Abstract A novel special core analysis (SCAL) study was conducted utilizing samples from a Middle Eastern Carbonate Reservoir in order to gain insights into flow behavior across stylolitic intervals. This study included relative permeability and capillary pressure measurements performed on individual core plug and core plug composite samples, as well as a unique waterflood experiment on a fourinch diameter whole core composite. All laboratory flow measurements were performed at reservoir conditions of temperature, pressure, and net confining stress. As part of this study, it was demonstrated that wettability restoration remains a significant challenge for carbonate core samples, with implications for coring and core analysis program design and interpretation of historic SCAL data. Corescale simulation using measured relative permeability and capillary pressure data along with whole core rock properties provides an opportunity to validate laboratory results across laboratory scales and can also serve as an intermediate to mechanistic modeling studies at larger scales. In this paper, the novel technical approach and significant findings for the special core analysis study are presented, with implications for modeling of displacement processes across stylolitic intervals in complex carbonate reservoirs. General recommendations for the design of special core analysis programs are also presented.
SPE 161932 An Advanced Special Core Analysis Study for a Middle Eastern Carbonate Field Lisa Lun, Kyle Guice, Jim Kralik, ExxonMobil Upstream Research Co.; Jon Meissner, ExxonMobil Production Co.; Maher Kenawy, Zubair Kalam, and Taha al-Dayyni, Abu Dhabi Co for Onshore Oil Operations Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the Abu Dhabi International Petroleum Exhibition & Conference held in Abu Dhabi, UAE, 11–14 November 2012 This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s) Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s) The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied The abstract must contain conspicuous acknowledgment of SPE copyright Abstract A novel special core analysis (SCAL) study was conducted utilizing samples from a Middle Eastern Carbonate Reservoir in order to gain insights into flow behavior across stylolitic intervals This study included relative permeability and capillary pressure measurements performed on individual core plug and core plug composite samples, as well as a unique waterflood experiment on a four-inch diameter whole core composite All laboratory flow measurements were performed at reservoir conditions of temperature, pressure, and net confining stress As part of this study, it was demonstrated that wettability restoration remains a significant challenge for carbonate core samples, with implications for coring and core analysis program design and interpretation of historic SCAL data Core-scale simulation using measured relative permeability and capillary pressure data along with whole core rock properties provides an opportunity to validate laboratory results across laboratory scales and can also serve as an intermediate to mechanistic modeling studies at larger scales In this paper, the novel technical approach and significant findings for the special core analysis study are presented, with implications for modeling of displacement processes across stylolitic intervals in complex carbonate reservoirs General recommendations for the design of special core analysis programs are also presented Introduction High quality special core analysis (SCAL) data (e.g., relative permeability and capillary pressure), integrated into internallyconsistent saturation functions, provide critical inputs into reservoir performance prediction throughout the reservoir lifecycle Acquiring high-quality data in the laboratory generally requires that measurements must be on rock samples representative of the reservoir (the right samples); measurements must be made under conditions representative of displacement processes in the reservoir (the right conditions); measurements must be made using precision equipment and techniques (the right equipment); and trained and experienced technologists are needed to conduct the measurements and model the data (the right people) For certain carbonate rock types, ensuring that measurements are performed on rock samples representative of the reservoir presents a challenge of scale A core sample may be considered representative of a specific reservoir rock type if it contains the relevant features that distinguish the reservoir rock type in a distribution that is “homogeneously heterogeneous” at the selected measurement scale Increasing the size of the measured core sample is often a good way to achieve a representative sample if key features are not homogeneously distributed at smaller scales For some carbonate rock types, including highly karsted rock types, identifying core samples with a representative distribution of heterogeneities at any laboratory scale is a significant challenge In these cases, one can gain insights into the impact of select heterogeneities on special core analysis measurements by performing an integrated suite of measurements spanning multiple length scales Given that the objective of any special core analysis study is to deliver high quality data to address questions at scales larger than can be measured in the laboratory, the desired multi-scale approach is to supplement special core analysis measurements at traditional scales with additional measurements at larger length scales As part of an integrated suite of measurements, whole core testing is particularly useful SPE 161932 to address the effects of key features of interest on flow performance, as a whole core represents the largest sample size that can be acquired from a reservoir In this study, an integrated suite of special core analysis measurements spanning multiple length scales is employed to investigate flow behavior across stylolitic features for a Middle Eastern carbonate reservoir Stylolites are diagenetic features that occur in many carbonate reservoirs as a result of pressure dissolution, generally result in low permeability and low porosity due to cementation in the immediate vicinity of a stylolite seam, and exist with significant variability in permeability, porosity, spatial extent, and connectivity At reservoir scales, stylolitic features may behave as either barriers or baffles to vertical flow A better understanding of flow behavior across stylolitic intervals is desired to better interpret production data and support future well planning The study presented was divided into three parts First, special core analysis measurements were performed on representative core samples at representative reservoir conditions using a multi-scale approach Laboratory measurements included capillary pressure and relative permeability measurements performed on core plug and core plug composite samples, as well as a unique whole core study to quantify flow across a large stylolite interval in the laboratory Second, the multi-scale laboratory measurements were integrated into a core-scale simulation model of the whole core experiment Finally, validated special core analysis inputs from the core-scale simulation model were used as part of a mechanistic model to understand flow across a stylolitic interval at reservoir scales Measurement of Capillary Pressure and Relative Permeability on Core Plugs and Core Plug Composites Capillary pressure and steady-state relative permeability measurements were performed on core samples in their native state (preserved) at reservoir net confining stress Samples were selected to cover a range of reservoir rock types and rock properties The testing strategy included relative permeability and capillary pressure measurements on stylolitic plug samples The absolute permeability of the plugs used in this study ranged from mD to 60 mD Water-oil imbibition and secondary drainage capillary pressure measurements were performed by the centrifuge method on individual, 1.5-inch diameter plug samples using rotovaped stock tank oil and synthetic reservoir brine at a temperature of 170°F Primary drainage capillary pressure measurements were performed by the centrifuge method with nitrogen gas (displacing phase) and synthetic brine (displaced phase) Relative permeability measurements were performed by the steadystate method on two-inch diameter samples (either long vertical plugs or core plug composites) using live reservoir fluids at reservoir temperature and pressure All capillary pressure and relative permeability measurements presented in this paper are plotted against normalized water saturations in a similar manner as presented in the Appendix of Meissner et al (2009) For primary drainage capillary pressure, the normalized water saturation, Swn, is defined as: S wn = S w ! S wirr ! S wirr where Sw is the water saturation and Swirr is the irreducible water saturation of each sample For primary imbibition and secondary drainage capillary pressure, Swn is defined as: Swn = Sw ! Sw,min ! Sw,min ! Sorw where Sw,min is the minimum water saturation achieved in that cycle for each sample and Sorw is residual oil saturation of that sample All of the relative permeability curves were scaled in a similar manner as the primary imbibition capillary pressure curve except Sw,min is the minimum water saturation achieved over all hysteresis cycles for each sample and Sorw is the minimum oil saturation achieved over all cycles for each sample Results from centrifuge capillary pressure measurements are presented in Figures 1-3 Water-oil primary imbibition capillary pressure data are plotted in Figure Oil-water secondary drainage capillary pressure data are plotted in Figure Gas-water primary drainage data are plotted in Figure In all cases, the capillary pressure data are calculated at the inlet face of the core plug using a numerical technique to solve the general equation described by Hassler and Brunner (1945) The same samples set of seven samples were used for all capillary measurements, although all cycles were not performed on Sample (secondary drainage omitted) or Sample (primary imbibition and secondary drainage omitted) Water-oil relative permeability measurements were conducted using the steady-state method on two-inch diameter samples (either long vertical core plugs or core plug composites) at full reservoir conditions (i.e., temperature, pressure, net confining stress) The steady-state method allows for accurate measurement of oil and water relative permeabilities over a wide range of fluid saturations The fully-recirculating experimental apparatus used for steady-state relative permeability measurements SPE 161932 was previously described in Braun and Blackwell (1981) Measurements were performed on each sample in the primary imbibition, secondary drainage, and secondary imbibition saturation pathways For each saturation pathway, the waterflood (imbibition) or oilflood (drainage) data acquired after the final steady-state fractional flow were analyzed as an unsteady-state flood utilizing the method of Johnson, Bossler, and Naumann (1959) Water-oil relative permeability data for three samples are presented on normalized saturation scales in Figures 4-6 In each figure, steady-state measurements are presented as filled circles (!, krow) and filled triangles (!, krw), and unsteady-state flood data are presented as solid lines Each figure includes primary imbibition, secondary drainage, and secondary imbibition pathways Hysteresis in both oil and water relative permeability data are generally observed between primary imbibition and secondary drainage for these samples, and is slightly more pronounced for the water phase Hysteresis is a qualitative indicator of wettability, and is usually most pronounced for the non-wetting phase The hysteresis data suggest that all samples are mixed-wet with a slight wettability preference for oil Following the relative permeability and capillary measurements described above, the samples were cleaned and restored, and capillary pressure and relative permeability measurements were again performed on the same samples Wang (1994) and Meissner et al (2009) have observed in independent studies that wettability restoration methods for carbonate samples are not reliable, particularly for lower quality samples (i.e., below 100 mD) A description of the cleaning process is included in the Appendix Representative examples of restored-state results of capillary pressure (primary imbibition and secondary drainage) and relative permeability (primary drainage) are shown in Figures 7-9 for Samples 5, 2, and respectively The data sets have been normalized on the same basis for each sample We observed marked differences between the results for preserved and restored-state samples in both capillary pressure and relative permeability with the exception of Sample (Figure 8) For this sample, the capillary pressure results appear more reproducible The absolute permeability of Sample (~60 mD) was the highest in the sample set Meissner et al (2009) presented data that indicated that wettability restoration for carbonate rocks may be more reliable on higher quality samples, and the results of this study are consistent with this observation While wettability itself is not a direct input into most reservoir simulators, high-quality relative permeability and capillary pressure data require that measurements are performed on samples in a condition representative of the reservoir Accordingly, since carbonate wettability restoration remains a significant challenge, careful coring and core preservation efforts are generally required to produce high-quality special core analysis data for carbonate reservoirs Whole Core Waterflood Experiment In addition to relative permeability and capillary pressure measurements conducted on core plug and composite samples, a novel whole core experiment was designed to study flow across a stylolitic whole core segment The experiment was performed on a 21.6-inch long, four-inch diameter whole core composite at reservoir temperature, pressure, and net confining stress in a unique whole core apparatus The whole core composite consisted of four whole core segments in their preserved state Each segment was selected to represent an appropriate reservoir interval A schematic of the whole core composite is shown in Figure 10 The second segment from the top, Sample WC2, contained a visible stylolitic interval Pressure taps were located at several points along the composite, as illustrated in Figure 10 A waterflood was performed vertically downward, and oil production and the pressure gradients were monitored In addition, in-situ saturation monitoring was utilized to measure water saturation along the length of the whole core composite throughout the waterflood The waterflood was performed at three progressively increasing flow rates (0.2, 0.4, 0.8 cc/min) A total of 21.6 pore volumes of brine were injected over the course of the experiment Oil production and pressure drop data from the whole core waterflood experiment are presented in Figure 11 Oil production is represented as a dark blue line, and total pressure drop is represented as a red line Local pressure drop data (i.e., between individual pressure taps) are also shown in orange (P1-P2), blue (P2-P3), and green (P3-P4) The water saturation profile along the length of the whole core composite is presented in Figure 12 for various points during the waterflood The oil production data indicate water breakthrough after 620 cc of oil production The movement of the flood front before breakthrough can be clearly observed from the saturation profile data (Figure 12) and also from the progression of peaks in the local pressure drop data with increasing distance from the inlet of the core (Figure 11) The center section exhibits the largest pressure drop as the flood front passes (27 psi), followed by the bottom section (17 psi) and the top section (7.4 psi) While the top section is approximately half the length of the other two sections, the center and bottom sections are of similar size The difference in peak pressure drop can be attributed to the presence of the lower permeability stylolitic interval in the center section After breakthrough, there is a period ("Qi = 400 cc) in which no additional oil is produced from the whole core composite This behavior after breakthrough is also reflected in the in-situ saturation monitoring data and is likely the SPE 161932 result of baffling within the stylolitic interval Subsequently, oil production recommences and then becomes progressively slower throughout the waterflood The water injection rate was doubled twice to see if there was a rate dependency on oil production First, the rate of water injection into the core was doubled after 12.4 pore volumes of brine had been injected into the whole core composite Then the rate of water injection was doubled again after another 16.2 total pore volumes were injected In each instance, there is an increase in the total and localized pressure drops, as shown in the figure Oil production from the whole core composite appears to be independent of injection rate, provided that total production is evaluated relative to throughput (rather than time) After the second increase in the injection rate, there is a notable decline in the pressure drop across the bottom section (P3-P4), whereas the local pressure drops across the other sections remain constant A decrease in pressure drop across the bottom of the core at an elevated injection rate is suggestive of a capillary end effect at the bottom of the core Water saturation profiles are shown at several points during the waterflood in Figure 12 The stylolitic whole core segment reaches a final water saturation that is notably higher (>95%) than the remainder of the whole core composite The location of the flood front is clearly visible for all saturation profiles before water breakthrough The whole core waterflood experiment clearly demonstrated that the selected stylolitic interval does not present a barrier to vertical flow at the whole core scale, that oil can be effectively displaced across the stylolite interval and that low residual oil saturations can be ultimately obtained above, below, and within the stylolite interval Core-scale simulation A core-scale simulation model was constructed to reproduce the results of the whole core waterflood experiment and verify the saturation function inputs measured on plugs and plug composites The whole core waterflood experiment was modeled using EMpower, the ExxonMobil proprietary reservoir simulation software (Beckner et al 2001) Saturation functions developed from the capillary pressure and relative permeability measurements on plugs/plug composites were used as inputs to the model The goal of the simulation was to validate the saturation function inputs from the plug scale experiments (capillary pressure and relative permeability) for the different rock types represented in the whole core experiment Cumulative oil production and pressure drop across the core were matched, although a rigorous history match was not the goal of the study Instead matching the overall behavior was deemed sufficient The whole core waterflood is modeled using two fluid phases (black oil model) with a rectangular model constructed of the following total dimensions: 81 cm2 (equivalent to inch diameter cross-sectional area), with a 10 # 10 gridding and 112 layers in the vertical dimension, with each vertical layer having a total height of 0.5 cm The vertical resolution of the grid was based on the resolution of the in-situ saturation monitoring system used in the whole core experiment (0.5 cm) The reference depth for the uppermost vertical layer is 8000 ft Each layer has a constant porosity and permeability based on porosity and permeability maps that were independently acquired on the whole core composite Absolute permeability was rescaled to permeability of oil at connate water, kocw, to match the reference permeability used to scale the relative permeability curves Horizontal permeability was set equal to vertical permeability based on whole core measurements of horizontal and vertical permeability Displacement data (e.g., capillary pressure and relative permeability) were applied separately for each whole core segment based on the results of plug and core plug composite measurements An injector well was placed in the uppermost layer to facilitate water injection in the model, and a producer well was connected to the lowermost layer in the model The porosity and absolute permeability of the injector and producer layers were matched to adjacent rock layers to improve numerical stability Capillary pressure in the producer layer was set to zero to be consistent with capillary effects observed at the outlet of the whole core composite during the waterflood Injection rate limits and producer pressure limits based on experimental data were used as boundary limits in the simulation model Layers 1, 14, 64, and 112 (arranged from top to bottom) correspond to the locations of the pressure transducers P1, P2, P3, and P4 respectively The initial water saturation of the whole core composite was slightly lower than that of the plug samples used in the capillary pressure and steady-state relative permeability measurements A design of experiments approach was used to investigate various approaches for endpoint scaling of capillary pressure and relative permeability functions in the core-scale simulation model, and also to assess the model’s sensitivity to the shape of the positive branch of the primary imbibition capillary pressure curves, which was not directly measured in the laboratory The various simulation runs revealed that the simulation results were not sensitive to endpoint scaling of the capillary pressure curves or the positive branch of the primary imbibition capillary pressure curves For relative permeability endpoint scaling, the optimal method to match the whole core waterflood experiment was to extend the Corey curves fit to laboratory data to the lower whole core Swi, with appropriate rescaling in krow and krw such that the initial oil permeability (kocw) in the whole core simulation matched that of the experiment Inclusion of secondary drainage relative permeability and capillary pressure data was considered in the model, but a sensitivity to capillary pressure hysteresis revealed minimal impact on results (i.e., less than 1% difference in pressure or cumulative oil production match) Accordingly, hysteresis was not included in the final core-scale simulation model SPE 161932 A comparison of results, oil production and pressure drop, from the whole core waterflood and the core-scale simulation model are presented in Figure 13 where experimental results are in solid lines and simulation results are in dashed lines Results are plotted with respect to volume of brine injected Overall, we find reasonable agreement between the experiment and core scale simulation results There are noticeable differences in pressure drop in the lower portion of the composite (P3P4) and water breakthough During the first two flow periods, P3-P4 is lower in the simulation than in the experiment while in the third flow period P3-P4 is higher in the simulation Also, water breakthrough is predicted as occurring later in the simulation than what occurred in the experiment This delay may be related to more complex heterogeneity existing in the stylolite, such as baffles, and in the rest of the core than were effectively captured in this one-dimensional model Screenshots from the simulation of water saturation in the core composite are shown in Figure 14 (green is low water saturation and blue is high water saturation) and line plots in Figure 15 The water front proceeds uniformly through the core, which is expected given the simplicity of the simulation model Water saturations at the front are higher by approximately 10 saturations units compared to the experimental data Water saturations at the end of the flood match the experimental data better (approximately 75-80% in the Upper/Lower Zones and 85-90% in the stylolitic interval) The simulation showed a small amount of capillary end effect at the bottom, outlet of the composite agreeing with the experimental data The water saturation in the stylolitic interval was higher than in other parts of the core, which is consistent with the experimental results While there are some differences between simulation and experimental results, the match is of acceptable quality given the purpose of simulation and the simplicity of the model The goal of the core scale simulation study was not to achieve a rigorous history match Instead, the goal was to obtain a reasonable description of the physical behavior to validate the saturation function inputs and this was achieved using a fit-for-purpose simulation model Mechanistic model The final phase of the project involved taking validated inputs to the core scale model and applying them at a mechanistic model scale The mechanistic model was built in EMpower The grid had a km # km areal span and was 0.055 km thick (180.5 ft) The model was built as a “layer-cake” with constant porosity and permeability values in each layer The layers were grouped into three gross divisions: an upper zone, a stylolitic interval, and a lower zone The stylolitic interval was explicitly modeled with horizontal permeability on the order of 0.5 mD The horizontal permeability of the lower zone was on the order of 10 mD while the permeability of the upper zone was approximately 50-100 times greater The vertical permeability was set equal to the horizontal permeability based on routine permeability measurements done on whole core samples Relative permeability and capillary pressure curves used in the mechanistic model are the same as those presented in the core-scale model of the whole core experiment There were three horizontal wells located at the bottom of the lower zone: one injector and two producers The producers were spaced from the injector at km and km Water was injected at a rate of 10,000 bbl/day with a constraint that the injector bottom hole pressure not exceed 6500 psi Producers were maintained at constant pressure boundary conditions of 1500 psi for producer1 and 1200 psi for producer2 which were above the bubble point pressure of 1000 psi Each producer was also set to shut-in when the produced water cut exceeded 80% Figure 16 shows screen captures of the oil saturation in the mechanistic model at various times where blue is low oil saturation and green is high oil saturation Despite injector and producer placement in the lower zone, the upper zone is swept faster than the lower zone in the mechanistic model The preferential sweep in the upper zone is primarily due to the large contrast in horizontal permeability between the upper and lower zones Gravitational cross flow from the upper to lower zones (light blue color below the stylolite) indicates that the stylolitic interval acts as a weak baffle to flow in the vertical direction, which is supported by observations in the laboratory study The mechanistic model is a useful tool that can be used to quickly assess the impact of different parameters (well placement, permeability contrast, baffles, saturation functions, etc.) on a reservoir scale Conclusions A novel workflow has been presented to measure and validate high-quality special core analysis data for heterogeneous carbonates The workflow consists of the following components: • An integrated suite of high-quality special core analysis measurements (relative permeability and capillary pressure) performed on core plug and core plug composite scales • A whole core experiment designed to assess the impact of specific heterogeneities that are not homogeneously distributed in a core sample at the laboratory scale • Core-scale simulation of the whole core experiment to validate special core analysis results at a larger scale • Implementation of validated special core analysis results into mechanistic or field scale models Achieving high-quality special core analysis data generally requires that measurements must be performed on representative rock samples, at representative reservoir conditions, using precision equipment and techniques, and are planned, executed, and integrated by trained and experienced technologists For carbonate core samples, there are particular considerations to SPE 161932 note: • • Wettability restoration to achieve representative reservoir conditions has been demonstrated in this and other studies to remain a significant challenge Accordingly, careful planning of carbonate coring and core preservation steps is required to ensure native state rock samples are available for high quality SCAL measurements For highly heterogeneous carbonates, identifying representative rock samples should include consideration for scale In this study, a multi-scale approach is demonstrated that includes flow studies at a maximum laboratory scale (i.e., whole core) This workflow was successfully demonstrated for a stylolite-containing Middle Eastern carbonate reservoir The study revealed that, at laboratory scales, stylolitic features not always act as barriers to the displacement of oil by water but rather act as flow baffles High-quality special core analysis measurements acquired on core plug and core plug composite samples have been validated against a core-scale simulation of a whole core waterflood experiment and were used directly in a mechanistic model to describe flow across a stylolitic interval at a field scale Acknowledgments The authors wish to thank Abu Dhabi Co for Onshore Oil Operations and ExxonMobil Upstream Research Company for their support and permission to publish this paper The authors also would like to recognize M.M Honarpour, Abi Modavi, J.A Boros, C Chiasson, D.C Laverick, R Longoria, L.J Manak, L.J Poore, J Rainey, and A.C Wood for their significant contributions Nomenclature cc milli-Liters cc/min milli-Liters per minute cm centimeters square centimeters cm2 EMpower proprietary ExxonMobil reservoir simulator ft feet (length) km kilometers permeability to oil at connate water kocw relative permeability to oil (displaced by water) krow relative permeability to water krw mD milli-Darcies pressure tap, where n = 1-4 Pn psi pounds per square inch !Qi change in volume injected SCAL special core analysis Sorw residual oil saturation water saturation Sw Swi initial water saturation irreducible water saturation Swirr Sw,min minimum water saturation normalized water saturation Swn USBM United States Bureau of Mines References Beckner, B.L., Hutfilz, J.M., Ray, M.B., and Tomich, J.F 2001 EMpower: ExxonMobil’s New Reservoir Simulation System Paper SPE 68116 presented at the 2001 SPE Middle East Oil Show, Bahrain, 17-20 March 2001 http://dx.doi.org/10.2118/68116-MS Braun, E.M., and Blackwell, R.J 1981 A Steady-State Technique for Measuring Oil-Water Relative permeability Curves at Reservoir Conditions Paper SPE 10155 presented at the 56th Annual Fall Technical Conference and Exhibition, SPE of AIME, San Antonio, Texas, 5-7 October 1981 http://dx.doi.org/10.2118/10155-MS Corey, A.T and Rathjens, C.H 1956 Effect of Stratification on Relative Permeability J Pet Technol (12): 69-71 SPE744-G http://dx.doi.org/10.2118/744-G Gomes, J.S., Ribeiro, M.T., Strohmenger, C.J., Negahban, S., Kalam, M.Z 2008 Carbonate Reservoir Rock Typing – The Link between Geology and SCAL Paper SPE 118284 presented at the Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, UAE, 3-6 November, 2008 http://dx.doi.org/10.2118/118284-MS SPE 161932 Hassler, G.L and Brunner, E.M 1945 Measurement of Capillary Pressure in Small Core Samples Petroleum Transactions, AIME 160: 114-123 http://dx.doi.org/10.2118/945114-G Honarpour, M.M., Nagarajan, N.R and Sampath, K 2006 Rock/Fluid Characterization and Integration - Implications on Reservoir Management Distinguished Author Series, J Pet Technol 58 (9): 120-130 SPE-103358-MS http://dx.doi.org/10.2118/103358-MS Honarpour, M.M., Djabbarah, N.F., and Sampath, K 2005 Whole-Core Analysis – Experience and Challenges SPE Res Eval & Eng (6): 460-469 SPE-81575-PA http://dx.doi.org/10.2118/81575-PA Honarpour, M.M., Djabbarah, N.F., Kralik, J.G 2004 Expert-based Methodology for Primary Drainage Capillary Pressure Measurements and Modeling Paper SPE 88709 presented at the 11th Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, UAE, 10-13 October, 2004 http://dx.doi.org/10.2118/88709-MS Ingle, J.D and Crouch, S.R 1988 Spectrochemical Analysis New Jersey: Prentice Hall Johnson, E.G., Bossler, E.M., and Naumann, V.O 1959 Calculation of Relative Permeability for Displacement Experiments Petroleum Transactions, AIME 216: 370-372 Kalam, M.Z., Al-Alawi, S.M., Al-Shekaili, S 1997 A Novel Technique for Predicting End-Point Relative Permeabilities of Heterogeneous Limestones from Log Derived Input Data Paper SPE 37694 was presented at the 1997 Middle East Oil Show and Technical Exhibition, Bahrain, 15-18 March, 1997 http://dx.doi.org/10.2118/37694-MS Koepnick, R.B 1987 Distribution and Permeability of Stylolite-Bearing Horizons Within a Lower Cretaceous Carbonate Reservoir in the Middle East Paper SPE 14173 presented at the SPE Annual Technical Conference and Exhibition, Las Vegas, NV, 22-25 September, 1985 http://dx.doi.org/10.2118/14173-PA Kralik, J.G., Guice, K., and Meissner, J.P 2010 Methods and Tools for the Development of Consistent Reservoir Rock Type Based Relative Permeability and Capillary Pressure Models for Reservoir Simulation Paper SPE 137357 presented at the Abu Dhabi International Petroleum Exhibition & Conference (ADIPEC), Abu Dhabi, UAE, 1-4 November 2010 http://dx.doi.org/10.2118/137357-MS Meissner, J.P., Wang, F.H.L., Kralik, J.G., Ab Majid, M.N., Bin Omar, M.I., Attia, T., Al-Ansari, K 2009 State of the Art Special Core Analysis Program Design and Results for Effective Reservoir Management, Dukhan Field, Qatar Paper IPTC 13664 presented at the International Petroleum Technology Conference (IPTC), Doha, Qatar, 7-9 December 2009 http://dx.doi.org/10.2523/13664-MS Montgomery, D.C, Design and Analysis of Experiments, 7th Edition, New York: John Wiley & Sons, 2008 Serag El Din, S Dernaika, M.R., Kalam, M.Z 2011 The Impact of Heterogeneity and Multi-Scale Measurements on Reservoir Characterization and STOOIP Estimations SPE Paper 147950 presented at the SPE Reservoir Characterization and Simulation Conference and Exhibition, Abu Dhabi, UAE, 9-11 October 2011 http://dx.doi.org/10.2118/147950-MS Wang, F.H 1994 Some Aspects of Wettability Alteration, Restoration, and Preservation In Proceedings of the 3rd International Symposium on Evaluation of Reservoir Wettability and its Effect on Oil Recovery, 21-23 September 1994, Laramie, WY, ed N.R Morrow, 119-122 Wang, F.H 1998 Effect of Wettability Alteration on Water/Oil Relative Permeability, Dispersion, and Flowable Saturation in Porous Media SPE Res Eng (2): 617-628 SPE-15019-PA http://dx.doi.org/10.2118/15019-PA Appendix – Cleaning Procedure After capillary pressure and relative permeability measurements were run on the plug samples, the plugs were extracted, cleaned, and then wettability was restored A different solvent mixture and sequence was used to clean the plugs compared to the method reported in Wang (1988) and Meissner et al (2009), however with comparable temperatures and flow rates In this study, the solvent sequence used was toluene saturated with water, then a methanol/acetone/chloroform azeotrope, and finally followed by methanol only The remaining methanol was blown out and dried under active vaccum 8 SPE 161932 Figures # #(& #(" #() #(* &$ ' # &# !% &" +,-./01' !"#$%%"&'()&*++,&*-(#+$ !"#$%%"&'()&*++,&*-(#+$ !'# +,-./01& !'% +,-./01$ +,-./01" !&# +,-./01% +,-./01) !&% &! ()*+,-.& ()*+,-." % ()*+,-.# ()*+,-./ $ ()*+,-.$ # !$# " !$% ! ! !"# /&0"%$1*2(3"4*&(5"4,&"4$/6-(7&"84$/6 Figure Water-oil primary imbibition capillary pressure data &$! &#! ()*+,-.& &"! !"#$%%"&'()&*++,&*-(#+$ ()*+,-." ()*+,-./ &!! ()*+,-.# %! ()*+,-.0 ()*+,-.$ $! ()*+,-.1 #! "! ! ! !'" !'# !'$ !'% !'" !'# !'$ !'% & /&0"%$1*2(3"4*&(5"4,&"4$/6-(7&"84$/6 & /&0"%$1*2(3"4*&(5"4,&"4$/6-(7&"84$/6 Figure Gas-water primary drainage capillary pressure data Figure Oil-water secondary drainage capillary pressure data SPE 161932 '"# !"($! '()*+,-*./0 '"! !"#$%&'"()"*+"$,&#&%-.(/*$0%&12(31.45& !"#$%&'"()"*+"$,&#&%-.(/*$0%&12(31.45& !"($$ !"#$! !"#$' !"#$& '()*+,-*./1 #23*3/*./0 #23*3/*./1 !"& #23*+,-*./0 #23*+,-*./1 !"% !"$ !"# !"#$% !"! $ $)' $)% $)* $)+ ! ! 61*+$#&7"8(9$%"*(4$%:*$%&12.(/*$0%&12 !"# !"$ !"% !"& ' 61*+$#&7"8(9$%"*(4$%:*$%&12.(/*$0%&12 Figure Steady-state water-oil relative permeability data for Sample in the preserved state Three hysteresis cycles were measured: primary imbibition (1st imb), secondary drainage (2nd dr), and secondary imbibition (2nd imb) Steady-state data are designated by individual symbols (! ! , krow;!, krw), and unsteady-state data are designated by lines '"$ !"($! '"# '()*+,-*./0 !"#$%&'"()"*+"$,&#&%-.(/*$0%&12(31.45& !"#$%&'"()"*+"$,&#&%-.(/*$0%&12(31.45& !"($$ !"#$! !"#$' '()*+,-*./1 '"! #23*3/*./0 #23*3/*./1 !"& #23*+,-*./0 #23*+,-*./1 !"% !"$ !"#$& !"# !"! !"#$% $ $)' $)% $)* $)+ 61*+$#&7"8(9$%"*(4$%:*$%&12.(/*$0%&12 ! ! !"# !"$ !"% !"& ' 61*+$#&7"8(9$%"*(4$%:*$%&12.(/*$0%&12 Figure Steady-state water-oil relative permeability data for Sample in the preserved state Three hysteresis cycles were measured: primary imbibition (1st imb), secondary drainage (2nd dr), and secondary imbibition (2nd imb) Steady-state data are designated by individual symbols (! ! , krow;!, krw), and unsteady-state data are designated by lines 10 SPE 161932 !"($! '"! &"# $*+,-./,012 !"#$%&'"()"*+"$,&#&%-.(/*$0%&12(31.45& !"#$%&'"()"*+"$,&#&%-.(/*$0%&12(31.45& !"($$ !"#$! !"#$' $*+,-./,013 &"! %45,51,012 %"# %45,51,013 %45,-./,012 %"! %45,-./,013 $"# $"! !"#$& !"# !"#$% !"! $ $)' $)% $)* $)+ ! ! !"% 61*+$#&7"8(9$%"*(4$%:*$%&12.(/*$0%&12 !"' !"( !") $ 61*+$#&7"8(9$%"*(4$%:*$%&12.(/*$0%&12 %# %# &# &# # # #'% #'" #'( #') & !&# &*+,-./0,12+-34 !%# %56,670,12+-34 &*+,-./0,84*+9746 !"#$%%"&'()&*++,&*-(#+$ !"#$%%"&'()&*++,&*-(#+$ Figure Steady-state water-oil relative permeability data for Sample 10 in the preserved state Three hysteresis cycles were measured: primary imbibition (1st imb), secondary drainage (2nd dr), and secondary imbibition (2nd imb) Steady-state data are designated by individual symbols (! ! , krow;!, krw), and unsteady-state data are designated by lines # # #'" #'( #') & !&# &*+,-./0,12+-34 !%# %56,670,12+-34 &*+,-./0,84*+9746 %56,670,84*+9746 %56,670,84*+9746 !$# !$# !"# #'% /&0"%$1*2(3"4*&(5"4,&"4$/6-(7&"84$/6 Figure A comparison of primary imbibition and secondary drainage capillary pressure data for Sample in the preserved and restored wettability states Results for Sample are representative of all other samples except for Sample !"# /&0"%$1*2(3"4*&(5"4,&"4$/6-(7&"84$/6 Figure A comparison of primary imbibition and secondary drainage capillary pressure data for Sample in the preserved and restored wettability states Results appear more reproducible Notably, Sample permeability was an order of magnitude greater than the other samples SPE 161932 11 !"($! '"# !"#$%&'"()"*+"$,&#&%-.(/*$0%&12(31.45& !"($$ !"#$%&'"()"*+"$,&#&%-.(/*$0%&12(31.45& '()*+,-*./01 23)+45 '()*+,-*./61 23)+45 '()*+,-*./01 75()0/58 '()*+,-*./61 75()0/58 '"! !"#$! !"#$' !"#$& !"& !"% !"$ !"# !"#$% !"! $ $)' $)% $)* $)+ ! ! 61*+$#&7"8(9$%"*(4$%:*$%&12.(/*$0%&12 !"# !"$ !"% !"& ' 61*+$#&7"8(9$%"*(4$%:*$%&12.(/*$0%&12 Figure A comparison of primary imbibition water-oil relative permeability data for Sample in the preserved and restored wettability states Steady-state data are designated by individual symbols (! ! , krow;!, krw), and unsteady-state data are designated by lines Flow Direction P1 P2 !"# !"$ P3 54.9 cm !"% !"& P4 Figure 10 Schematic of the whole core composite used in the whole core waterflood Samples labeled from top to bottom are WC1, WC2, WC3, and WC4 Sample WC2 contained a visibile stylolitic interval 12 SPE 161932 Figure 11 Production and pressure drop data from the whole core waterflood Figure 12 Water saturation profiles at various points during the whole core waterflood SPE 161932 13 3'4'796'88:;#"2'3# 4'=>@77'88 3'4'79A'88:;#"2'3# 4'6=A@7'88 3'4'79?'88:;#"2'3# 4'