbonate core samples to create preferentially water-wet and preferentially oil-wet systems. They found a good agreement between the wetting behavior obtained from NMR measurement and that from a combined Amott /USBM measurements. They concluded that proton relaxation measurements (T 1 and T 1ρ ) are able to differentiate water wet from oil wet surfaces compared to deutrium relaxation measurements. Chen et al., (2006) used effective surface relaxivity to demonstrate the nature of wettability on NMR responses on Berea core samples and found that their proposed NMR wettability indices (either water index, oil index, or combined index) correlated well with the conventional Amott Harvey index, suggesting that quantitative information about rock wettability can be obtained from NMR measurements. They also investigated the effect of oil based mud (OBM) surfactants on wettability alteration and the NMR responses on Berea cores; their result showed that oil based mud surfactant altered the wettability in Berea core samples to intermediate or oil wet. They further posit that the NMR interpretation of the S wir underestimates the measured value when wettability alteration occurs. Zhang et al., (2000) found NMR measurements to be an effective tool in analyzing wettability alteration. They used both Soltrol 130 as the refined oil and a 30 API deep water Gulf of Mexico crude oil as the saturating fluids to acquire T 1 distributions of Bentheim, Berea, and North Burbank sandstone rocks. They replaced water (H 2 O) in the pores by diffusing heavy water (D 2 O or Deutrium), which does not have an NMR signal at the measured frequency, into the samples; this separates the brine phase response from the oil phase response. They observed both Bentheim and Berea were water wet in the presence of refined oil, but became mixed wet after aging in crude oil. They also found the North Burbank sandstone was mixed wet when saturated with either the refined oil or crude oil. Looyestijn and Hoffman, (2006) developed a quantitative NMR wettability index, I w, that is scaled from +1 for strongly water wet, through 0 for neutral, to -1 for strongly oil wet. Their results showed a good correlation between the NMR wettability index and the industry standard (USBM) index in carbonates, which we have adopted and modified to analyze the wettability index for the Ordovician source rock. Odusina et al. (2011) used NMR to determine the wettability of six Berea sandstone core plugs. In the first sequence of his experiments, he saturated the Berea samples in dodecane for 24 hours at 3000 psi before performing NMR T 2 measurements then immersing the same samples in brine for another 24 hours at room conditions before performing NMR. Before he started the second sequence he cleaned his samples in the soxhlet extractor for 24 hours at 100 C using a mixture of 80% methanol and 20% toluene. In the second part of his experiment, the reverse was the case, he started by saturating his samples with brine at 3000 psi for 24 hours before performing NMR T 2 measurements then immersing the same samples in dodecane for another 24 hours at room condition before performing NMR measurements. He observed Berea sandstone exhibits water-wet behavior and the smaller pores were filled with brine while the larger pores were filled with both brine and dodecane. Freedman et al., (2002) also observed similar finding in their Berea sandstone study. Odusina et al. (2011) also used NMR to determine the wettability of 50 shale samples from four different formations; Eagle ford, Barnett, Floyd and Woodford. He conducted two sequences of imbitition experiments on twin plugs: first samples were allowed to imbibe dodecane then brine and second where samples first were allowed to imbibe brine then dodecane. He observed the shales studied displayed mixed mettability except the Woodford, which had an affinity for dodecane compared to other formations. The main aim of this study was to determine the wettability of the Ordovician shale source rock using NMR to monitor the sequential imbibition of brine and dodecane and to also determine the effective surface relaxivity for the shale samples. NMR Background Proton NMR measures the net magnetization of the hydrogen atoms when an external magnetic field is present (Dunn et al., 2002; Kleinberg et al., 1993; Howard, 1994; Dastidar, 2006). Proton NMR relaxation in rock is characterized by: Diffusion effects were minimized with the use of fast measurement timing and homogeneous magnetic field. Bulk fluid relaxation is an intrinsic property of the fluid while surface relaxation dominates in a fast diffusion limit (Dunn et al., 2002). Surface relaxation is affected by the interaction of the fluid with the surface. Surface relaxivity and the ratio of the pore surface area to the pore volume are proportional to the surface relaxation and can be described by the following equation:

3 SPE Experimental Procedure NMR measurements were carried out using the Oxford Maran Ultra spectrometer to obtain T 2 measurements from the CPMG sequence. The spectrometer runs at a frequency of 2MHz, which is the same as downhole NMR logging tools, so data obtained from core measurements are directly applicable to the interpretation of downhole logs. Ten 1 inch by 1inch long core plugs from the Ordovician organic rich shale from various depth were used in this study. The as received state NMR, was run prior to the spontaneous imbibition experiments. Two sequences using the same experimental procedures were carried out. For the first sequence, we ran NMR on the as received state sample then allowed the sample to imbibe 25,000 ppm NaCl solution for 48 hours; we then ran the NMR on the same plug after it imbibed dodecane for 48 hours. After the first sequence was completed, the samples were then placed in a vacuum oven for 48 hours at room temperature to remove imbibed fluids prior to starting the second sequence. For the second sequence, fluid imbibition was carried out in the reverse order starting with dodecane then brine imbibition. All the samples were weighed before and after each fluid imbibition for gravimetric analysis. The same CMPG sequence was used for the NMR runs. All NMR measurements were carried out using 10,000 scans to obtain an optimal signal to noise ratio and a value of 150µs was used for the echo time spacing. To minimize diffusion effects and to capture the whole range in the small pores, measurements were made with small echo time spacing. In order to capture the effect of the imbibed fluid, the CPMG decays curves were subtracted and the remaining echo train was converted to a relaxation spectrum. This process is known as the Time Domain Analysis. This method is more robust than subtracting the wait times of the acquired decay curves (Winkler et al. 2006). For instance, to capture the effect of the imbibed dodecane or brine in the second sequence, we subtracted the NMR decay curve of the vacuum dried sample from the NMR decay curve after dodecane imbibition, and for the brine spectra we subtracted the NMR decay curve after dodecane imbibiton from the NMR decay curve after brine imbibition. Results and Discussion The mineralogy data for the Ordovician organic rich shale samples were obtained using transmission Fourier Transform Infrared spectroscopy (Sondergeld and Rai, 1993; Ballard, 2007). Table 5 shows that samples XX01, XX02, and XX03 are clay-rich while samples XX05, XX07, XX09, XX12, XX23 and XX25 are carbonate-rich and sample XX04 is the boundary between the clay-rich samples and the carbonate-rich samples. It is the only sample that had smectite and the greatest apatite content. The Ordovician organic rich shale samples had TOC values ranging between 0.3% and 5.8% with an average of 3% ± 1.8%. Helium porosity measurements were performed on finely crushed end pieces of the samples using techniques presented by Karastathis (2007). These values were between 1.5% and 5.7%. The as received state NMR measurements (Fig 1) in the first sequence, showed some residual fluid (0.7% - 2.2% with an average of 1.1% ± 0.5%) was present in the shale samples. Dominant peaks were observed from the T 2 spectra for the shale samples at relaxation times ranging from 0.3 to 1.5ms. Fig. 1: As received state T 2 spectra for 10 samples from the Ordovician source rock. Dominant peaks appearing at relaxation times ranging from 0.3 ms to 1.5 ms. Note there is residual water even in the poorly preserved samples and that smaples show a considerable variation in the residual saturations.

4 Dodecane Brine 4 SPE Gravimetric analysis showed that a significant amount of brine was imbibed into the samples during spontaneous imbibition. The NMR porosity after brine imbibition ranged between 0.8% and 6.3% for all samples, confirming that brine was indeed imbibed. In the fast diffusion limit, the dominant relaxation mechanism is surface relaxation. This suggests the surfaces in contact with the imbibed brine have an affinity for it, causing this fast relaxation to occur. No peaks appear at any time close to the bulk relaxation of brine, 3 seconds, suggesting that all the introduced brine is experiencing surface relaxation. Subtraction of the as received state spectra from the imbibed brine spectra shows only the imbibed brine distribution in the samples (Fig. 2A), and this compared favorably with the amount of brine estimated by the gravimetric analysis (Table 1). The secondary peaks occurring around 10 and 100 ms are associated with microcracks (Odusina, et al., 2010). The spectrum for imbibed dodecane (Fig. 2B) was obtained after subtracting the NMR decay curve for brine imbibition from the NMR decay curve after dodecacne imbibition. Samples XX04, XX07, XX12 previously showed minimal brine imbibition but had a strong affinity for dodecane suggesting there are less hydrophilic wetting surfaces and more oil wetting surfaces in these samples. Two identical sequences were run on each sample for consistency purposes. After vacuum-drying the samples, the second imbibition sequence was run starting with dodecane imbibition then brine imbibition. The spectra for the amount of dodecane imbibed (Fig. 3A) for this case was obtained by subtracting the NMR decay curve of the vacuum dried sample from the NMR decay curve after dodecane imbibition. We observed the same three samples still had a strong affinity for dodecane which was consistent with the gravimetric analysis and the NMR wettability index. 2A 2B Figure 2: Brine and dodecane difference NMR spectra for 10 samples from the Ordovican shale source rock for the first imbibition sequence. The brine signal comes in earlier than the dodecane signal. A fast relaxation time for brine occurring below 1ms was observed, suggesting a strong influence of surface relaxation. Samples XX04, XX07 and XX12 had a strong affinity for dodecane. These three samples also had the highest TOC weight percentage compared to the others.

5 Brine Dodecane SPE XX07 3A XX12 XX04 3B Figure 3: Dodecane and brine difference spectra for 10 samples from the Ordovican shale source rock for the second imbibition sequence. Samples XX04, XX07 and XX12 had a strong affinity for dodecane suggesting these samples are oil-wet. These three samples also had the highest TOC weight percentage compared to the others. Gravimetric Observation We observed consistency between the gravimetric and the NMR estimated pore fluid volumes. The samples highlighted in red in Table 1 imbibed more dodecane than brine. This observation was consistent with the NMR response in both imbibition sequences. The main advantage NMR has over the gravimetric analysis is that we are able to see where the fluids are being imbibed.

6 6 SPE Table1: Gravimetric analysis of the imbibed volumes after the first and second imbibition sequences. Samples highlighted in red imbibed more dodecane than brine which was consistent with the results obtained from the NMR spectra. Depth FIRST SEQUENCE (Brine Ratio of Imbibed Brine to Imbibed Dodecane Dodecane) Pore Volume Depth SECOND SEQUENCE (Dodecane Ratio of Imbibed Brine to Imbibed Imbibed Volume Dodecane Dodecane Brine Brine) Pore Volume Imbibed Volume Sw Sw Brine Dodecane (ft) (cc) (cc) (cc) (ft) (cc) (cc) (cc) XX XX XX XX XX XX XX XX XX XX XX XX XX XX XX XX XX XX XX XX NMR Wettability Index An NMR wettability index from Looyestijn and Hofman (2006) was modified for a quantitative shale wettability index. In our case, we obtained brine wetting surface fraction (S w ) by dividing the NMR pore fluid volume (actual amount of brine imbibed) by the helium porosity. The dodecane wetting surface fraction (S do ) was obtained in the same manner by dividing the NMR pore fluid volume (actual amount of dodecane imbibed) by the helium porosity. We observed consistency between the gravimetric analysis, NMR response as well as the NMR wettability index. Samples showing high dodecane spontaneous imbibition gave a negative wettability index, indicating they are fully oil wet. Table 2 shows a summary of the brine and dodecane wetting surface fraction used to obtain the calculated NMR wettability index. The NMR wettability has been scaled to follow existing indices where -1 is for a fully oil-wet, 0 is for neutral and +1 is for a fully water-wet. The governing NMR wettability index equation is given by: Where NMR(S w ) and NMR(S do ) are the amounts of water and dodecane imbided, respectively as measured by NMR.

7 SPE Table 2: Summary of the fraction of the total porosity filled at the native state saturation measurements, the fraction after total imbibition, brine and dodecane wetting surface fraction. The brine and dodecane wetting surface fraction were used to obtain the NMR wettability index. The samples highlighted in red where oil-wet which was consistent with the results obtained from both the gravimetric analysis and the NMR spectra. Depth Snative Sw Sdo Stotal NMR Iw TOC,% XX XX XX XX XX XX XX XX XX XX Estimation of effective surface Relaxivity using NMR and Mercury Injection Capillary Pressure (MICP) The quantitative correlation between NMR and mercury injection capillary pressure (MICP) measurements made on the samples were used to estimate the effective surface relaxivity parameter, ρ e as suggested by Kleinberg, (1996). It is important to note that mercury injection characterizes the sample pore throat while NMR estimates fluid content in the pore bodies. It is inherently assumed that bigger pore throats are related to bigger pore bodies which may not be the case, especially in shaly formations though this assumption has worked well for sandstones (Lowden et al., 2003). Also, the presence of clay signature may possibly affect the NMR distribution. With this, a scaling factor was used to match the two distributions. Mercury data for samples XX09, XX23 and XX25 were extremely noisy and were left out of the analysis. The matching of the two curves (Fig. 4) was done by normalizing their amplitudes by dividing by the maximum value, and the highest value was used for the matching. The obtained scaling factor ranged from 17.3 psi.sec to 108 psi.sec with an average of 49 ± 37.1 psi.sec. Some of the mercury data still showed that intrusion was occurring even at the equipment limit of 60,000 psi, possibly missing some porosity in the very small sized pores. Agreement between the NMR and MICP data at short relaxtion times and high intrusion pressures suggest these rocks are mainly composed of nanometer sized pores. As explained earlier, in the fast diffusion limit, T 2 is proportional to a pore body size distribution and faster T 2 times corresponds to smaller pore body sizes. From the scaling factors obtained, the effective surface relaxivity was calculated by assuming cylindrical pore bodies; combining the Washburn equation with the NMR T 2 relaxation equation to obtain the following: Where, ρ e = effective surface relaxivity, γ = surface tension (485dynes/cm for Air-Hg), θ = advancing contact angle (140 o for air-hg), P c T 2 = scaling factor. The effective surface relaxivities obtained ranged between 0.5 µm/sec to 3.1 µm/sec with an average of 1.7 ± 1.0 µm/sec. Using the average effective surface relaxivity of 1.7μm/s, the largest peaks map into pore body sizes of 0.3 nm to 20 nm, as shown in Fig. 5. Sample XX04 contained smectite and was the boundary between the clay rich samples and the carbonate rich samples. Sample XX04 has the highest effective surface relaxivity and also has the greatest amount of smectite, an ironrich clay. Matteson et al., 2000 also observed similar findings in their experiments when glauconite was present. The estimated scaling factors and corresponding effective surface relaxivities can be seen in Table 3.

8 8 SPE Fig. 4: Matching between NMR and MICP curves for sample XX01. This was done by normalizing their amplitudes by dividing by the maximum value, and the highest value was used for the matching. The obtained scaling factor was 25.1psi.sec Table 3: Summary of the scaling factor used to obtain the effective surface relaxivity for the shale samples.. The obtained scaling factor ranged from 17.3 psi.sec to 108 psi.sec with an average of 49 ± 37.1 psi.sec while the effective surface relaxivity ranged from 0.5 µm/sec to 3.1 µm/sec with an average of 1.7 ± 1.0 µm/sec. Sample XX04 contained smectite and was the boundary between the clay rich samples and the carbonate rich samples.

9 SPE Figure 5: T 2 to pore body size. Using an average surface relaxivity of 1.7μm/s the largest peaks maps into pore body sizes of 0.3 nm to 20 nm. Table 4: Effective surface relaxivity and quantitative FTIR mineralogy data for the Ordovician shale samples

10 10 SPE Conclusion NMR can be used qualitatively to determine shale wettability and the NMR wettability index developed as well as the gravimetric measurements quantitatively supports the NMR measurements. The Ordovician source rock samples are of mixed wettability with a correlation between oil wetting and TOC content. Imbibition of each fluid is observed in the smallest pores suggesting there is an efficient network connectivity which is enhanced by desiccation microfractures. Effective surface relaxivity is dependent on mineralogy, which ranged from 0.5 µm/sec to 3.1 µm/sec with an average of 1.7 ± 1.0 µm/sec. Larger values of surface relaxivity are associated with carbonate rich samples. References Cited Anderson, W.G Wettability Literature Survey--part 2: Wettability Measurement, Journal of Petroleum Technology, November, pp Ballard B.D., 2007, Quantitative Mineralogy of Reservoir Rocks Using Fourier Transform Infrared Spectroscopy, SPE STU, Presented at Annual Technical Conference and Exhibition, Anaheim, California, November Boult, P. J.; Theologou, P. N.; Foden, J Capillary Seals Within the Eromanga Basin, Australia: Implications for Exploration and Production, AAPG Memoir, 67, (Seals,Traps and the Petroleum System), Brown R.J.S, and Fatt I Measurement of Fractional Wettability of Oil Fields Rocks by Nuclear Magnetic Relaxation Method. Petroleum Transaction, AIME, 207, 262 Chen J., Hirasaki G.J., and Flaum M NMR wettability indices: Effect of OBM on wettability and NMR responses. Journal of Petroleum Science and Engineering 52: Dastidar R., Chandra C.S., Sondergeld C.H., and Shahreyar R NMR Response of Two Clastic Reservoirs: Influence of Depositional Environment, PETROPHYSICS, VOL. 47, NO. 3, P Dunn, K.J., D. J. Bergman and G. A. Latorraca, 2002, Nuclear Magnetic Resonance: Petrophysical and Logging Applications, Pergamon Press, New York, 293 pp. Freedman R., Heaton N., Flaum M., Hirasaki G.J., Flaum C., and Hurlimann M Wettability, Saturation, and Viscosity from NMR Measurements. SPE presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 29 September 2 October. Howard, J.J., Wettability and fluid saturations determined from NMR T1 distributions. Magn. Reson. Imaging 12 (2), Howard J.J. and Spinler E.A Nuclear Magnetic Resonance Measurements of Wettability and Fluid Saturations in Chalk. SPE 26471, Advanced Technology Series, Vol. 3. No.1 Hsu W., Xiaoyu L., and Flumerfelt R.W Wettability of Porous Media by NMR Relaxation Methods. SPE presented at the SPE Annual Technical Conference and Exhibition, Washington, DC, 4 7 October. Kleinberg, R.L., 1996, Utility of NMR T2 distributions, connection with capillary pressure, clay effect, and determination of the surface relaxivity parameter ρ2: Magnetic Resonance Imaging, vol. 14(7/8), p Kleinberg R. L., Straley C., Kenyon W.E., Akkurt R., and Farooqui S.A Nuclear Magnetic Resonance of Rocks: T1 vs. T2. Paper SPE presented at the 1993 SPE Annual Technical Conference and Exhibition, Houston, Texas, 3 6 October.

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