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Experimental artifacts caused by wettability variations in chalk
Journal of Petroleum Science and Engineering 33 (2002) 49 – 59 www.elsevier.com/locate/jpetscieng
Experimental artifacts caused by wettability variations in chalk E.A. Spinler a,*, B.A. Baldwin a,1, A. Graue b,2 a
Phillips Petroleum Co., Phillips Research Center, Bartlesville, OK, 74004, USA b University of Bergen, USA
Abstract Alteration of the wettability is often a part of the restoration process for core plugs or used to obtain a desired wettability in outcrop plugs. If the procedure does not provide a uniform wettability state in the plug, experimental artifacts can result. For immersion under crude oil to alter wettability, it was observed that the wettability distribution in a chalk plug was nonuniform. Capillary pressure curves by the direct measurement of saturation method were used to determine the wettability variation within the plug. This plug did not imbibe water because its exterior was rendered almost oil-wet, while the interior remained strongly water-wet. Similarly, for preparation methods that flow crude oil into a plug, the wettability could vary from the end of the sample to the interior or to the other end. The distribution of water and oil in the plug from a subsequent waterflood would then vary with the pressure imposed by the flow direction. Consequently, a forced displacement waterflood could recover different amounts of oil depending upon the direction of the waterflood. A neural net was used to capture the behavior of forced displacement for various wettabilities from measured capillary pressure curves and then used to predict waterflood results. D 2002 Elsevier Science B.V. All rights reserved. Keywords: Wettability; Spontaneous imbibition; Forced imbibition; Wettability alteration; Capillary pressure
1. Introduction Crude oil is commonly used to restore the wettability of reservoir core material or to alter the wettability of outcrop rock to a desired state for further laboratory measurements (Cuiec, 1975; Anderson, 1986a,b; Buckley, 1996). Practices often cite that the resultant wettability is primarily a function of the water saturation present in the rock, the crude oil properties, *
Corresponding author. Fax: +1-918-662-5315. E-mail addresses: [email protected] (E.A. Spinler), [email protected] (B.A. Baldwin), [email protected] (A. Graue). 1 Retired from Phillips Petroleum. 2 Fax: +1-47-55-58-94-40.
the aging time and temperature. Other important variables are the rock properties and the brine composition. Alternate methods include flowing of the crude oil into the rock followed by immersion in the crude or flowing continuously/periodically to freshen the crude oil in the rock. Sometimes, the flow direction is reversed. Aging is often performed at elevated temperature for a predetermined period of time. It is normally assumed that the wettability of the altered or restored rock is uniform. This is not always the case since nonuniform wettability from rock preparation methods has been observed by the authors and others (Spinler et al., 1999; Graue et al., 2000; Standnes and Austad, 2000). The purpose, herein, is to examine the possible impact that nonuniform wettability from restoration/
0920-4105/02/$ - see front matter D 2002 Elsevier Science B.V. All rights reserved. PII: S 0 9 2 0 - 4 1 0 5 ( 0 1 ) 0 0 1 7 5 - 9
50
E.A. Spinler et al. / Journal of Petroleum Science and Engineering 33 (2002) 49–59
Table 1 Properties of portland chalk plug CP-4 Length (cm) Diameter (cm) Porosity (%) Absolute Permeability (mD)
3.72 3.81 48 4
wettability alteration methods may have on some common laboratory experiments.
2. Equipment, material, methods The investigated rock sample, designated CP-4, was a low permeability, high porosity Portland outcrop chalk. Its properties are listed in Table 1. Preparation consisted of drying and saturating with brine (5% sodium chloride and 3.8% calcium chloride by weight in deionized water.) The sample was flushed with reservoir oil at 90j C to an initial water saturation (Swi) of
20% and then aged under that oil at 90 jC for 50 days to alter the wettability. After aging, the reservoir oil was replaced by flow at 90 jC with decalin followed by n-decane. 3-D spontaneous imbibition was conducted at 20 jC for 1000 h followed by forced displacement at a flow rate of 34 ml/h to determine an Amott water index for wettability. The Amott water index (Amott, 1959; Anderson, 1986a,b), Iw, is defined as ratio of the water volume displaced by spontaneous imbibition of water to the total water volume displaced by both spontaneous and forced imbibition of water. The plug was restored by flow to Swi with octadecane at about 35 jC to replace the n-decane. Octadecane has a melting point of 27 jC and when solidified, it is invisible to magnetic resonance imaging (MRI). The liquid brine does image and that allows determination of the water local saturations within the plug from image intensities. The direct measurement of saturation method (Spinler and Baldwin, 1997) was used to obtain the Swi distribution (Fig. 1) and imbibition capillary
Fig. 1. Initial water saturation map from MRI image. Adjacent shades represent 2% Sw difference.
E.A. Spinler et al. / Journal of Petroleum Science and Engineering 33 (2002) 49–59
pressure ( Pc) curves for wettability. To determine Pc, a centrifuge with a swinging bucket was used to develop the saturation profiles in the rock plugs. The sample was heated and cooled while centrifuging, respectively, to melt and solidify the octadecane. The solid octadecane eliminated redistribution by fixing the spatial position of fluids within the plug for subsequent MRI images outside of the centrifuge. Therefore, the water saturation distribution developed at approximately 35 jC in the centrifuge were determined from the image intensities measured outside the centrifuge at f 20 jC. Once the capillary pressure information was obtained, the plug was dried in a vacuum oven at about 70 jC to remove all fluids (The brine had been viscously displaced by fresh water to remove the salts.) The plug was saturated 100% with n-decane for porosity determination. Image intensity from MRI was used to obtain values of porosity for each pixel position within the plug image (Fig. 2). Brighter
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intensity meant more n-decane at that location within the plug and consequently more porosity; lower intensity meant less porosity. The porosity was calculated by assuming that the average intensity for the plug image was equal to the gravimetrically measured average plug porosity. The left side of plug image (Fig. 2) contained calculated porosity generally greater than the average of 48% and the right side of the plug image contained porosity of generally less than 48%. Images were obtained with a Varian 85/310 CSI. It has a 31 cm bore, 2 T superconducting magnet and operates at 85.55 MHz for hydrogen protons. A 9 cm I.D. saddle coil was used as both transmitting and receiving coil. The amount of fluid hydrogen protons was obtained using the Hahn spin-echo sequence with a 4 ms echo time and a 2.0 s recovery time. One slice, approximately 4 mm thick, was obtained through the center axis of the plug. This orientation produced a rectangle that shows the saturation gradient aligned
Fig. 2. Porosity map from MRI image at 100% n-decane saturation. Adjacent shades represent 1% / difference.
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E.A. Spinler et al. / Journal of Petroleum Science and Engineering 33 (2002) 49–59
parallel to the centrifugal axis. The field of view was 9 8 cm with a pixel resolution of 0.52 0.62 mm with 16 repetitive measurements averaged per each pixel. The images consisted of 255 levels of gray in a 256 256 display. The intensity of the individual pictures was adjusted to produce a presentable visual display; however, absolute intensities were used for quantitative determinations. A neural net was used to determine equilibrium saturation profiles in a model of a hypothetical sample with properties similar to the plug previously described. The neural net had four inputs, one hidden layer of two nodes and one output. Input data consisted of wettability, porosity, Swi, and capillary pressure ( Pc). Output was water saturation (Sw). Training was performed with data obtained from plug CP-4 by direct measurement of saturation.
3. Results and discussion 3.1. Wettability determination To determine Pc behavior, the plug CP-4, starting at an average Swi of about 25%, was centrifuged under brine and octadecane at 35 jC until apparent capillary equilibrium was reached after about 2 weeks. The resultant image (Fig. 3) displayed the fluid distribution for both spontaneous and forced imbibition relative to the free water level. There were no radial artifacts from the centrifugal field since the image represented only a 4-mm-thick slice that was orientated parallel to the centrifuge axis. A fracture is visible in the image slightly to the left of center. This fracture occurred during the centrifuging, but did not affect the analysis. The brightest areas outside of the plug represented free
Fig. 3. MRI image of water saturation distribution after centrifuging. Each shade represents 5% Sw change. Lines with litter identify location of data for Pc curves.
E.A. Spinler et al. / Journal of Petroleum Science and Engineering 33 (2002) 49–59
water and its uppermost edge was the free water level boundary with the octadecane. The free water level was also observed in the fracture. An unusual feature of the fluid distribution was the apparent concave, downward from the center, shape of the saturation distributions within the plug from one side to other side. This feature suggested that the Pc behavior within the plug varied from the interior to the edges. To evaluate this anomaly required that each column of pixels making up the image be evaluated separately. Spontaneous and forced imbibition capillary pressure curves were determined for different positions within
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the plug (Fig. 4a to f) indicated by the vertical lines on the shaded contour map of Fig. 3 and assigned a twoletter curve identifier for tracking. (A Pc determination along the edge of the plug was not obtainable because the MRI software transforms and the high signal contrast between the plug interior as well as the free water intensity compromised measurements near the sides.) Capillary pressure was zero, by definition, at the free water level so it was possible to obtain the saturations (Table 2 and Fig. 5) necessary to calculate an Amott water index (Fig. 6) from each Pc curve. These capillary pressure curves showed that the appa-
Fig. 4. (a) Imbibition Pc curve at position BK near left edge of MRI image in Fig. 3, showing moderate water-wet behavior. (b) Imbibition Pc curve at position CA on the left side of MRI image in Fig. 3, showing water-wet behavior. (c) Imbibition Pc curve at position CQ left of fracture in MRI image in Fig. 3, showing strong water-wet behavior. (d) Imbibition Pc curve at position DN in center of MRI image in Fig. 3, showing strong water-wet behavior. (e) Imbibition Pc curve at position EK on the right side of MRI image in Fig. 3, showing water-wet behavior. (f) Imbibition Pc curve at position FM near right edge of MRI image in Fig. 3, showing moderate water-wet behavior.
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E.A. Spinler et al. / Journal of Petroleum Science and Engineering 33 (2002) 49–59
Table 2 Saturations used for Amott water index Curve identifier
BK
CA
CQ
DN
EK
FM
Swi Swf Swff Calculated Iw Pixel position
0.23 0.49 0.72 0.53 9
0.26 0.60 0.69 0.79 25
0.26 0.66 0.68 0.95 41
0.28 0.65 0.66 1.00 64
0.28 0.63 0.67 0.88 87
0.25 0.50 0.72 0.53 115
1
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rent wettability of the plug varied from strongly waterwet at the center to less water-wet near the edges. Standnes and Austad (2000) experimentally observed oil coloration in cleaved plugs (wettability was altered in a similar manner), indicating the same type of wettability variation as determined herein. Recognizing that the wettability was also likely affected from the plug upper and lower ends, the capillary pressure curves were truncated at their top and bottom to examine only the influence of varying wettability perpendicular to the plug axis in the middle interior of the plug. Examination of the different shapes to the capillary pressure curves found them consistent with the calculated wettabilities. The more water-wet rock had higher capillary pressures above the free water level for any particular water saturation and had higher residual oil saturations further below the free water level. The variation of wettability observed within this plug was believed to be a result of the core preparation
Fig. 6. Wettability variation perpendicular to the axis of the plug as calculated from saturation data. Pc curve identifiers are from Fig. 3.
process. As previously described, the plug had been aged by immersion in crude oil after it had been flushed to initial water saturation with the same crude oil. Diffusion during the soaking process in crude oil probably altered the outside of the plug to a near neutral wet state while only altering the interior to the extent that the polar or other components of the crude further diffused or were forcibly displaced into the plug. The low permeability of the chalk would have exacerbated the wettability contrast between the plug interior and exterior by impeding the diffusion process. 3.2. Spontaneous imbibition effects
Fig. 5. The water saturations along the imbibition Pc curve data show behavior typical for wettability variations. Pc curve identifiers are from Fig. 3.
The consequences of this wettability variation on spontaneous imbibition of brine is apparent from the 3-D imbibition test conducted on the CP-4 plug (Fig. 7) when compared to other plugs as obtained from Graue et al. (1999). Included are the imbibition curves for a highly water-wet plug (CPA-1.5) and another plug (CP-13) with an apparent moderate wettability, Iw = 0.76. The average wettability for CP-4 is about the same as for CP-13; however, the imbibition rate behavior is dramatically different. Since some imbibition had occurred and allowed water into CP-4, it may be that with sufficient imbibition time, the spontaneous imbibition endpoint for CP-4 would be the same as for CP-13, with a uniform wettability.
E.A. Spinler et al. / Journal of Petroleum Science and Engineering 33 (2002) 49–59
Fig. 7. Measured imbibition curves for various apparent wettabilities from Graue et al. (1999). The affect of the wettability variation in plug CP-4 has reduced the imbibition rate compared to a plug of similar average wettability, CP-13.
3.3. Forced displacement effects An alternative to aging by immersion under crude oil is to flow, continuously or periodically, the crude oil through the plug for wettability alteration. Flowing crude oil to restore or alter the wettability of rock could also result in a nonuniform wettability distribution in chalk (Graue et al., 2000). That experimental work is not duplicated herein, but an examination of some of the consequences of a nonuniform wettability for flow tests can be estimated using the Pc data obtained from CP-4. The approach was to use a neural net trained to predict equilibrium water saturations for wettability ranging from Iw = 0.5 to 1 and for capillary pressures from 5 to 0 psi from the data of CP-4. The data range for training was extended slightly on each end of the pressures to improve the accuracy of the predictions. Excellent agreement was obtained between calculated and measured saturations (Fig. 8). The shape of the calculated Pc curves appeared to agree well with the data and typical Pc behavior (Fig. 9). A simple model with different cases of linear wettability variations in a rock was chosen (see Fig. 10) for ease of presentation. A slightly more complex case with a parabolic profile similar to that in Fig. 6 was also chosen and will be described separately from the linear cases. Predictions of saturation profiles for
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Fig. 8. The neural net match to model the Pc imbibition data between 5 and 1 psi is excellent.
any wettability variation are equally obtainable from the neural net. The increasing and decreasing wettability cases will allow a comparison of the consequences of water flooding in the same and opposite direction to the direction of wettability alteration created by a previous oil flood. The case of a uniform wettability will allow for comparisons of the varying wettability cases with the conventional assumption of uniform wettability. The properties of the model for the linear profiles are an average wettability of Iw = 0.75, a
Fig. 9. Neural net predicted imbibition Pc curves match the measured saturation data variation with Pc. The predicted curves from 5 to 0 psi display equilibrium saturation profiles for forced imbibition at different uniform wettabilities.
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E.A. Spinler et al. / Journal of Petroleum Science and Engineering 33 (2002) 49–59
Fig. 10. Three cases of different linear wettability variations along length with average Iw = 0.75. The fourth case has a parabolic wettability variation with average Iw = 0.84.
uniform porosity of 48% and a uniform initial water saturation of 23%. These properties were selected to be within the scope of the training for the neural net. Equilibrium saturation profiles for the three different linear wettability cases under different flooding scenarios are shown in Figs. 11– 13. The normalized length is arbitrary as only the inlet-to-outlet differential pressure and the wettability profiles are affecting the water saturations. It is obvious that the spontaneous imbibition endpoint saturation profiles of Fig. 11
Fig. 11. The neural net calculated saturation variation for spontaneous imbibition before flow for the linear wettability variations of Fig. 10.
should mimic the wettability profiles. The slight curvature is somewhat a consequence of having a uniform Swi with a varying Iw. At a differential pressure of 1 psi (Fig. 12) significant changes have occurred at the inlet were the greatest pressure change has occurred. At a pressure differential of 5 psi (Fig. 13), the decreasing water-wet and the uniform water-wet saturation profiles are similar, except for the outlet end. The saturation profile at 5 psi pressure differential for the increasing water-wet case appears similar to the other two cases for only the interior of the model. Another way to look at the equilibrium saturation profiles under different flooding scenarios is shown in Figs. 14 –16. The constant wettability (Fig. 14) case shows the typical end effect (defined as trapping of the oil in this case, the wetting fluid below Pc = 0) with changing flood pressures. All profiles were pinned at the outlet face to a saturation determined by the wettability of that face. In the decreasing waterwet case (Fig. 15), the magnitude of the outlet end effect was enhanced by the lower outlet wettability. For the increasing water-wet case (Fig. 16), there was no outlet end effect because the outlet was highly water-wet. The inlet shows a large variation in saturation. This behavior has been observed experimentally for an increasing water-wet case by Graue et al. (2000).
Fig. 12. The neural net calculated saturation variation for 1 psi inlet to outlet pressure differential for the linear wettability variations of Fig. 10.
E.A. Spinler et al. / Journal of Petroleum Science and Engineering 33 (2002) 49–59
Fig. 13. The neural net calculated saturation variation for 5 psi inlet to outlet pressure differential for the linear wettability variations of Fig. 10.
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Fig. 15. The neural net calculated saturation for different inlet to outlet pressure differentials showing an enhanced outlet end-effect behavior for decreasing water-wet case of Fig. 10.
The parabolic wettability case (Fig. 10) was to evaluate the possible effects by oil flooding from both ends of a plug in an effort to reduce wettability variations. The profile was chosen to be similar to that experimentally measured and described in Fig. 6. For this case, the average wettability is Iw = 0.84 and the other assumed plug properties are the same as described above. The resultant equilibrium saturation profiles for various flooding scenarios (Fig. 17) are different than those described above. At low flooding
pressures, the water saturations at both ends of the plug are decreased. Graue et al. (2000) have also independently observed this type of profile in their experimental work from bidirectional oil floods. It is also possible to obtain from the figures presented (Figs. 11 – 13), an idea of profiles under other combinations of wettability variation. As an example, the reader could combine the 1st half of the profile of the decreasing water-wet case with the second half of the profile of the increasing water-wet case and have a
Fig. 14. The neural net calculated saturations for different inlet to outlet pressure differentials showing conventional outlet end-effect behavior for constant wettability case.
Fig. 16. The neural net calculated saturation variation for different inlet to outlet pressure differentials showing no outlet end-effect behavior for increasing water-wet case of Fig. 10.
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case that is more water-wet at the inlet and outlet ends. Such a profile might occur from partial cleaning of the plug. Other scenarios are left to the reader. Not only are the saturation profiles different, as expected, in the rock from variations in wettability, the calculated ultimate recovery would be expected to vary with direction of the waterflood (see Fig. 18). For the linear cases with the same average wettability, the maximum difference in ultimate recovery was about three saturation units; however, this could be significantly greater for larger wettability variations and larger flooding pressure differentials. Flooding of a plug from both ends may help mitigate some of the variation in a plug, but the impact on an experiment could still be sizeable. 3.4. Discussion As illustrated, the methods of wettability alteration or restoration that result in a nonuniform wettability can affect spontaneous and forced imbibition results. Hydrocarbon recovery and variations in internal saturations of a plug can be significant. The outcome may be greater or less for other rock and crude oil systems. Inconsistent results in laboratory experiments may be due to wettability artifacts such as seen here. The consequence of a nonuniform wettability has implications far beyond spontaneous imbibition
Fig. 18. The direction of waterflood with respect to wettability variations can affect ultimate oil recovery.
and forced displacement oil recovery. Accurate measurements of fundamental properties for the evaluation of oil field reservoirs, such as electrical parameters, relative permeabilities and capillary pressures, have always assumed and required uniform sample wettability. The increasing use of saturation profiles to understand mechanistic fluid flow behavior is dependent upon knowledge of local wettability. Oil recovery variations could affect the selection or even the viability of cost sensitive EOR processes.
4. Conclusions
Fig. 17. The neural net calculated saturation variation for different inlet-to-outlet pressure differentials for the parabolic wettability variation case of Fig. 10.
(1) Some methodologies for restoring/preparing laboratory samples may introduce undesired wettability variations that are not discernible by conventional measures of wettability that average over the entire sample. (2) Internal wettability variations in a laboratory sample can affect the rate and amount of oil recovered by spontaneous imbibition and/or forced imbibition. (3) Internal wettability variations can be obtained by measurement of the appropriate internal saturation variations. (4) Direct measurement of saturation for capillary pressure can provide data from heterogeneous rock samples down to a millimeter scale. This capability is unique to this methodology.
E.A. Spinler et al. / Journal of Petroleum Science and Engineering 33 (2002) 49–59
(5) Complete imbibition capillary pressure curves with both spontaneous and forced components provide an accurate measure of wettability. Nomenclature C cm I.D. Iw mD MHz mm MRI Pc Sw Sw f Swff Sw i U % j
Celsius Centimeter Inside diameter Amott water index for wettability Millidarcy Megahertz Millimeter Magnetic resonance imaging Capillary pressure Water saturation Final spontaneous imbibition Sw Final forced imbibition Sw Initial Sw Porosity Percent Degrees
Acknowledgements The authors thank Phillips Petroleum Company for permission to publish this paper. Thanks to J. Stevens, K. Farmer and D. Chancellor for laboratory assistance.
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References Amott, E., 1959. Observations relating to the wettability of porous rock. Trans. AME, 156 – 162. Anderson, W.G., 1986a. Wettability literature survey: Part 1. Rock/ Oil/Brine interactions and the effects of core handling on wettability. J. Pet. Technol., Trans. 37, 1125 – 1144. Anderson, W.G., 1986b. Wettability literature survey: Part 2. Wettability measurement. J. Pet. Technol., Trans. 38, 1246 – 1262. Buckley. J., 1996. Mechanisms and Consequences of Wettability Alteration by Crude Oils. PhD thesis, Dept. of Petrol. Eng., Heriot-Watt University, Edinburgh, UK. Cuiec, L., 1975. Restoration of the natural state of core samples. Paper SPE 5634, 50th Annu. Meet. of AIME, Dallas, TX, Sept. 28 – Oct 1. Graue, A., Moe, R.W., Bogno, E., 1999. Impacts of wettability on capillary pressure and relative permeability. SCA 9907, 1999 Int. Symp. of the Soc. of Core Analysts. Graue, A., Aspenes, T., Bogno, E., Moe, R.W., Ramsdal, J., 2000. Alteration of wettability and wettability heterogeneity. 6th Int. Symp. on Evaluation of Reservoir Wettability and Its Effect on Oil Recovery, Socorro, NM, Sept 27 – 28. Spinler, E.A., Baldwin, B.A., 1997. Capillary pressure scanning curves by direct measurement of saturation. SCA 9705, 1997 Int. Symp. of the Soc. of Core Analysts. Spinler, E.A., Baldwin, B.A., Graue, A., 1999. Simultaneous measurement of multiple capillary pressure curves from wettability and rock property variations within single rock plugs. SCA 9957, 1999 Int. Symp. of the Soc. of Core Analysts. Standnes, D.C., Austad, T., 2000. Wettability alteration in chalk: 1. Preparation of core material and oil properties. J. Pet. Sci. Eng. 28, 111 – 121.
Experimental artifacts caused by wettability variations in chalk E.A. Spinler a,*, B.A. Baldwin a,1, A. Graue b,2 a
Phillips Petroleum Co., Phillips Research Center, Bartlesville, OK, 74004, USA b University of Bergen, USA
Abstract Alteration of the wettability is often a part of the restoration process for core plugs or used to obtain a desired wettability in outcrop plugs. If the procedure does not provide a uniform wettability state in the plug, experimental artifacts can result. For immersion under crude oil to alter wettability, it was observed that the wettability distribution in a chalk plug was nonuniform. Capillary pressure curves by the direct measurement of saturation method were used to determine the wettability variation within the plug. This plug did not imbibe water because its exterior was rendered almost oil-wet, while the interior remained strongly water-wet. Similarly, for preparation methods that flow crude oil into a plug, the wettability could vary from the end of the sample to the interior or to the other end. The distribution of water and oil in the plug from a subsequent waterflood would then vary with the pressure imposed by the flow direction. Consequently, a forced displacement waterflood could recover different amounts of oil depending upon the direction of the waterflood. A neural net was used to capture the behavior of forced displacement for various wettabilities from measured capillary pressure curves and then used to predict waterflood results. D 2002 Elsevier Science B.V. All rights reserved. Keywords: Wettability; Spontaneous imbibition; Forced imbibition; Wettability alteration; Capillary pressure
1. Introduction Crude oil is commonly used to restore the wettability of reservoir core material or to alter the wettability of outcrop rock to a desired state for further laboratory measurements (Cuiec, 1975; Anderson, 1986a,b; Buckley, 1996). Practices often cite that the resultant wettability is primarily a function of the water saturation present in the rock, the crude oil properties, *
Corresponding author. Fax: +1-918-662-5315. E-mail addresses: [email protected] (E.A. Spinler), [email protected] (B.A. Baldwin), [email protected] (A. Graue). 1 Retired from Phillips Petroleum. 2 Fax: +1-47-55-58-94-40.
the aging time and temperature. Other important variables are the rock properties and the brine composition. Alternate methods include flowing of the crude oil into the rock followed by immersion in the crude or flowing continuously/periodically to freshen the crude oil in the rock. Sometimes, the flow direction is reversed. Aging is often performed at elevated temperature for a predetermined period of time. It is normally assumed that the wettability of the altered or restored rock is uniform. This is not always the case since nonuniform wettability from rock preparation methods has been observed by the authors and others (Spinler et al., 1999; Graue et al., 2000; Standnes and Austad, 2000). The purpose, herein, is to examine the possible impact that nonuniform wettability from restoration/
0920-4105/02/$ - see front matter D 2002 Elsevier Science B.V. All rights reserved. PII: S 0 9 2 0 - 4 1 0 5 ( 0 1 ) 0 0 1 7 5 - 9
50
E.A. Spinler et al. / Journal of Petroleum Science and Engineering 33 (2002) 49–59
Table 1 Properties of portland chalk plug CP-4 Length (cm) Diameter (cm) Porosity (%) Absolute Permeability (mD)
3.72 3.81 48 4
wettability alteration methods may have on some common laboratory experiments.
2. Equipment, material, methods The investigated rock sample, designated CP-4, was a low permeability, high porosity Portland outcrop chalk. Its properties are listed in Table 1. Preparation consisted of drying and saturating with brine (5% sodium chloride and 3.8% calcium chloride by weight in deionized water.) The sample was flushed with reservoir oil at 90j C to an initial water saturation (Swi) of
20% and then aged under that oil at 90 jC for 50 days to alter the wettability. After aging, the reservoir oil was replaced by flow at 90 jC with decalin followed by n-decane. 3-D spontaneous imbibition was conducted at 20 jC for 1000 h followed by forced displacement at a flow rate of 34 ml/h to determine an Amott water index for wettability. The Amott water index (Amott, 1959; Anderson, 1986a,b), Iw, is defined as ratio of the water volume displaced by spontaneous imbibition of water to the total water volume displaced by both spontaneous and forced imbibition of water. The plug was restored by flow to Swi with octadecane at about 35 jC to replace the n-decane. Octadecane has a melting point of 27 jC and when solidified, it is invisible to magnetic resonance imaging (MRI). The liquid brine does image and that allows determination of the water local saturations within the plug from image intensities. The direct measurement of saturation method (Spinler and Baldwin, 1997) was used to obtain the Swi distribution (Fig. 1) and imbibition capillary
Fig. 1. Initial water saturation map from MRI image. Adjacent shades represent 2% Sw difference.
E.A. Spinler et al. / Journal of Petroleum Science and Engineering 33 (2002) 49–59
pressure ( Pc) curves for wettability. To determine Pc, a centrifuge with a swinging bucket was used to develop the saturation profiles in the rock plugs. The sample was heated and cooled while centrifuging, respectively, to melt and solidify the octadecane. The solid octadecane eliminated redistribution by fixing the spatial position of fluids within the plug for subsequent MRI images outside of the centrifuge. Therefore, the water saturation distribution developed at approximately 35 jC in the centrifuge were determined from the image intensities measured outside the centrifuge at f 20 jC. Once the capillary pressure information was obtained, the plug was dried in a vacuum oven at about 70 jC to remove all fluids (The brine had been viscously displaced by fresh water to remove the salts.) The plug was saturated 100% with n-decane for porosity determination. Image intensity from MRI was used to obtain values of porosity for each pixel position within the plug image (Fig. 2). Brighter
51
intensity meant more n-decane at that location within the plug and consequently more porosity; lower intensity meant less porosity. The porosity was calculated by assuming that the average intensity for the plug image was equal to the gravimetrically measured average plug porosity. The left side of plug image (Fig. 2) contained calculated porosity generally greater than the average of 48% and the right side of the plug image contained porosity of generally less than 48%. Images were obtained with a Varian 85/310 CSI. It has a 31 cm bore, 2 T superconducting magnet and operates at 85.55 MHz for hydrogen protons. A 9 cm I.D. saddle coil was used as both transmitting and receiving coil. The amount of fluid hydrogen protons was obtained using the Hahn spin-echo sequence with a 4 ms echo time and a 2.0 s recovery time. One slice, approximately 4 mm thick, was obtained through the center axis of the plug. This orientation produced a rectangle that shows the saturation gradient aligned
Fig. 2. Porosity map from MRI image at 100% n-decane saturation. Adjacent shades represent 1% / difference.
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E.A. Spinler et al. / Journal of Petroleum Science and Engineering 33 (2002) 49–59
parallel to the centrifugal axis. The field of view was 9 8 cm with a pixel resolution of 0.52 0.62 mm with 16 repetitive measurements averaged per each pixel. The images consisted of 255 levels of gray in a 256 256 display. The intensity of the individual pictures was adjusted to produce a presentable visual display; however, absolute intensities were used for quantitative determinations. A neural net was used to determine equilibrium saturation profiles in a model of a hypothetical sample with properties similar to the plug previously described. The neural net had four inputs, one hidden layer of two nodes and one output. Input data consisted of wettability, porosity, Swi, and capillary pressure ( Pc). Output was water saturation (Sw). Training was performed with data obtained from plug CP-4 by direct measurement of saturation.
3. Results and discussion 3.1. Wettability determination To determine Pc behavior, the plug CP-4, starting at an average Swi of about 25%, was centrifuged under brine and octadecane at 35 jC until apparent capillary equilibrium was reached after about 2 weeks. The resultant image (Fig. 3) displayed the fluid distribution for both spontaneous and forced imbibition relative to the free water level. There were no radial artifacts from the centrifugal field since the image represented only a 4-mm-thick slice that was orientated parallel to the centrifuge axis. A fracture is visible in the image slightly to the left of center. This fracture occurred during the centrifuging, but did not affect the analysis. The brightest areas outside of the plug represented free
Fig. 3. MRI image of water saturation distribution after centrifuging. Each shade represents 5% Sw change. Lines with litter identify location of data for Pc curves.
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water and its uppermost edge was the free water level boundary with the octadecane. The free water level was also observed in the fracture. An unusual feature of the fluid distribution was the apparent concave, downward from the center, shape of the saturation distributions within the plug from one side to other side. This feature suggested that the Pc behavior within the plug varied from the interior to the edges. To evaluate this anomaly required that each column of pixels making up the image be evaluated separately. Spontaneous and forced imbibition capillary pressure curves were determined for different positions within
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the plug (Fig. 4a to f) indicated by the vertical lines on the shaded contour map of Fig. 3 and assigned a twoletter curve identifier for tracking. (A Pc determination along the edge of the plug was not obtainable because the MRI software transforms and the high signal contrast between the plug interior as well as the free water intensity compromised measurements near the sides.) Capillary pressure was zero, by definition, at the free water level so it was possible to obtain the saturations (Table 2 and Fig. 5) necessary to calculate an Amott water index (Fig. 6) from each Pc curve. These capillary pressure curves showed that the appa-
Fig. 4. (a) Imbibition Pc curve at position BK near left edge of MRI image in Fig. 3, showing moderate water-wet behavior. (b) Imbibition Pc curve at position CA on the left side of MRI image in Fig. 3, showing water-wet behavior. (c) Imbibition Pc curve at position CQ left of fracture in MRI image in Fig. 3, showing strong water-wet behavior. (d) Imbibition Pc curve at position DN in center of MRI image in Fig. 3, showing strong water-wet behavior. (e) Imbibition Pc curve at position EK on the right side of MRI image in Fig. 3, showing water-wet behavior. (f) Imbibition Pc curve at position FM near right edge of MRI image in Fig. 3, showing moderate water-wet behavior.
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Table 2 Saturations used for Amott water index Curve identifier
BK
CA
CQ
DN
EK
FM
Swi Swf Swff Calculated Iw Pixel position
0.23 0.49 0.72 0.53 9
0.26 0.60 0.69 0.79 25
0.26 0.66 0.68 0.95 41
0.28 0.65 0.66 1.00 64
0.28 0.63 0.67 0.88 87
0.25 0.50 0.72 0.53 115
1
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rent wettability of the plug varied from strongly waterwet at the center to less water-wet near the edges. Standnes and Austad (2000) experimentally observed oil coloration in cleaved plugs (wettability was altered in a similar manner), indicating the same type of wettability variation as determined herein. Recognizing that the wettability was also likely affected from the plug upper and lower ends, the capillary pressure curves were truncated at their top and bottom to examine only the influence of varying wettability perpendicular to the plug axis in the middle interior of the plug. Examination of the different shapes to the capillary pressure curves found them consistent with the calculated wettabilities. The more water-wet rock had higher capillary pressures above the free water level for any particular water saturation and had higher residual oil saturations further below the free water level. The variation of wettability observed within this plug was believed to be a result of the core preparation
Fig. 6. Wettability variation perpendicular to the axis of the plug as calculated from saturation data. Pc curve identifiers are from Fig. 3.
process. As previously described, the plug had been aged by immersion in crude oil after it had been flushed to initial water saturation with the same crude oil. Diffusion during the soaking process in crude oil probably altered the outside of the plug to a near neutral wet state while only altering the interior to the extent that the polar or other components of the crude further diffused or were forcibly displaced into the plug. The low permeability of the chalk would have exacerbated the wettability contrast between the plug interior and exterior by impeding the diffusion process. 3.2. Spontaneous imbibition effects
Fig. 5. The water saturations along the imbibition Pc curve data show behavior typical for wettability variations. Pc curve identifiers are from Fig. 3.
The consequences of this wettability variation on spontaneous imbibition of brine is apparent from the 3-D imbibition test conducted on the CP-4 plug (Fig. 7) when compared to other plugs as obtained from Graue et al. (1999). Included are the imbibition curves for a highly water-wet plug (CPA-1.5) and another plug (CP-13) with an apparent moderate wettability, Iw = 0.76. The average wettability for CP-4 is about the same as for CP-13; however, the imbibition rate behavior is dramatically different. Since some imbibition had occurred and allowed water into CP-4, it may be that with sufficient imbibition time, the spontaneous imbibition endpoint for CP-4 would be the same as for CP-13, with a uniform wettability.
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Fig. 7. Measured imbibition curves for various apparent wettabilities from Graue et al. (1999). The affect of the wettability variation in plug CP-4 has reduced the imbibition rate compared to a plug of similar average wettability, CP-13.
3.3. Forced displacement effects An alternative to aging by immersion under crude oil is to flow, continuously or periodically, the crude oil through the plug for wettability alteration. Flowing crude oil to restore or alter the wettability of rock could also result in a nonuniform wettability distribution in chalk (Graue et al., 2000). That experimental work is not duplicated herein, but an examination of some of the consequences of a nonuniform wettability for flow tests can be estimated using the Pc data obtained from CP-4. The approach was to use a neural net trained to predict equilibrium water saturations for wettability ranging from Iw = 0.5 to 1 and for capillary pressures from 5 to 0 psi from the data of CP-4. The data range for training was extended slightly on each end of the pressures to improve the accuracy of the predictions. Excellent agreement was obtained between calculated and measured saturations (Fig. 8). The shape of the calculated Pc curves appeared to agree well with the data and typical Pc behavior (Fig. 9). A simple model with different cases of linear wettability variations in a rock was chosen (see Fig. 10) for ease of presentation. A slightly more complex case with a parabolic profile similar to that in Fig. 6 was also chosen and will be described separately from the linear cases. Predictions of saturation profiles for
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Fig. 8. The neural net match to model the Pc imbibition data between 5 and 1 psi is excellent.
any wettability variation are equally obtainable from the neural net. The increasing and decreasing wettability cases will allow a comparison of the consequences of water flooding in the same and opposite direction to the direction of wettability alteration created by a previous oil flood. The case of a uniform wettability will allow for comparisons of the varying wettability cases with the conventional assumption of uniform wettability. The properties of the model for the linear profiles are an average wettability of Iw = 0.75, a
Fig. 9. Neural net predicted imbibition Pc curves match the measured saturation data variation with Pc. The predicted curves from 5 to 0 psi display equilibrium saturation profiles for forced imbibition at different uniform wettabilities.
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E.A. Spinler et al. / Journal of Petroleum Science and Engineering 33 (2002) 49–59
Fig. 10. Three cases of different linear wettability variations along length with average Iw = 0.75. The fourth case has a parabolic wettability variation with average Iw = 0.84.
uniform porosity of 48% and a uniform initial water saturation of 23%. These properties were selected to be within the scope of the training for the neural net. Equilibrium saturation profiles for the three different linear wettability cases under different flooding scenarios are shown in Figs. 11– 13. The normalized length is arbitrary as only the inlet-to-outlet differential pressure and the wettability profiles are affecting the water saturations. It is obvious that the spontaneous imbibition endpoint saturation profiles of Fig. 11
Fig. 11. The neural net calculated saturation variation for spontaneous imbibition before flow for the linear wettability variations of Fig. 10.
should mimic the wettability profiles. The slight curvature is somewhat a consequence of having a uniform Swi with a varying Iw. At a differential pressure of 1 psi (Fig. 12) significant changes have occurred at the inlet were the greatest pressure change has occurred. At a pressure differential of 5 psi (Fig. 13), the decreasing water-wet and the uniform water-wet saturation profiles are similar, except for the outlet end. The saturation profile at 5 psi pressure differential for the increasing water-wet case appears similar to the other two cases for only the interior of the model. Another way to look at the equilibrium saturation profiles under different flooding scenarios is shown in Figs. 14 –16. The constant wettability (Fig. 14) case shows the typical end effect (defined as trapping of the oil in this case, the wetting fluid below Pc = 0) with changing flood pressures. All profiles were pinned at the outlet face to a saturation determined by the wettability of that face. In the decreasing waterwet case (Fig. 15), the magnitude of the outlet end effect was enhanced by the lower outlet wettability. For the increasing water-wet case (Fig. 16), there was no outlet end effect because the outlet was highly water-wet. The inlet shows a large variation in saturation. This behavior has been observed experimentally for an increasing water-wet case by Graue et al. (2000).
Fig. 12. The neural net calculated saturation variation for 1 psi inlet to outlet pressure differential for the linear wettability variations of Fig. 10.
E.A. Spinler et al. / Journal of Petroleum Science and Engineering 33 (2002) 49–59
Fig. 13. The neural net calculated saturation variation for 5 psi inlet to outlet pressure differential for the linear wettability variations of Fig. 10.
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Fig. 15. The neural net calculated saturation for different inlet to outlet pressure differentials showing an enhanced outlet end-effect behavior for decreasing water-wet case of Fig. 10.
The parabolic wettability case (Fig. 10) was to evaluate the possible effects by oil flooding from both ends of a plug in an effort to reduce wettability variations. The profile was chosen to be similar to that experimentally measured and described in Fig. 6. For this case, the average wettability is Iw = 0.84 and the other assumed plug properties are the same as described above. The resultant equilibrium saturation profiles for various flooding scenarios (Fig. 17) are different than those described above. At low flooding
pressures, the water saturations at both ends of the plug are decreased. Graue et al. (2000) have also independently observed this type of profile in their experimental work from bidirectional oil floods. It is also possible to obtain from the figures presented (Figs. 11 – 13), an idea of profiles under other combinations of wettability variation. As an example, the reader could combine the 1st half of the profile of the decreasing water-wet case with the second half of the profile of the increasing water-wet case and have a
Fig. 14. The neural net calculated saturations for different inlet to outlet pressure differentials showing conventional outlet end-effect behavior for constant wettability case.
Fig. 16. The neural net calculated saturation variation for different inlet to outlet pressure differentials showing no outlet end-effect behavior for increasing water-wet case of Fig. 10.
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case that is more water-wet at the inlet and outlet ends. Such a profile might occur from partial cleaning of the plug. Other scenarios are left to the reader. Not only are the saturation profiles different, as expected, in the rock from variations in wettability, the calculated ultimate recovery would be expected to vary with direction of the waterflood (see Fig. 18). For the linear cases with the same average wettability, the maximum difference in ultimate recovery was about three saturation units; however, this could be significantly greater for larger wettability variations and larger flooding pressure differentials. Flooding of a plug from both ends may help mitigate some of the variation in a plug, but the impact on an experiment could still be sizeable. 3.4. Discussion As illustrated, the methods of wettability alteration or restoration that result in a nonuniform wettability can affect spontaneous and forced imbibition results. Hydrocarbon recovery and variations in internal saturations of a plug can be significant. The outcome may be greater or less for other rock and crude oil systems. Inconsistent results in laboratory experiments may be due to wettability artifacts such as seen here. The consequence of a nonuniform wettability has implications far beyond spontaneous imbibition
Fig. 18. The direction of waterflood with respect to wettability variations can affect ultimate oil recovery.
and forced displacement oil recovery. Accurate measurements of fundamental properties for the evaluation of oil field reservoirs, such as electrical parameters, relative permeabilities and capillary pressures, have always assumed and required uniform sample wettability. The increasing use of saturation profiles to understand mechanistic fluid flow behavior is dependent upon knowledge of local wettability. Oil recovery variations could affect the selection or even the viability of cost sensitive EOR processes.
4. Conclusions
Fig. 17. The neural net calculated saturation variation for different inlet-to-outlet pressure differentials for the parabolic wettability variation case of Fig. 10.
(1) Some methodologies for restoring/preparing laboratory samples may introduce undesired wettability variations that are not discernible by conventional measures of wettability that average over the entire sample. (2) Internal wettability variations in a laboratory sample can affect the rate and amount of oil recovered by spontaneous imbibition and/or forced imbibition. (3) Internal wettability variations can be obtained by measurement of the appropriate internal saturation variations. (4) Direct measurement of saturation for capillary pressure can provide data from heterogeneous rock samples down to a millimeter scale. This capability is unique to this methodology.
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(5) Complete imbibition capillary pressure curves with both spontaneous and forced components provide an accurate measure of wettability. Nomenclature C cm I.D. Iw mD MHz mm MRI Pc Sw Sw f Swff Sw i U % j
Celsius Centimeter Inside diameter Amott water index for wettability Millidarcy Megahertz Millimeter Magnetic resonance imaging Capillary pressure Water saturation Final spontaneous imbibition Sw Final forced imbibition Sw Initial Sw Porosity Percent Degrees
Acknowledgements The authors thank Phillips Petroleum Company for permission to publish this paper. Thanks to J. Stevens, K. Farmer and D. Chancellor for laboratory assistance.
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