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An investigation of the effect of wettability on NMR characteristics of sandstone rock and fluid systems
Journal of Petroleum Science and Engineering 39 (2003) 389 – 398 www.elsevier.com/locate/jpetscieng
An investigation of the effect of wettability on NMR characteristics of sandstone rock and fluid systems S.H. Al-Mahrooqi a, C.A. Grattoni a,*, A.K. Moss b, X.D. Jing a,1 b
a Department of Earth Science and Engineering, Imperial College London, Prince Consort Road, London SW7 2BP, UK Applied Reservoir Technology (ART), Unit 4B, The Birches Industrial Estate, Imberhorne Lane, East Grinstead, West Sussex RH19 1XY, UK
Received 12 March 2002; received in revised form 21 October 2002
Abstract Predicting reservoir wettability and its effect on fluid distribution and hydrocarbon recovery remains one of the major challenges in reservoir evaluation and engineering. Current laboratory based techniques require the use of rock – fluid systems that are representative of in situ reservoir wettability and preferably under reservoir conditions of pressure and temperature. However, the estimation of reservoir wettability is difficult to obtain from most laboratory experiments. In theory, it should be possible to determine the wettability of reservoir rock – fluid systems by nuclear magnetic resonance (NMR) due to the surfacesensitive nature of NMR relaxation measurements. Thus, NMR logs should in principle be able to give an indication of reservoir wettability, however, as yet 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. A series of systematic laboratory experiments were designed using a range of sandstone core plugs with the aim of investigating the feasibility of using NMR measurements as a means to determine wettability. NMR T2 spectrum measurements were performed in reservoir core plugs at different saturations and wettability states. The samples were first cleaned by hot solvent extraction, then saturated with brine and a drainage/imbibition cycle performed. At the lowest brine saturation the same samples were aged in crude oil and a further drainage/imbibition cycle performed. NMR transverse relaxation time, T2, was measured on fully saturated samples, at residual saturations and some intermediate saturation values. The wettability of the samples is evaluated using the Archie’s saturation exponent and by Amott-Harvey wettability index. The wettability of the cores studied ranged from mixed-wet to oil-wet. The NMR T2 results for cleaned and aged reservoir core plugs, containing oil and water, show that fluid distribution and wettability can be deduced from such measurements. The results on aged core plugs suggest that the oil occupies a wide range of pore sizes and is in contact with the pore walls. The results presented in the paper suggest that NMR T2 relaxation has the potential to be an alternative technique to evaluate rock wettability in the laboratory and in the reservoir. D 2003 Elsevier Science B.V. All rights reserved. Keywords: Wettability; Saturation; Electrical resistivity; NMR; T2 distribution
* Corresponding author. Fax: +44-207-594-7444. E-mail addresses: [email protected] (S.H. Al-Mahrooqi), [email protected] (C.A. Grattoni), [email protected] (A.K. Moss), [email protected] (X.D. Jing). 1 Currently with Shell International Exploration and Production, Rijswijk, The Netherlands. 0920-4105/03/$ - see front matter D 2003 Elsevier Science B.V. All rights reserved. doi:10.1016/S0920-4105(03)00077-9
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1. Introduction Nuclear magnetic resonance (NMR) measurements on reservoir core samples are performed to obtain an improved interpretation of NMR log data. The estimation of petrophysical properties is significantly improved if the 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 T1 and T2 spectra. NMR is a non-invasive technique that can provide information about the pore structure, the amount of fluid in-situ and the interactions between the pore fluids and the rock. Thus, it could be used as a fast and relatively easy method for determining wettability. The development of a downhole wettability measurement technique could provide vital information to improve reservoir characterisation and performance predictions. 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. Thus, NMR measurements should allow the evaluation of wettability. Numerous researchers have explored the link between wettability and NMR relaxation measurements. However, the majority of the studies were performed under conditions that are not representative of oil reservoirs. Brown and Fatt (1956) conducted the earliest study on water-saturated sand packs and measured the spin-lattice relaxation time T1 on five sand packs, made from different mixtures of clean and Dri-filmtreated sand. They found that the inverse of the water relaxation time, T1, increased linearly with the percentage of oil-wet sand. Similar behaviour was observed by Saraf et al. (1970) for water-saturated bead-packs composed of glass beads (water-wet) and polymer beads (oil-wet). Although the relaxation time of fully saturated media is proportional to the affinity of the fluid to the rock surface, this is of limited application to laboratory studies of oil reservoirs where oil and water are present. Hsu et al. (1992) used NMR relaxation experiments to study the wettability of fully water saturated beadpacks, limestones and dolomites. They concluded that proton relaxation measurements are
able to distinguish water-wet from oil-wet surfaces. However, T1 is strongly affected by the surface paramagnetic impurities. A good agreement was found between the wetting behaviour obtained from NMR relaxation and from a combined Amott/USBM method. Oren et al. (1994) conducted NMR studies on sandstones containing oil and water. NMR T1 measurements were performed at various saturations during low rate imbibition displacements for both water-wet and intermediate-wet cores. They analysed the relaxation time using a multiexponential model with two or three exponential terms. For fully saturated water-wet rocks, they found that rock – fluid interactions are stronger when water rather than oil occupies the pore space, which increases surface relaxation strength and hence shortens the relaxation time. They concluded that for water-wet samples, the intensity of the longest T1 component correlates with oil saturation and that the oil distribution at residual saturation could be inferred from NMR measurements. Howard (1994, 1998) studied the influence of wettability on the NMR response for chalk samples. NMR T1 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. (2000) studied the effect of oil type (refined and crude oil) on residual oil saturation, Amott wettability index and NMR T1 measurements for three types of sandstones. Two sandstones showed water-wet characteristics with refined oil, but became mixed-wet after aging them in crude oil. They concluded that NMR measurements are an effective tool for analysing wettability alteration. Freedman et al. (2001a,b) performed NMR experiments in sandstones, limestone and Dolomite containing brine and refined or crude oil. CMPG data suites were acquired under a constant magnetic field gradient and the data analysed with the multifluid relaxational model, which allows the identification of the fluids within the rock. This method was used to accurately obtain total porosity, fluid saturation and oil viscosities.
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Most published NMR studies into rock wettability have focused on the spin-lattice relaxation time T1. However, significant advances in NMR techniques have improved NMR measurements and currently most NMR laboratory instruments and logging tools are able to process the NMR signals into T1 and T2 relaxation time distributions. The measurement of T2 relaxation is preferred as it is faster and usually provides similar distributions to T1. This paper aims to relate traditional NMR T2 measurement to wettability for partially brine saturated sandstones. The studies have been performed on cleaned and aged reservoir cores. The wettability characteristics of the samples and the T2 distribution have been linked with their electrical behaviour and Amott-Harvey wettability index tests.
2. NMR theory 2.1. Single phase response NMR T2 relaxation is usually measured using the Carr-Purcell-Meiboom-Gill (CPMG) pulse sequence The CPMG echo train comprises a 90j pulse, followed by a train of 180j pulses. This pulse sequence eliminates dephasing effects produced by local variations in the magnetic field and therefore measures the true T2 of the sample. Therefore, the signal decay is due to interactions with neighbouring spins and surfaces. The CPMG pulse sequence takes only a few seconds to run, which makes it practical both in the laboratory and for well logging applications. For fluids within a rock three independent relaxation mechanisms occur: (1) bulk relaxation which is an intrinsic property of the fluid, (2) surface relaxation at the fluid– solid interface and (3) 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, the relaxation time is shorter for the fluid with more interaction with the pore walls (Oren et al., 1994; Gogolashvili, 1996).
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In the fast diffusion limit, the relaxation time observed experimentally is an average relaxation time for all the nuclei in the pores. Therefore, in a small pore, the nuclei are more likely to interact with the surface, and so the average relaxation time will be faster (shorter) than in a large pore. For a fully saturated sample, each pore-size has a distinctive T2 value, which is proportional to the surface to volume ratio. The echo-train corresponding to one particular pore-size will have a characteristic T2 value and signal amplitude proportional to the amount of fluid contained in all the pores of that size. The resulting echotrain therefore consists of a continuous distribution of T2 values each with different signal amplitudes. 2.2. Two phase response Air– water systems are commonly used to define the boundary between free and bound fluid within the T2 distribution, this is known as the T2 cutoff. The analysis of such systems is relatively easy as there is no NMR response from the air and the T2 relaxation is exclusively due to the protons in the water. At irreducible water saturation, all the water is capillary-bound and the corresponding T2 distribution represents the range of pore sizes containing this immobile water as shown in Fig. 1. Some very short T2 values may also result from water in pendular rings, crevices and roughness in the pore surfaces, which appear as an increase in the signal amplitude at short T2 times when compared with the fully saturated signal (Coates et al., 1997).
Fig. 1. Typical NMR T2 distribution for a sandstone. The components of capillary bound water are shown.
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For cores containing oil and water, the interpretation of the T2 distribution becomes more complex. In strongly water-wet rocks, the wetting films prevent the oil from interacting with the pore surfaces. The T2 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 T2 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 T2 distribution at different saturations, the wettability of the rock fluid system can be deduced. The magnitude of the T2 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.
3. Test procedures Sandstone samples from a North Sea reservoir were selected for this study. Table 1 shows the petrophysical data for these samples. The samples were cleaned as described in next section and samples 35 and 40 were aged. 3.1. Sample preparation The samples are 3.8 cm in diameter and 4.5 –5.0 cm in length. All samples originally contained crude oil, which was cleaned from the pore space by Soxhlet extraction using a chloroform/methanol azeotrope Table 1 Petrophysical properties of the cleaned reservoir samples Sample Klinkenberg Porosity Grain Formation Cementation ID permeability (%) density factora exponenta (mD) (g/cc) 35 40 94
10 516 564 a
20.4 23.2 21.3
2.65 2.65 2.65
24.9 17.6 16.9
Measured at a confining pressure of 15.86 MPa.
1.95 1.92 1.75
(12.6% methanol and 87.4% chloroform boiling at 53 jC) for a week, then they were further cleaned by using hot refluxing methanol (boiling point = 64.5 jC). Each sample was placed in a saturator and evacuated. The simulated formation brine, degassed and filtered to 0.45 Am, was then introduced under vacuum. The samples were left overnight under pressure. Complete saturation was verified using the dry weight, the saturated weight, helium pore volume and brine density. All samples attained full brine saturation. 3.2. Desaturation by continuous injection Fully brine-saturated samples were loaded into Viton rubber sleeves. A brine saturated capillary contact mat was placed at the ends of the sleeved sample and a water-wet ceramic disc (impermeable to oil below a threshold pressure of 1500 kPa) mounted at one end. Stainless steel flow platens and stems filled with brine were mounted at each end of the sample before loading them into a multi-sample test cell. The flow stems were insulated from the body of the cell so that the resistance across the sample, in the two-electrode configuration, could be measured. Confining pressure was applied in increments from 0.69 MPa to a maximum of 15.86 MPa. The downstream end of each sample was connected to a burette, allowing the measurement of the brine volume expelled from the samples during application of confining pressure and oil injection. Pore volume reduction was determined by measuring the volume of brine squeezed from the samples as the overburden pressure increased. The resistivity of the samples were monitored until they stabilised indicating that both ionic and pressure equilibrium had been achieved. Before oil injection, brine was flowed through the sample to ensure full saturation. The resistance of each sample was then recorded and the formation factors and cementation exponents calculated (Table 1). A mixture of light paraffin oils, trade name Multipar (density = 764 kg/m3 at 20 jC, viscosity = 1.13 mPa s at 20 jC), was injected into each sample by using dedicated slow rate syringe pumps. The continuous injection desaturation process is analogous to capillary pressure equilibrium desaturation if the flow rate is kept low and capillary force dominates. The flow rate used was less than 0.5 cm3/day, so desatura-
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tion of the samples takes about 20 days (depending on sample pore volume). Measurements of resistance, volume displaced and temperature were made each day. Temperature corrected resistivity index and saturations were then calculated. Brine saturations can be measured to an accuracy of 0.1% of pore volume. 3.3. Sample aging to change wettability Dead crude oil was used to induce wettability changes during aging. However, as the crude oil may contain some asphaltenes, which may induce wettability changes (Buckley, 2001), a stability test between crude oil and Multipar was performed. Ten mixtures of crude oil and Multipar with volume ratios 0.025 (1/40) to 0.8 (4/1) were prepared, stored at room temperature for 72 h and then filtered through a 0.22 Am Millipore filter. Then the filter was washed with 20 cm3 of pentane, dried in an oven at 50 jC and weighted. The amount of precipitated for all the mixtures was below the experimental error, 0.05%, indicating that the changes in wettability are not due to asphaltenes destabilization by the Multipar oil. After the lowest brine saturation was attained during the continuous injection; samples 35 and 40 were removed from the multi-sample cell and the Multipar test oil was replaced with dead crude oil from the same well as the samples. The samples were loaded in a pressure vessel and a pore pressure of 1.38 MPa applied. The samples were aged in an oven at 85 jC for 40 days. At the end of this period, the samples were cooled to room temperature, the pressure reduced to atmospheric and the crude oil in the pore space flushed out with the Multipar test oil. Each sample was then loaded in a Hassler cell and flooded with brine, reducing the oil volume down to residual oil saturation. Volumes of oil displaced were collected and the new brine saturations calculated. Samples were then reloaded into the multi-sample cell, confining pressure was applied and each sample connected to a syringe pump and desaturated at the same flow rate as in the previous test. 3.4. NMR measurements The NMR T2 relaxation measurements were performed in a Resonance Instruments MARAN 2 spectrometer at ambient pressure and 34.0 jC and at
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different brine saturations. The parameter settings for the CPMG pulse sequence used for the sandstone samples are summarised in Table 2. The resulting echo-train from the CPMG pulse consists of a continuous distribution of T2 values each with different signal amplitudes. It is mathematically difficult to recover the data by fitting a continuous distribution of exponential decays. A method to simplify this problem is to select a predetermined number of T2 values over a specified time range (usually evenly spaced in logarithmic time), and fit the echo-train using these values, to calculate the signal amplitude associated with each one, known as multi-exponential decomposition process. The DXP software from Resonance Instruments was used to obtain T2 distributions from the CPMG echo-train data. The software is based on a procedure called zeroth order regularisation, more details of which can be found in Press et al. (1992). The T2 cutoff is used to define a transition point between mobile and capillary bound water. This value depends on the pore structure and surface relaxivity, which is influenced by the fluid– solid interactions. Use of a single cutoff implies pores below a certain size are considered completely saturated. T2 cutoff can be determined in the laboratory by obtaining the T2 distribution at two saturations, fully brine saturated and irreducible water saturation. The T2 cutoff is defined as the relaxation time at the point where the cumulative porosity of the fully saturated sample equals the irreducible water saturation when air is used as the displacing phase: Swirr ¼
T2 X cutoff
AðT2 Þ
ð1Þ
T2 ¼0:1 ms
where A is the signal amplitude in the brine saturated T2 distribution and Swirr is the irreducible water saturation after desaturation to end point. Table 2 Parameter settings for NMR CPMG pulse sequence Frequency (MHz) Number of scans s (As) Recycle delay (s) Number of echos P90 (As) P180 (As)
2.2 100 200 10 8000 14.8 29.6
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4. Results 4.1. Desaturation by continuous injection and resistivity Archie’s equations are often used to relate the resistivity of partially brine saturated reservoir rocks to porosity and saturation. The wettability of the rock will have an effect on the resistivity because it controls the spatial distribution of the oil and the conducting brine phase at pore level. Thus, although it is affected by many factors, the Archie saturation exponent can give an indication of the rock wettability especially if the measurements are performed on the same samples before and after aging. Previous studies have shown that the Archie saturation exponent increases with increased oil-wet nature of the rock surface (Donaldson and Siddiqui, 1987; Lewis et al., 1988; Moss et al., 1999). This exponent can be obtained as the slope from a log –log plot of resistivity index as a function of water saturation. The resistivity index as a function of saturation for samples 35 and 40 are shown in Fig. 2a,b. During oil injection in the cleaned sample 35 the saturation exponents range from 1.60 to 1.62, from Sw = 1.00 to 0.34 (Fig. 2a). After aging, the saturation exponent increases to 1.95 –2.65 at saturations between 0.48 and 0.77. The non-linearity of saturation exponents has been noted in previous studies and attributed
to various physical mechanisms (Diederix, 1982; Longeron et al., 1989; Moss et al., 1999). The aging causes similar changes for sample 40, but with a larger increase in saturation exponent (see Fig. 2b). The increase of the saturation exponent values for the aged sample is due to wettability alteration by the crude oil. The Amott-Harvey wettability index for measurements on an adjacent core plug indicated that the cleaned sample was still weakly oil-wet and aging produced a more oil-wet sample, strongly oil-wet according to the Amott-Harvey index (see Table 3). Another indication of the wettability change is the increase of the irreducible water saturation between primary and secondary drainage. Aging has rendered some of the surfaces within the samples oil-wet thus changing the fluid distribution at pore scale. Different components of the electrical path control the resistivity behaviour (Grattoni and Dawe, 1998). At a given brine saturation, the aged samples contains fewer continuous brine pathways thus the resistivity index increases after aging. Note that the aging process will preferentially change the wettability of the larger pores occupied by oil but it might not change the wettability of the microporous regions within the sample, as they are occupied by water. This effect has been modelled by Man and Jing (2001) using a network model and the changes in resistivity index calculated are similar to those presented here.
Fig. 2. Resistivity index as a function of water saturation for primary and secondary drainage (after aging), during oil continuous injection for samples 35 and 40.
S.H. Al-Mahrooqi et al. / Journal of Petroleum Science and Engineering 39 (2003) 389–398 Table 3 End point saturations and Amott-Harvey wettability index (AHI) Sample ID
Irreducible water saturation
Residual oil saturation
Water index (IW)
Oil index (IO)
Amott-Harvey index (IW IO)
35 40 94
0.483 0.382 0.273
0.121 0.149 0.237
0.03 0.03 0.23
1.00 1.00 0.54
0.97 0.97 0.22
Strongly water-wet, AHI = 0.3 to 1.0; weakly water-wet, AHI = 0.0 to 0.3; weakly oil-wet, AHI = 0.0 to 0.3; strongly oil-wet, AHI = 0.3 to 1.0.
4.2. NMR measurements 4.2.1. T1 and T2 distributions on fully brine saturated samples The T1 and T2 distributions, normalised to porosity, for sample 94 after cleaning and fully saturated with brine are plotted in Fig. 3. T2 distributions for cleaned and water saturated the cores 94, 40 and 35 are shown in Figs. 4a, 5a and 6a, respectively. It can be observed in Fig. 3 that both T1 and T2 distributions are very similar. The sample was desaturated by gas at 689 kPa in a porous plate cell and the T2 cutoff was determined using Eq. (1). This sample has a smaller proportion of capillary bound water and lower irreducible water saturation than sample 35 (Fig. 6a). The presence of clays (mainly illite) also leads to lower permeability for sample 35 and a shift of the mean T2 time to lower values. Additionally, samples 40 and 94
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present grain dissolution, which results in enhanced secondary porosity and permeability as well as larger T2 cutoff. The peak and the distributions for longer times, above the cutoff, is almost the same for T1 and T2 for all the samples. The measurement of T2 is faster than T1 and is the most common logging NMR measurement; thus, the rest of this paper focuses on T2 data. 4.2.2. T2 on samples saturated with oil and water Two-phase, oil and water, NMR T2 measurements were performed at irreducible/residual saturations and after spontaneous imbibition/drainage during Amott wettability measurements. Fig. 4a,b shows the T2 distributions for sample 94 at different saturations. The cleaned sample was initially fully saturated with water. At irreducible water saturation, the signal from the oil is represented by the T2 distribution at longer times than the cutoff. The large long time peak has shifted to longer times, due to non-wetting oil. The water coating the larger, oil invaded pores, cause an increase in signal amplitude of the low time response for the sample at irreducible water saturation. At higher water saturation, the oil peak decreases proportionally to the change in oil saturation (Fig. 4b). The T2 distributions at different saturations and wettability states for sample 40 are shown in Fig. 5a,b. Two main distributions (components) can be observed after aging. The distribution at shorter times corresponds to water contained in the smaller pores, as the aging
Fig. 3. T1 and T2 distributions for sample 94, cleaned and fully water saturated. The vertical line is the T2 cutoff.
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Fig. 4. T2 distributions for sample 94 at different water saturations. The vertical line is the T2 cutoff and the shadowed area is the T2 distribution for bulk oil. All the measurements were performed after cleaning.
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 (Fig. 5b), it can be noted that the long time peak decreases, it becomes wider and it is displaced to longer times. During 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 T2 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 in sample 40, the microporous regions remain water-wet while the larger
pores are oil-wet, which is confirmed by the saturation exponents obtained after aging (2.52 – 3.38) (Fig. 2b). On the other hand, according to the Amott-Harvey index (Table 3), after aging, the sample is strongly oilwet. Sample 35 has a low permeability (10 mD), due to clays blocking the pore space, and it presents a different T2 distribution. The fully saturated T2 distribution has a larger component at shorter times (Fig. 6a), which is reflected in a larger irreducible water saturation. After aging, the oil and water components have similar behaviour to sample 40. Although the signal of the long time peak decreases after spontaneous and forced imbibition (Fig. 6b), it is not displaced to longer times, suggesting that the water imbibed and injected during forced displacement
Fig. 5. T2 distributions for sample 40 at different water saturations. The shadowed area is the T2 distribution for bulk oil. All the measurements were performed after aging with the exception of Sw = 1.0, which was performed after cleaning.
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Fig. 6. T2 distributions for sample 35 at different water saturations. The shadowed area is the T2 distribution for bulk oil. All the measurements were performed after aging with the exception of Sw = 1.0, which was performed after cleaning.
behaves as a wetting fluid. However, as it can be observed in Fig. 6, the distribution for the oil has an apparent shift to shorter times compared to bulk oil. This faster relaxation may indicate that some surface relaxation occurs between the oil and the clays. Thus, this sample can be also classified as mix-wet with brine in the clays partially shielded from the bulk brine by a film of oil on the surface of the clays. This observation agrees with the electrical resistivity measurements as a lower increase in saturation index was observed indicating that aging has rendered a smaller proportion of surfaces oil-wet (Fig. 2a). However, this observation does not agree with the Amott-Harvey index, which indicates a strongly oil-wet rock ( 0.97). The behaviour of this sample may be due the presence of pore lining clays, which keeps the quartz grains water-wet while the clay surfaces in contact with oil may become oil-wet. At residual oil saturation, the oil may be in the form of ganglia as well as globules attached to the clays, while the water fills the small pores, wets the quartz and some of the clay. A similar behaviour was noted by Zhang et al. (2000). Under this scenario, oil and water may have separated pathways. 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 T2 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, but fur-
ther experimental and pore-network modelling is needed.
5. Conclusions
For both cleaned and aged cores, the smaller pores seem to be always filled with water and have little variation in their signal at different saturation. An increase of signal of this component at lower water saturations indicates the presence of water in crevices and rough surfaces. The signal from the oil component, or peak at longer time in the T2 distribution, is proportional to the oil saturation. However, fluid identification is necessary if oil saturation is to be determined from T2 distributions as the water may also contribute to signal amplitude at longer times. In our experiments, aged samples present two separated peaks: one at shorter times related to smaller water-wet pores and another at longer times related to larger oil-wet pores, presenting a mix-wet behaviour. In aged cores, the peak at longer time widens as the water saturation increases, due to oil wetting the larger pores and water giving a bulk NMR response. The aged core that contained clays has both water and oil-wet pathways, thus when either oil or water saturation increase the fluid moves through its respectively wetted pore network and does not produce any NMR response similar to that of a non-wetting bulk fluid.
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The NMR results suggest that T2 distributions can provide valuable information regarding rock wettability, rock –fluid interactions and phase distributions. The development of this technique could provide a faster and reliable method for wettability determination. However, further experiments and pore-scale modelling are needed to establish a procedure that could be used for different rock types, fluids and all the range of water saturation.
Acknowledgements The experiments were performed in the BG Petrophysics Laboratory at Imperial College. The authors acknowledge the financial support from EPSRC. Sultan Al-Mahrooqi would like to thank Petroleum Development of Oman (PDO) for financial support and encouragement.
References Brown, R.J.S., Fatt, I., 1956. Measurements of fractional wettability of oilfield rocks by the nuclear magnetic relaxation method. Trans. AIME 207, 262 – 264. Buckley, J.S., 2001. Effective wettability of minerals exposed to crude oil. Curr. Opin. Colloid Interface Sci. 6, 191 – 196. Coates, G.R., Marschall, D., Mardon, D., Galford, J., 1997. A new characterisation of bulk-volume irreducible using magnetic Resonance. Advances in Petrophysics, 5 years of Dialog 1993 – 1997. London Petrophysical Society, London, pp. 128 – 140. Diederix, K.M., 1982. Anomalous relationships between resistivity index and water saturation in Rotliegend Sandstone (The Netherlands). Trans. SPWLA 23rd Annual Logging Symp. Paper X. Donaldson, E.C., Siddiqui, S.M., 1987. Relationship between the Archie saturation exponent and wettability. SPE 16790, 62nd SPE Annual Tech. Conf. and Exhibition, Dallas, TX. Freedman, R., Heaton, N., Flaum, M., 2001a. Field applications of a new nuclear magnetic resonance fluid characterisation method. SPE 71713, SPE Annual Tech. Conf. and Exhibition, New Orleans, LA.
Freedman, R., Lo, S., Flaum, M., Hirasaki, G.J., Matteson, A., Sezginer, A., 2001b. A new NMR method of fluid characterization in reservoir rocks: experimental confirmation and simulation results. SPE J. 6, 452 – 464. Gogolashvili, E., 1996. Wettability and T1 proton relaxation times of sandstones rocks. Magn. Reson. Imaging 14, 1003 – 1005. Grattoni, C.A., Dawe, R.A., 1998. The effect of multiphase spatial distribution within porous media on electrical resistivity. Log Analyst 39, 47 – 59. Howard, J.J., 1994. Wettability and fluid saturations determined from NMR T1 distributions. Magn. Reson. Imaging 12, 197 – 200. Howard, J.J., 1998. Quantitative estimates of porous media wettability from proton NMR measurements. Magn. Reson. Imaging 16, 529 – 533. Hsu, W.F., Li, X., Flumerfelt, R.W., 1992. Wettability of porous media by NMR relaxation methods. SPE 24761, 67th Annual Tech. Conf. and Exhibition, Washington, DC. Lewis, M.G., Sharma, M.M., Dunlap, H.F., Dorfman, M.H., 1988. Techniques for measuring the electrical properties of sandstone cores. SPE 18178, 63rd SPE Annual Tech. Conf. and Exhibition, Houston, TX. Longeron, D.G., Argaud, M.J., Feraud, J.P., 1989. Effect of overburden pressure, nature and microscopic distribution of fluids on electrical properties of rock samples. SPE Form. Eval. 4, 194 – 202. Man, H.N., Jing, X.D., 2001. Network modelling of strong and intermediate wettability on electrical resistivity and capillary pressure. Adv. Water Resour. 24, 345 – 363. Moss, A.K., Jing, X.D., Archer, J.S., 1999. Laboratory investigation of wettability and hysteresis effects on resistivity index and capillary pressure characteristics. J. Pet. Sci. Eng. 24, 231 – 242. Oren, P.E., Ruesla˚tten, H.G., Skjetne, T., Buller, A.T., 1994. Some advance in NMR characterisation of reservoir sandstones. North Sea Oil and Gas Reservoirs, vol. III. Kluwer Academic Publishers, pp. 307 – 316. Press, W.H., Teukolsky, W.T., Vetterling, W.T., Flannery, B.P., 1992. Numerical Recipes in FORTRAN 77, 2nd ed. Cambridge Univ. Press, Cambridge. ISBN 0-521-43064-1. Saraf, D.N., Kumar, J., Fatt, I., 1970. Determination of wettability of porous materials by the nuclear magnetic resonance technique. Indian J. Technol. 8, 125 – 130. Zhang, G.Q., Huang, C.C., Hirasaki, G.J., 2000. Interpretation of wettability in sandstones with NMR analysis. Petrophysics 41, 223 – 233.
An investigation of the effect of wettability on NMR characteristics of sandstone rock and fluid systems S.H. Al-Mahrooqi a, C.A. Grattoni a,*, A.K. Moss b, X.D. Jing a,1 b
a Department of Earth Science and Engineering, Imperial College London, Prince Consort Road, London SW7 2BP, UK Applied Reservoir Technology (ART), Unit 4B, The Birches Industrial Estate, Imberhorne Lane, East Grinstead, West Sussex RH19 1XY, UK
Received 12 March 2002; received in revised form 21 October 2002
Abstract Predicting reservoir wettability and its effect on fluid distribution and hydrocarbon recovery remains one of the major challenges in reservoir evaluation and engineering. Current laboratory based techniques require the use of rock – fluid systems that are representative of in situ reservoir wettability and preferably under reservoir conditions of pressure and temperature. However, the estimation of reservoir wettability is difficult to obtain from most laboratory experiments. In theory, it should be possible to determine the wettability of reservoir rock – fluid systems by nuclear magnetic resonance (NMR) due to the surfacesensitive nature of NMR relaxation measurements. Thus, NMR logs should in principle be able to give an indication of reservoir wettability, however, as yet 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. A series of systematic laboratory experiments were designed using a range of sandstone core plugs with the aim of investigating the feasibility of using NMR measurements as a means to determine wettability. NMR T2 spectrum measurements were performed in reservoir core plugs at different saturations and wettability states. The samples were first cleaned by hot solvent extraction, then saturated with brine and a drainage/imbibition cycle performed. At the lowest brine saturation the same samples were aged in crude oil and a further drainage/imbibition cycle performed. NMR transverse relaxation time, T2, was measured on fully saturated samples, at residual saturations and some intermediate saturation values. The wettability of the samples is evaluated using the Archie’s saturation exponent and by Amott-Harvey wettability index. The wettability of the cores studied ranged from mixed-wet to oil-wet. The NMR T2 results for cleaned and aged reservoir core plugs, containing oil and water, show that fluid distribution and wettability can be deduced from such measurements. The results on aged core plugs suggest that the oil occupies a wide range of pore sizes and is in contact with the pore walls. The results presented in the paper suggest that NMR T2 relaxation has the potential to be an alternative technique to evaluate rock wettability in the laboratory and in the reservoir. D 2003 Elsevier Science B.V. All rights reserved. Keywords: Wettability; Saturation; Electrical resistivity; NMR; T2 distribution
* Corresponding author. Fax: +44-207-594-7444. E-mail addresses: [email protected] (S.H. Al-Mahrooqi), [email protected] (C.A. Grattoni), [email protected] (A.K. Moss), [email protected] (X.D. Jing). 1 Currently with Shell International Exploration and Production, Rijswijk, The Netherlands. 0920-4105/03/$ - see front matter D 2003 Elsevier Science B.V. All rights reserved. doi:10.1016/S0920-4105(03)00077-9
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1. Introduction Nuclear magnetic resonance (NMR) measurements on reservoir core samples are performed to obtain an improved interpretation of NMR log data. The estimation of petrophysical properties is significantly improved if the 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 T1 and T2 spectra. NMR is a non-invasive technique that can provide information about the pore structure, the amount of fluid in-situ and the interactions between the pore fluids and the rock. Thus, it could be used as a fast and relatively easy method for determining wettability. The development of a downhole wettability measurement technique could provide vital information to improve reservoir characterisation and performance predictions. 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. Thus, NMR measurements should allow the evaluation of wettability. Numerous researchers have explored the link between wettability and NMR relaxation measurements. However, the majority of the studies were performed under conditions that are not representative of oil reservoirs. Brown and Fatt (1956) conducted the earliest study on water-saturated sand packs and measured the spin-lattice relaxation time T1 on five sand packs, made from different mixtures of clean and Dri-filmtreated sand. They found that the inverse of the water relaxation time, T1, increased linearly with the percentage of oil-wet sand. Similar behaviour was observed by Saraf et al. (1970) for water-saturated bead-packs composed of glass beads (water-wet) and polymer beads (oil-wet). Although the relaxation time of fully saturated media is proportional to the affinity of the fluid to the rock surface, this is of limited application to laboratory studies of oil reservoirs where oil and water are present. Hsu et al. (1992) used NMR relaxation experiments to study the wettability of fully water saturated beadpacks, limestones and dolomites. They concluded that proton relaxation measurements are
able to distinguish water-wet from oil-wet surfaces. However, T1 is strongly affected by the surface paramagnetic impurities. A good agreement was found between the wetting behaviour obtained from NMR relaxation and from a combined Amott/USBM method. Oren et al. (1994) conducted NMR studies on sandstones containing oil and water. NMR T1 measurements were performed at various saturations during low rate imbibition displacements for both water-wet and intermediate-wet cores. They analysed the relaxation time using a multiexponential model with two or three exponential terms. For fully saturated water-wet rocks, they found that rock – fluid interactions are stronger when water rather than oil occupies the pore space, which increases surface relaxation strength and hence shortens the relaxation time. They concluded that for water-wet samples, the intensity of the longest T1 component correlates with oil saturation and that the oil distribution at residual saturation could be inferred from NMR measurements. Howard (1994, 1998) studied the influence of wettability on the NMR response for chalk samples. NMR T1 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. (2000) studied the effect of oil type (refined and crude oil) on residual oil saturation, Amott wettability index and NMR T1 measurements for three types of sandstones. Two sandstones showed water-wet characteristics with refined oil, but became mixed-wet after aging them in crude oil. They concluded that NMR measurements are an effective tool for analysing wettability alteration. Freedman et al. (2001a,b) performed NMR experiments in sandstones, limestone and Dolomite containing brine and refined or crude oil. CMPG data suites were acquired under a constant magnetic field gradient and the data analysed with the multifluid relaxational model, which allows the identification of the fluids within the rock. This method was used to accurately obtain total porosity, fluid saturation and oil viscosities.
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Most published NMR studies into rock wettability have focused on the spin-lattice relaxation time T1. However, significant advances in NMR techniques have improved NMR measurements and currently most NMR laboratory instruments and logging tools are able to process the NMR signals into T1 and T2 relaxation time distributions. The measurement of T2 relaxation is preferred as it is faster and usually provides similar distributions to T1. This paper aims to relate traditional NMR T2 measurement to wettability for partially brine saturated sandstones. The studies have been performed on cleaned and aged reservoir cores. The wettability characteristics of the samples and the T2 distribution have been linked with their electrical behaviour and Amott-Harvey wettability index tests.
2. NMR theory 2.1. Single phase response NMR T2 relaxation is usually measured using the Carr-Purcell-Meiboom-Gill (CPMG) pulse sequence The CPMG echo train comprises a 90j pulse, followed by a train of 180j pulses. This pulse sequence eliminates dephasing effects produced by local variations in the magnetic field and therefore measures the true T2 of the sample. Therefore, the signal decay is due to interactions with neighbouring spins and surfaces. The CPMG pulse sequence takes only a few seconds to run, which makes it practical both in the laboratory and for well logging applications. For fluids within a rock three independent relaxation mechanisms occur: (1) bulk relaxation which is an intrinsic property of the fluid, (2) surface relaxation at the fluid– solid interface and (3) 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, the relaxation time is shorter for the fluid with more interaction with the pore walls (Oren et al., 1994; Gogolashvili, 1996).
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In the fast diffusion limit, the relaxation time observed experimentally is an average relaxation time for all the nuclei in the pores. Therefore, in a small pore, the nuclei are more likely to interact with the surface, and so the average relaxation time will be faster (shorter) than in a large pore. For a fully saturated sample, each pore-size has a distinctive T2 value, which is proportional to the surface to volume ratio. The echo-train corresponding to one particular pore-size will have a characteristic T2 value and signal amplitude proportional to the amount of fluid contained in all the pores of that size. The resulting echotrain therefore consists of a continuous distribution of T2 values each with different signal amplitudes. 2.2. Two phase response Air– water systems are commonly used to define the boundary between free and bound fluid within the T2 distribution, this is known as the T2 cutoff. The analysis of such systems is relatively easy as there is no NMR response from the air and the T2 relaxation is exclusively due to the protons in the water. At irreducible water saturation, all the water is capillary-bound and the corresponding T2 distribution represents the range of pore sizes containing this immobile water as shown in Fig. 1. Some very short T2 values may also result from water in pendular rings, crevices and roughness in the pore surfaces, which appear as an increase in the signal amplitude at short T2 times when compared with the fully saturated signal (Coates et al., 1997).
Fig. 1. Typical NMR T2 distribution for a sandstone. The components of capillary bound water are shown.
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For cores containing oil and water, the interpretation of the T2 distribution becomes more complex. In strongly water-wet rocks, the wetting films prevent the oil from interacting with the pore surfaces. The T2 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 T2 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 T2 distribution at different saturations, the wettability of the rock fluid system can be deduced. The magnitude of the T2 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.
3. Test procedures Sandstone samples from a North Sea reservoir were selected for this study. Table 1 shows the petrophysical data for these samples. The samples were cleaned as described in next section and samples 35 and 40 were aged. 3.1. Sample preparation The samples are 3.8 cm in diameter and 4.5 –5.0 cm in length. All samples originally contained crude oil, which was cleaned from the pore space by Soxhlet extraction using a chloroform/methanol azeotrope Table 1 Petrophysical properties of the cleaned reservoir samples Sample Klinkenberg Porosity Grain Formation Cementation ID permeability (%) density factora exponenta (mD) (g/cc) 35 40 94
10 516 564 a
20.4 23.2 21.3
2.65 2.65 2.65
24.9 17.6 16.9
Measured at a confining pressure of 15.86 MPa.
1.95 1.92 1.75
(12.6% methanol and 87.4% chloroform boiling at 53 jC) for a week, then they were further cleaned by using hot refluxing methanol (boiling point = 64.5 jC). Each sample was placed in a saturator and evacuated. The simulated formation brine, degassed and filtered to 0.45 Am, was then introduced under vacuum. The samples were left overnight under pressure. Complete saturation was verified using the dry weight, the saturated weight, helium pore volume and brine density. All samples attained full brine saturation. 3.2. Desaturation by continuous injection Fully brine-saturated samples were loaded into Viton rubber sleeves. A brine saturated capillary contact mat was placed at the ends of the sleeved sample and a water-wet ceramic disc (impermeable to oil below a threshold pressure of 1500 kPa) mounted at one end. Stainless steel flow platens and stems filled with brine were mounted at each end of the sample before loading them into a multi-sample test cell. The flow stems were insulated from the body of the cell so that the resistance across the sample, in the two-electrode configuration, could be measured. Confining pressure was applied in increments from 0.69 MPa to a maximum of 15.86 MPa. The downstream end of each sample was connected to a burette, allowing the measurement of the brine volume expelled from the samples during application of confining pressure and oil injection. Pore volume reduction was determined by measuring the volume of brine squeezed from the samples as the overburden pressure increased. The resistivity of the samples were monitored until they stabilised indicating that both ionic and pressure equilibrium had been achieved. Before oil injection, brine was flowed through the sample to ensure full saturation. The resistance of each sample was then recorded and the formation factors and cementation exponents calculated (Table 1). A mixture of light paraffin oils, trade name Multipar (density = 764 kg/m3 at 20 jC, viscosity = 1.13 mPa s at 20 jC), was injected into each sample by using dedicated slow rate syringe pumps. The continuous injection desaturation process is analogous to capillary pressure equilibrium desaturation if the flow rate is kept low and capillary force dominates. The flow rate used was less than 0.5 cm3/day, so desatura-
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tion of the samples takes about 20 days (depending on sample pore volume). Measurements of resistance, volume displaced and temperature were made each day. Temperature corrected resistivity index and saturations were then calculated. Brine saturations can be measured to an accuracy of 0.1% of pore volume. 3.3. Sample aging to change wettability Dead crude oil was used to induce wettability changes during aging. However, as the crude oil may contain some asphaltenes, which may induce wettability changes (Buckley, 2001), a stability test between crude oil and Multipar was performed. Ten mixtures of crude oil and Multipar with volume ratios 0.025 (1/40) to 0.8 (4/1) were prepared, stored at room temperature for 72 h and then filtered through a 0.22 Am Millipore filter. Then the filter was washed with 20 cm3 of pentane, dried in an oven at 50 jC and weighted. The amount of precipitated for all the mixtures was below the experimental error, 0.05%, indicating that the changes in wettability are not due to asphaltenes destabilization by the Multipar oil. After the lowest brine saturation was attained during the continuous injection; samples 35 and 40 were removed from the multi-sample cell and the Multipar test oil was replaced with dead crude oil from the same well as the samples. The samples were loaded in a pressure vessel and a pore pressure of 1.38 MPa applied. The samples were aged in an oven at 85 jC for 40 days. At the end of this period, the samples were cooled to room temperature, the pressure reduced to atmospheric and the crude oil in the pore space flushed out with the Multipar test oil. Each sample was then loaded in a Hassler cell and flooded with brine, reducing the oil volume down to residual oil saturation. Volumes of oil displaced were collected and the new brine saturations calculated. Samples were then reloaded into the multi-sample cell, confining pressure was applied and each sample connected to a syringe pump and desaturated at the same flow rate as in the previous test. 3.4. NMR measurements The NMR T2 relaxation measurements were performed in a Resonance Instruments MARAN 2 spectrometer at ambient pressure and 34.0 jC and at
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different brine saturations. The parameter settings for the CPMG pulse sequence used for the sandstone samples are summarised in Table 2. The resulting echo-train from the CPMG pulse consists of a continuous distribution of T2 values each with different signal amplitudes. It is mathematically difficult to recover the data by fitting a continuous distribution of exponential decays. A method to simplify this problem is to select a predetermined number of T2 values over a specified time range (usually evenly spaced in logarithmic time), and fit the echo-train using these values, to calculate the signal amplitude associated with each one, known as multi-exponential decomposition process. The DXP software from Resonance Instruments was used to obtain T2 distributions from the CPMG echo-train data. The software is based on a procedure called zeroth order regularisation, more details of which can be found in Press et al. (1992). The T2 cutoff is used to define a transition point between mobile and capillary bound water. This value depends on the pore structure and surface relaxivity, which is influenced by the fluid– solid interactions. Use of a single cutoff implies pores below a certain size are considered completely saturated. T2 cutoff can be determined in the laboratory by obtaining the T2 distribution at two saturations, fully brine saturated and irreducible water saturation. The T2 cutoff is defined as the relaxation time at the point where the cumulative porosity of the fully saturated sample equals the irreducible water saturation when air is used as the displacing phase: Swirr ¼
T2 X cutoff
AðT2 Þ
ð1Þ
T2 ¼0:1 ms
where A is the signal amplitude in the brine saturated T2 distribution and Swirr is the irreducible water saturation after desaturation to end point. Table 2 Parameter settings for NMR CPMG pulse sequence Frequency (MHz) Number of scans s (As) Recycle delay (s) Number of echos P90 (As) P180 (As)
2.2 100 200 10 8000 14.8 29.6
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4. Results 4.1. Desaturation by continuous injection and resistivity Archie’s equations are often used to relate the resistivity of partially brine saturated reservoir rocks to porosity and saturation. The wettability of the rock will have an effect on the resistivity because it controls the spatial distribution of the oil and the conducting brine phase at pore level. Thus, although it is affected by many factors, the Archie saturation exponent can give an indication of the rock wettability especially if the measurements are performed on the same samples before and after aging. Previous studies have shown that the Archie saturation exponent increases with increased oil-wet nature of the rock surface (Donaldson and Siddiqui, 1987; Lewis et al., 1988; Moss et al., 1999). This exponent can be obtained as the slope from a log –log plot of resistivity index as a function of water saturation. The resistivity index as a function of saturation for samples 35 and 40 are shown in Fig. 2a,b. During oil injection in the cleaned sample 35 the saturation exponents range from 1.60 to 1.62, from Sw = 1.00 to 0.34 (Fig. 2a). After aging, the saturation exponent increases to 1.95 –2.65 at saturations between 0.48 and 0.77. The non-linearity of saturation exponents has been noted in previous studies and attributed
to various physical mechanisms (Diederix, 1982; Longeron et al., 1989; Moss et al., 1999). The aging causes similar changes for sample 40, but with a larger increase in saturation exponent (see Fig. 2b). The increase of the saturation exponent values for the aged sample is due to wettability alteration by the crude oil. The Amott-Harvey wettability index for measurements on an adjacent core plug indicated that the cleaned sample was still weakly oil-wet and aging produced a more oil-wet sample, strongly oil-wet according to the Amott-Harvey index (see Table 3). Another indication of the wettability change is the increase of the irreducible water saturation between primary and secondary drainage. Aging has rendered some of the surfaces within the samples oil-wet thus changing the fluid distribution at pore scale. Different components of the electrical path control the resistivity behaviour (Grattoni and Dawe, 1998). At a given brine saturation, the aged samples contains fewer continuous brine pathways thus the resistivity index increases after aging. Note that the aging process will preferentially change the wettability of the larger pores occupied by oil but it might not change the wettability of the microporous regions within the sample, as they are occupied by water. This effect has been modelled by Man and Jing (2001) using a network model and the changes in resistivity index calculated are similar to those presented here.
Fig. 2. Resistivity index as a function of water saturation for primary and secondary drainage (after aging), during oil continuous injection for samples 35 and 40.
S.H. Al-Mahrooqi et al. / Journal of Petroleum Science and Engineering 39 (2003) 389–398 Table 3 End point saturations and Amott-Harvey wettability index (AHI) Sample ID
Irreducible water saturation
Residual oil saturation
Water index (IW)
Oil index (IO)
Amott-Harvey index (IW IO)
35 40 94
0.483 0.382 0.273
0.121 0.149 0.237
0.03 0.03 0.23
1.00 1.00 0.54
0.97 0.97 0.22
Strongly water-wet, AHI = 0.3 to 1.0; weakly water-wet, AHI = 0.0 to 0.3; weakly oil-wet, AHI = 0.0 to 0.3; strongly oil-wet, AHI = 0.3 to 1.0.
4.2. NMR measurements 4.2.1. T1 and T2 distributions on fully brine saturated samples The T1 and T2 distributions, normalised to porosity, for sample 94 after cleaning and fully saturated with brine are plotted in Fig. 3. T2 distributions for cleaned and water saturated the cores 94, 40 and 35 are shown in Figs. 4a, 5a and 6a, respectively. It can be observed in Fig. 3 that both T1 and T2 distributions are very similar. The sample was desaturated by gas at 689 kPa in a porous plate cell and the T2 cutoff was determined using Eq. (1). This sample has a smaller proportion of capillary bound water and lower irreducible water saturation than sample 35 (Fig. 6a). The presence of clays (mainly illite) also leads to lower permeability for sample 35 and a shift of the mean T2 time to lower values. Additionally, samples 40 and 94
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present grain dissolution, which results in enhanced secondary porosity and permeability as well as larger T2 cutoff. The peak and the distributions for longer times, above the cutoff, is almost the same for T1 and T2 for all the samples. The measurement of T2 is faster than T1 and is the most common logging NMR measurement; thus, the rest of this paper focuses on T2 data. 4.2.2. T2 on samples saturated with oil and water Two-phase, oil and water, NMR T2 measurements were performed at irreducible/residual saturations and after spontaneous imbibition/drainage during Amott wettability measurements. Fig. 4a,b shows the T2 distributions for sample 94 at different saturations. The cleaned sample was initially fully saturated with water. At irreducible water saturation, the signal from the oil is represented by the T2 distribution at longer times than the cutoff. The large long time peak has shifted to longer times, due to non-wetting oil. The water coating the larger, oil invaded pores, cause an increase in signal amplitude of the low time response for the sample at irreducible water saturation. At higher water saturation, the oil peak decreases proportionally to the change in oil saturation (Fig. 4b). The T2 distributions at different saturations and wettability states for sample 40 are shown in Fig. 5a,b. Two main distributions (components) can be observed after aging. The distribution at shorter times corresponds to water contained in the smaller pores, as the aging
Fig. 3. T1 and T2 distributions for sample 94, cleaned and fully water saturated. The vertical line is the T2 cutoff.
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Fig. 4. T2 distributions for sample 94 at different water saturations. The vertical line is the T2 cutoff and the shadowed area is the T2 distribution for bulk oil. All the measurements were performed after cleaning.
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 (Fig. 5b), it can be noted that the long time peak decreases, it becomes wider and it is displaced to longer times. During 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 T2 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 in sample 40, the microporous regions remain water-wet while the larger
pores are oil-wet, which is confirmed by the saturation exponents obtained after aging (2.52 – 3.38) (Fig. 2b). On the other hand, according to the Amott-Harvey index (Table 3), after aging, the sample is strongly oilwet. Sample 35 has a low permeability (10 mD), due to clays blocking the pore space, and it presents a different T2 distribution. The fully saturated T2 distribution has a larger component at shorter times (Fig. 6a), which is reflected in a larger irreducible water saturation. After aging, the oil and water components have similar behaviour to sample 40. Although the signal of the long time peak decreases after spontaneous and forced imbibition (Fig. 6b), it is not displaced to longer times, suggesting that the water imbibed and injected during forced displacement
Fig. 5. T2 distributions for sample 40 at different water saturations. The shadowed area is the T2 distribution for bulk oil. All the measurements were performed after aging with the exception of Sw = 1.0, which was performed after cleaning.
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Fig. 6. T2 distributions for sample 35 at different water saturations. The shadowed area is the T2 distribution for bulk oil. All the measurements were performed after aging with the exception of Sw = 1.0, which was performed after cleaning.
behaves as a wetting fluid. However, as it can be observed in Fig. 6, the distribution for the oil has an apparent shift to shorter times compared to bulk oil. This faster relaxation may indicate that some surface relaxation occurs between the oil and the clays. Thus, this sample can be also classified as mix-wet with brine in the clays partially shielded from the bulk brine by a film of oil on the surface of the clays. This observation agrees with the electrical resistivity measurements as a lower increase in saturation index was observed indicating that aging has rendered a smaller proportion of surfaces oil-wet (Fig. 2a). However, this observation does not agree with the Amott-Harvey index, which indicates a strongly oil-wet rock ( 0.97). The behaviour of this sample may be due the presence of pore lining clays, which keeps the quartz grains water-wet while the clay surfaces in contact with oil may become oil-wet. At residual oil saturation, the oil may be in the form of ganglia as well as globules attached to the clays, while the water fills the small pores, wets the quartz and some of the clay. A similar behaviour was noted by Zhang et al. (2000). Under this scenario, oil and water may have separated pathways. 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 T2 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, but fur-
ther experimental and pore-network modelling is needed.
5. Conclusions
For both cleaned and aged cores, the smaller pores seem to be always filled with water and have little variation in their signal at different saturation. An increase of signal of this component at lower water saturations indicates the presence of water in crevices and rough surfaces. The signal from the oil component, or peak at longer time in the T2 distribution, is proportional to the oil saturation. However, fluid identification is necessary if oil saturation is to be determined from T2 distributions as the water may also contribute to signal amplitude at longer times. In our experiments, aged samples present two separated peaks: one at shorter times related to smaller water-wet pores and another at longer times related to larger oil-wet pores, presenting a mix-wet behaviour. In aged cores, the peak at longer time widens as the water saturation increases, due to oil wetting the larger pores and water giving a bulk NMR response. The aged core that contained clays has both water and oil-wet pathways, thus when either oil or water saturation increase the fluid moves through its respectively wetted pore network and does not produce any NMR response similar to that of a non-wetting bulk fluid.
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The NMR results suggest that T2 distributions can provide valuable information regarding rock wettability, rock –fluid interactions and phase distributions. The development of this technique could provide a faster and reliable method for wettability determination. However, further experiments and pore-scale modelling are needed to establish a procedure that could be used for different rock types, fluids and all the range of water saturation.
Acknowledgements The experiments were performed in the BG Petrophysics Laboratory at Imperial College. The authors acknowledge the financial support from EPSRC. Sultan Al-Mahrooqi would like to thank Petroleum Development of Oman (PDO) for financial support and encouragement.
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