SPE-169088-MS

A Novel, Field-representative Enhanced Oil Recovery Coreflood Method Robin Gupta, Pengbo Lu, Rodney Glotzbach, Owen Hehmeyer, ExxonMobil Upstream Research Company

Copyright 2014, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Improved Oil Recovery Symposium held in Tulsa, Oklahoma, USA, 12–16 April 2014. 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 This study describes a new method that can improve laboratory determination of enhanced oil recovery (EOR) potential for a test fluid relative to a base fluid. The new method uses a modified steady-state fractional flow method to measure the shift in oil saturation in a rock at an intermediate fractional flow when changing from a base brine to a test EOR brine(s). This study uses fractional flow analysis and simulations to illustrate the new method and compare with the conventional unsteady-state approach. Through case studies, this work demonstrates that the conventional unsteady-state approach can under or overestimate EOR brine performance due to poor test design or limitations of the conventional method. The proposed method addresses these limitations. The study also discusses how to determine optimal values of fractional flow and total flow rate, both of which are critical test parameters for the new method. Introduction An era of high oil prices has rekindled interest in enhanced oil recovery methods of all kinds, and laboratory apparatuses that have lain unused have been put back to work. Unfortunately, the same methods of measuring EOR performance that have in the past yielded inconclusive results are often still applied. Coworkers of the authors previously reported (Gupta et al. 2011) observations of incremental oil recovery from limestone and dolomite using Advanced Ion Management (AIM), a modified salinity injection process. These experiments used single plugs, the unsteady-state core flood method, and a variety of injection rates. Difficulty interpreting these experiments motivated us to develop a new, improved method. This paper presents a novel, field-representative, coreflood method for measuring EOR benefit in the laboratory. There have been several recent attempts to improve the predictive performance of EOR corefloods, mostly centered on the use of in-situ saturation monitoring, which we highlight here. Sorop and coworkers (2013) report that their low salinity SCAL protocol includes in-situ water saturation monitoring, measurement of relative permeability and capillary pressure, numerical simulation, and combined use of secondary and tertiary flooding. The purpose of in-situ saturation monitoring is to show whether the produced oil is a result of capillary end effects or a reduction in remaining oil along the core. The authors claim that this rigorous multi-experiment process enables application of laboratory results to larger scale simulation predictions. Buikema and coworkers (2011) also used in-situ saturation monitoring to measure the saturation reduction. While applying in-situ saturation monitoring to all EOR corefloods is possible, we will show that using a modified steady-state approach obviates the need for doing so and improves predictive capability. While the proposed approach is applicable to any EOR process it is most beneficial to EOR processes where decoupling of contributions from capillary pressure from other contributions is required for determining the EOR potential of a fluid. Processes that employ wettability-altering agents, such as surfactant addition and salinity modification are therefore of most interest. For pedagogical purpose, we adopt modified salinity injection as the example process throughout this paper. Many of the reported modified salinity experiments suffer from low flow rates, insufficiently long core plugs, too-high water saturations, and a variety of other problems.

This paper is organized as follows. First, the oft-used unsteady state EOR core flood method is described and its limitations enumerated. Next, our proposed modified steady-state method is described. Its advantages are illustrated using a reduced

2 SPE 169088

salinity injection example, although the benefits of the method apply more broadly. Finally, we conclude by summarizing the major findings and placing them in context with the previous experimental and modeling work. Limitations of the Unsteady-State EOR Core Flood Method Corefloods are commonly performed to estimate and compare the displacement efficiency of potential injection fluids. The conventional coreflood test method for estimating the enhanced oil recovery potential of a given injection water is as follows. A base brine (e.g., formation water, produced water, aquifer water, sea water, or mix of them) is injected first at 100% water fractional flow (Fw) into an oil saturated rock(s) at some initial water saturation until oil production is minimal or ceases. The base brine is then immediately followed by injection of a second (test) water of interest at Fw=100%. The EOR potential of the second brine is estimated from the additional oil produced over the base brine oil recovery. Sometimes multiple injection waters are injected in sequence to evaluate their respective EOR potential in comparison to the previously injected waters. At every injection water step, the injection is continued until oil production is minimal or ceases before switching to the next injection water. This conventional approach is an unsteady-state coreflood. This conventional coreflood technique poses several limitations to correctly screen and estimate the EOR potential of injection fluids: 1. Capillary end effects may be significant in conventional coreflood lab tests. The capillary discontinuity at the core end

causes accumulation of oil relative to water. The trapped oil at the end of the core reduces the volume of produced oil, leading to underestimation of oil recovery with both base and test brines. Because interfacial tension (IFT) reduction reduces the capillary end effect, in the case where the second brine reduces IFT, the field-scale oil recovery may be overestimated.

2. In the case where the fractional flow curve of the second brine is significantly shifted in favor of incremental oil recovery compared to a base brine, but the ultimate residual oil saturations are not significantly different between the brines, the conventional coreflood method could significantly underestimate the EOR potential of the second brine. The point is further illustrated with an example (Case Study 2) later in this paper.

3. The injection of the second brine may recover additional oil due to changes in one or more of relative permeability,

viscosity ratio, and capillary pressure. A drawback of the conventional coreflood method is the difficulty of distinguishing among which change(s) contribute to oil recovery. Relative permeability and viscosity ratio shifts matter most to field-scale recovery due to displacement efficiency improvements, while capillary pressure contributions are negligible. Therefore, decoupling contributions from capillary pressure from other contributions is required for determining the EOR potential of a fluid.

4. The oil phase mobility at close to Fw=100% at the outlet is very low. Hence, even for the case where endpoints are shifted, the oil production would be impractically slow and could again lead to underestimation of field-scale second brine performance. However, in field applications the economic limit of water fractional flow (i.e., water-cut) is typically 90-95%, where oil mobility is still significant.

5. Analysis of a typical EOR coreflood relies on an assumption of 100% sweep efficiency. Thus, core heterogeneity may

cause interpretation artifacts in unsteady-state corefloods, particularly for limited brine injection volumes. Description of the New Core Flood Method The new method offers an alternative way to screen EOR injection brines and compare oil recovery performance between a base brine and second brine(s). In this method, the base brine and the oil are injected at an intermediate water fractional flow (0% < Fw < 100%) into an oil-saturated rock(s) having some initial water saturation, and at a constant total flow rate, until a steady-state or close to a steady-state oil saturation is obtained. After obtaining steady-state saturation with the base brine and the oil, the second brine and the oil are injected at the same water fractional flow and total flow rate. The injection of the second brine is continued until steady-state or close to a steady-state saturation is obtained in the rock(s). The EOR potential of the second brine is measured based on the change in water-cut and extent of decrease in oil saturation of the rock(s) compared to the base brine and oil injection. The new method offers an opportunity to measure the base brine and oil steady-state relative permeability curve (Braun and Blackwell 1981) up to the test intermediate Fw point, and estimate the second brine-oil relative permeability curve from the test intermediate Fw and onwards. The obtained relative permeability curves can be used to compare fractional flow curves and measure the shift in the curves at the test intermediate Fw point, if any. For the steady-state relative permeability measurement portion, the test is performed in a closed loop or circulating mode, where the base brine and oil are co-injected through a two-phase separator. The separator interface level is used to determine

SPE 169088 3

rock saturation changes. Since limited fluid quantity is required in the closed loop mode, many pore volumes are generally injected to obtain each steady-state relative permeability point. The second brine is injected in an open loop or non-circulating mode, where the effluent from the core is taken out of the oven and collected. The shrinkage of effluent oil has to be accounted for in rock saturation calculations. The reason for using two different injection modes is to avoid having two different brines in the same separator, which can cause experimental artifacts due to brine density differences, as discussed in Case Study 4 below. Diagram 1 shows a simplified schematic of our modified steady-state laboratory test apparatus. The intermediate Fw and total flow rate values are critical test parameters for the new method. The total flow rate that minimizes capillary end effect artifacts and the intermediate Fw point that optimizes oil recovery response at the outlet are both estimated before the test. The methodology is discussed later in the paper. The new method can be applied to most EOR corefloods including surfactant, alkali, polymer, or their combinations, and Advanced Ion Management (AIM) where selective ions in the injection water are added or removed, or the injection water is diluted (also called low salinity injection) to obtain EOR (Gupta et al. 2011; Seccombe et al. 2008; Vo et al. 2012; Yousef et al. 2010; Zhang et al. 2007) Method for Simulating the Core Flood To illustrate the concept and estimate the experimental outcome, core flood simulations were carried out using ExxonMobil’s in-house reservoir simulation platform. Analytical calculations were used to calculate the steady-state saturation profiles. Huang and Honarpour (1996) performed similar calculations. For a 1-D coreflood, the steady-state water saturation equation is given by,

𝑑𝑆𝑤𝑑𝑥

= �𝑑𝑃𝑜𝑑𝑥

− 𝑑𝑃𝑤𝑑𝑥� 𝑑𝑃𝑐

𝑑𝑥� , ………………. (1)

where,

𝑑𝑃𝑖𝑑𝑥

= 𝑄𝑖𝜇𝑖𝐾𝑖(𝑆𝑤) 𝐴

+ 𝜌𝑖𝑔, for 𝑖 = 𝑜,𝑤. …….. (2) Capillary pressure is assumed zero at the core outlet boundary. The results of the analytical calculations closely match those of the in-house simulator. The new method has been successfully implemented for several EOR lab tests using live brine and live crude oil at reservoirs conditions, and will be published in the future. Results and Discussion Example of the new method To illustrate the new method, an example AIM EOR simulation is considered. The AIM brine is assumed to alter the rock wettability towards a more water-wet condition with no change in saturation end points. Table 1 shows the input rock and fluid properties. The simulated coreflood is performed in a vertical orientation with fluids injected at the bottom. The brine salinities are assumed identical, hence, the viscosity of the initial brine, referred to as the base brine, and the AIM brine are identical. Figure 1 shows the fractional flow and imbibition capillary pressure (Pc) curves used in this example. The first step is to calculate the test intermediate fractional flow. An optimal fractional flow exists based on the method of the experiment and extent of field replication desired. For the above example, Figure 2(a) shows that the maximum oil saturation difference at one pore volume of injection (∆Sw at 1PV) is obtained at Fw=45%. Since both brine and oil are co-injected in this process, the incremental oil recovery sensitivity – the ratio of the incremental oil to the total produced – may not be optimal at the point of maximum oil saturation difference. Because of brine property differences, it is not practical to perform closed loop (circulating mode) steady-state injection with both brines. Hence, at least one brine injection must be performed in an open loop (non-circulating mode) format. Thus, a high water fractional flow (85-95%) may be more suitable for this new method. Fortunately, the significant water saturation change in the region of roughly 40% to 95% water fractional flow enables experimental flexibility. The optimum for this example case is 92% as shown in Figure 2(b), which plots Fw against a multiplication of Sw at 1 PV, front velocity, and fractional flow. The parameterization in Figure 2(b) is based on the concept of optimizing upon the three factors – how much additional oil collected (Sw), how fast (velocity), and with how much oil injected in the system (Fw). A fractional flow of 92% is also comparable to practical field abandonment water-cuts, whereas 45% is too low. The total test flow rate for the method is selected such that the capillary end effect contribution to the change in oil saturation is minimized. Figure 3 shows the water saturation profile at 92% and 100% water fractional flow for various flow rates. Clearly, low flow rates like 0.1 cc/min have significant capillary end effects and can affect the test interpretation. However, flow rates above 0.8 cc/min and 4 cc/min for 92% and 100% fractional flows respectively, have relatively smaller capillary end effect (oil hold up). Hence, for this rock, it would be appropriate to perform the test up to Fw=92% at a total flow rate of 0.8 cc/min and above, and for 100% Fw at a total flow rate of 4 cc/min and above. On the other hand, caution needs to be

4 SPE 169088

exercised that selected total flow rate is not so high that residual saturations and relative permeability start changing due to the change in capillary number. The above estimations of optimal fractional flow and total flow rate require input imbibition relative permeability and capillary pressure data. These data are generally obtained from existing special core analysis (SCAL) data on similar rocks or analogs. However, if no SCAL data are available, then Fw=91% can be used as a reasonable test fractional flow. This rule of thumb is based on the observation that the optimal Fw for most studied systems fell in the range of 89% to 93%. The test flow rate estimation can be replaced by performing a test at a constant pressure drop instead of constant flow rate. The selected pressure drop needs to be sufficiently high that capillary end effects are minimized. The total flow rate at each fractional flow is adjusted to honor the desired pressure drop. In some cases, apparatus or design constraints would require testing at constant pressure drop, even when SCAL data is available. Table 2 shows the flow rates corresponding to a 100 psi pressure drop across the core. Clearly, the flow rates at 92% and 100% Fw are high enough to minimize capillary end effects. Imbibition relative permeability is independent of flow rate (Chen and Wood 2001). Therefore, as long as capillary end effects are minimized, steady state relative permeability measurement at constant flow rate or constant pressure drop should give the same relative permeability curves. In this example, the steady-state relative permeability was measured in the closed loop mode with the base brine and oil at increasing Fw points (given in Table 2) up to the test intermediate fractional flow of 92%. The injection is then switched from the base brine-oil in the close loop mode at Fw=92% to the AIM brine-oil in the open loop mode at Fw=92%, keeping the total flow the same, 0.8 cc/min. The AIM brine is injected until a steady-state is attained and the water-cut stabilized at 92%. Later, the AIM brine is injected at Fw=100%, and unsteady-state imbibition relative permeability curves are obtained using the method of Johnson, Bossler, and Naumann (JBN) (Johnson et al. 1959) One of the benefits of the new method is that both EOR and SCAL experimental data are collected on the same rock-fluid system. Figure 4 and Figure 5 show imbibition relative permeability and fractional flow curves, respectively. A clear shift in both the curves is observed after brine switching. The estimated relative permeability curves exactly match the theoretical input displacement curves, except the small deviation over the high Sw portion of unsteady-state (JBN) curve. This deviation from the theoretical curves at high Sw is due to the capillary end effect, which the JBN method does not account for. The magnitude of imbibition Pc (Figure 1b) increases with increasing Sw; therefore for the same flow rate, capillary end effects are more pronounced at high average core Sw. This can be seen in Figure 3, where the Sw profile for Fw=92% at 0.8 cc/min has negligible oil hold-up at the outlet, while the profile for Fw=100% at 4 cc/min shows significant oil hold-up in the top five cm of the core. Figure 6 shows the water cut profile after switching the brines at Fw=92%. The water cut went down to 58% after 0.28 PV and came back up to 92% after 0.6 PV. For most cases, if the optimal fractional flow is selected properly, the water cut stabilizes within 1 PV. Hence, not much oil needs to be injected in the open loop mode. The shift in fractional curves, and the rate and the quantity of the incremental oil at the test intermediate Fw determines the test brine’s EOR potential. Case Study 1: Wettability-Altering Processes That Shift the Fractional Flow Curve to the Right (with Minimal Pc Impact) This case study describes the cases where the conventional method may underestimate a test brine’s EOR potential. The case is illustrated with the same example used in the above section using Figure 7. The fractional flow curves for the base and the second brines are shown in Figure 1(a). Figure 7 is the same data as Figure 1(a), but zoomed in to show the high water fractional flow regime. Figure 7 shows that the water saturation difference between the base and second brines at Fw=92% results in incremental oil recovery of 10 saturation units (s.u.), while flowing at Fw=99.99% results in incremental oil recovery of about 2.5 saturation units. Figure 8 further illustrates the comparison between the conventional and the new modified steady-state methods. In this example the steady-state water saturation profiles are compared between the base and second brines at fractional flows of 92% and 100%. The saturation profiles are nearly identical for the conventional (Fw=100%) method, but well-separated for the new method (Fw=92%). Clearly, even with significant differences in fractional flow curves (Figure 1a), 100% Fw injection (conventional method) produces small oil saturation differences between the two brines, while the proposed method predicts 10 s.u. of oil recovery. Thus, this new method improves EOR potential estimation versus the conventional coreflood method. Many oil reservoirs are mixed-wet. A mixed-wet rock tends to have the lower residual oil saturation (Sor) compared to oil-wet or water-wet rocks (Jadhunandan and Morrow 1995). Therefore, for an EOR application involving wettability alteration from a mixed-wet state towards more a water-wet condition, instead of no change in saturation end points, the Sor increases. Example fractional flow curves illustrative of this situation can be seen in Figure 9, where the AIM brine Sor is 5% higher than the base brine. The water saturation difference between the base and the AIM brines at Fw=90% results in incremental oil recovery of 5.6 saturation units, while Fw=99.99% results in -1.3 saturation units. Figure 10 shows the expected EOR test responses of both the conventional and new methods. In the conventional approach, no noticeable jump in oil recovery is observed upon switching the brines (Figure 10a). This oil recovery response could be wrongly interpreted that the AIM brine has no EOR

SPE 169088 5

potential. On the other hand, the new method clearly demonstrates the AIM brine’s EOR potential. Figure 10b shows the water cut profile after switching the brines at Fw=90%. The water cut went down to 75% after 0.28 PV and came back up to 90% after 0.6 PV. The overall oil saturation decreased by 5.6%. A similar observation was made by Ligthelm et al. (2009). They showed using oil relative permeability curves that even if a mixed-wet rock has lower ultimate residual oil saturation than a water-wet rock, at practical field or well abandonment water-cut limits, the effective residual oil saturation for a water-wet rock could be lower than mixed-wet rock, and therefore wettability alteration to a water-wet condition can provide EOR benefit. Due to constraints of reservoir rock type or core availability, the coreflood test may have to be performed on heterogeneous rocks. The conventional method may underestimate oil recovery on heterogeneous rock. For the limited throughput, the heterogeneous rock may not sweep 100% and recover less oil. Since the new method uses a steady-state approach where many pore volumes injected, it is a more robust method for heterogeneous rock. Case Study 2: Capillary End Effect Influence for Cases Where Pc Changes with minimal Fractional Flow Curve Shift This case study encompasses situations where the conventional method overestimates a test brine’s EOR potential. The case is illustrated with the new method example where the capillary end effect changes can lead to significant EOR overestimation. During an EOR flood, capillary pressure curves can change due to changes in interfacial tension and/or wettability. Let’s assume a case where both brines have the same fractional flow curve – that of the base brine shown in Figure 1(a) – but have different capillary pressure curves as shown in Figure 1(b). The steady-state water saturation profiles for the AIM and base brines on a half foot core at 1 ft/day (0.06 cc/min) injection rate are shown in Figure 11. The water saturation profile is significantly dominated by capillary end effect. The shift in capillary pressure causes significant change in the oil hold up in the capillary end effect dominated region. In this example, just the change in capillary pressure curves results in 6.3% additional oil recovery. While capillary end effects can significantly influence lab test interpretations, it has minimal impact on field-scale recovery. Figure 12 shows the steady-state water saturation profile at different lengths (normalized) for the same displacement parameters. For the same flow rate, the oil hold up at the outlet decreases with the increase in length scale, and at field-scale it is negligible. For the same example, the capillary pressure curve shift results in ~0% EOR for a 1000 ft. length compared to 6.3% at core scale – conventional coreflooding therefore overestimated the test brine’s EOR potential. The new method minimizes the capillary artifacts by performing the test at higher rates. Further, for the same flow rate, lower Fw has smaller oil hold up from capillary end effects compared to Fw=100%. This is illustrated in Figure 13, which shows the steady-state water saturation profiles at different Fw on a foot long rock at 0.15 cc/min. Decoupling capillary pressure contribution, which could be significant depending on the test design, from relative permeability and viscosity changes is often challenging in the conventional EOR coreflood, and the new method addresses this challenge. Case Study 3: The Effect of Viscosity Reduction This case study describes the case where viscosity reduction reduces low salinity brine’s EOR benefit. This case is illustrated with an example of a favorable wettability alteration towards a more water-wet state using low salinity brine injection in a high salinity reservoir. Figure 14 shows the fractional flow curves for this example. Figure 14a shows the fractional flow curves for the case where salinity modification has no effect on viscosity – both brines have the same viscosity of 0.42 cP and the relative permeability modification results in 3% s.u. change at Fw=90%. However, the more physically realistic case is shown in Figure 14b, which uses the same relative permeability curves used in Figure 14a, but takes into account the viscosity reduction (from 0.42 cP to 0.24 cP) upon switching from the base brine to the AIM brine. The reduction in brine viscosity offsets the enhancement from favorable wettability alteration (i.e., a favorable relative permeability shift), and ~0% shift in saturation is observed at Fw=90% (Figure 14b). The benefit from low salinity injection EOR could be in the single digits (Yousef et al. 2012), and oil recovery loss due to salinity reduction could be significant. Since the new method captures shifts both in fractional flow at practical water-cut and relative permeability curves, it can estimate recovery loss due to salinity reduction. Case Study 4: Effects of Varying Salinity in a Two-Phase Separator This case study describes how a single two-phase separator used to quantify oil production from two different brines can lead to erroneous results. Diagram 2 shows a schematic of a two-phase separator. Generally, a two-phase separator has two limbs that are in communication: the collection limb and the measurement limb. The fluids are injected into and taken out from the collection limb, and the oil production data are estimated by measuring the height of the oil-brine interface in the measuring limb. It is assumed that the interface height will be the same in both limbs. An acoustic signal is sent from the bottom of the separator, through the measurement limb. The signal reflects off the hydrocarbon/brine interface. The transit time for the signal to return to the sensor is measured and from this measurement the height of the oil-brine interface is determined, and thus the oil recovery is measured. However, if the same separator is used to measure oil productions from two different brines in an EOR lab test, it can give erroneous results because the assumption that the height of the oil-brine interface is the same in both the limbs does not hold. The differences in brine density, interfacial tension, and wettability can cause different hydrostatic heads in the two limbs, which can create the appearance of oil production and lead to wrong test interpretation.

6 SPE 169088

This effect pertains to both the new and conventional EOR core flood methods. The case is illustrated through an experiment (not a simulation) where low salinity brine (1,840 ppm) was injected in a separator filled with a high salinity brine (250,000 ppm) and crude oil. There was no core in this experiment. The low salinity brine was injected into the separator at 0.9 cc/min and the effluent brine was taken out of the oven via a back pressure regulator. The injection was performed for about 85 minutes and stopped later. Since no oil was produced in this example, the separator oil volume should not change. However, an apparent increase in oil volume was observed in this experiment. Figure 15 shows the separator oil volume response with time. The oil volume increased up to ~16 cc as low salinity brine replaced high salinity brine in the collection limb. Later, when injection was stopped, the brines continued to diffuse and homogenize, causing the apparent oil volume to decrease (Figure 15). The general indicators of such separator related recovery artifacts are unrealistically high (e.g., 85% +) coreflood oil recovery, relatively flat core pressure drop even with a sharp oil recovery jump upon EOR brine injection, and poor material balance. Since brine density difference dominates this test artifact, it is more profound in low salinity EOR lab tests. Conclusions A new EOR coreflood method is demonstrated in this paper. Through several case studies, it was demonstrated that the conventional unsteady-state approach can under or overestimate EOR brine performance due to poor test design, significant capillary end effects, or the limitations of the conventional method. The new test method addresses these lab artifacts and limitations. This work discussed how to design an effective new test by determining optimal values of fractional flow and total flow rate. To summarize, some advantages of the new method are: 1. Additional oil recovery contributions from relative permeability and/or mobility change can be decoupled from those due

to capillary pressure changes. The shift in fractional curves, and the rate and the quantity of the incremental oil at the test intermediate Fw determines the test brine’s EOR potential.

2. For the same total test flow rate, oil hold up due to capillary end effect is smaller than the conventional method. Further, the test flow rates are optimized to minimize any capillary end effects.

3. Both SCAL and EOR test measurements are obtained on the same rock. Steady-state relative permeability curves can be obtained for the base brine until the point of test intermediate Fw, and unsteady-state relative permeability is obtained from point of test Fw and later. The SCAL data can be used for field-scale simulation.

4. The test is more representative of a field scenario. The new method test is performed at a water-cut comparable to practical field abandonment water-cuts. An optimization on how much oil is injected, collected and the rate of production is used for the test design.

5. The new method procedure eliminates artifacts caused by different brine salinities in a two-phase separator.

Nomenclature

A= Cross-sectional area AIM = Advanced Ion Management EOR = Enhanced oil recovery Fw = Water fractional flow g= gravitational constant IFT= Interfacial tension JBN= Johnson, Bossler, and Naumann (JBN) method Ki(Sw)= Phase permeability (Base permeability times relative permeability) OOIP = Original oil in place Pi= Phase pressure Po= Oil phase pressure ppm= Parts per million PV= Pore volumes Pw= Water phase pressure Qi= Phase flow rate (total flow rate times phase fractional flow) s.u. Saturation units SCAL= Special core analaysis Sw= Water saturation μi= Phase viscosity ρi= Phase density

SPE 169088 7

Acknowledgements We thank Dawn E. Cline, Somnath Sinha, and Rong Xiao for their valuable contributions to this work.

References 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 SPE Annual Technical Conference and Exhibition, San Antonio, TX, 5–7 October. http://dx.doi.org/10.2118/10155-MS

Buikema, T., Mair, C., Williams, D., Mercer, D., Webb, K., Hewson, A., Reddick, C.E.A., and Robbana, E. 2011. Low Salinity Enhanced Oil Recovery: Laboratory to Day One Field Implementation - LoSal EOR into the Clair Ridge Project. Paper B15 presented at the 16th EAGE Improved Oil Recovery European Symposium, Cambridge, UK, 12–14 April.

Chen, A.L. and Wood, A.C. III. 2001. Rate Effects on Water-Oil Relative Permeability. Paper SCA 2001-19 presented at the International Symposium of the Society of Core Analysts, Edinburgh, Scotland, 17–19 September.

Gupta, R., Smith Jr., P.G., Hu., L., Willingham, T.W., Lo Cascio, M., Shyeh, J.J., and Harris, C.R. 2011. Enhanced Waterflood for Middle East Carbonate Cores – Impact of Injection Water Composition. Paper 142668-MS presented at the SPE Middle East Oil and Gas Show and Conference, Manama, Bahrain, 25–28 September. http://dx.doi.org/10.2118/142668-MS.

Huang, D.D. and Honarpour, M.M. 1996. Capillary End Effects in Coreflood Calculations. Paper 9634 presented at International Symposium of the Society of Core Analysts, Montpellier, France, 8–10 September.

Jadhunandan, P.P. and Morrow, N.R. 1995. Effect of Wettability on Waterflood Recovery for Crude-Oil/Brine/Rock Systems. SPE Res Eng 10 (1): 40–46. SPE 22597-PA. http://dx.doi.org/10.2118/22597-PA.

Johnson, E.F., Bossler, D.P., and Naumann, V.O.N. 1959. Calculation of Relative Permeability from Displacement Experiments. Trans. AIME: 370–372.

Ligthelm, D.J., Gronsveld, J., Hofman, J.P., Brussee, N.J., Marcelis, F., and van der Linde, H.A. 2009. Novel Waterflooding Strategy by Manipulation of Injection Brine Composition. Paper SPE 119835 presented at the EUROPEC/EAGE Conference and Exhibition, Amsterdam, The Netherlands, 8–11 June. http://dx.doi.org/10.2118/119835-MS.

Seccombe, J.C., Lager, A., Webb, K., Jerauld, G. and Fueg, E. 2008. Improving Wateflood Recovery: LoSal™ EOR Field Evaluation. Paper SPE 113480 presented at the SPE/DOE Symposium on Improved Oil Recovery, Tulsa, Oklahoma, 20–23 April. http://dx.doi.org/10.2118/113480-MS.

Sorop, T.G., Suijkerbuijk, B.M.J.M., Masalmeh, S.K., Looijer, M.T., Parker, A.R., Dindoruk, D., and Goodyear, S. 2013. Accelerated Deployment of Low Salinity Waterflooding in Shell. Paper A09 presented at the 17th European Symposium on Improved Oil Recovery, St. Petersburg, Russia, 16–18 April.

Vo, L.T., Gupta, R., and Hehmeyer, O.J. 2012. Ion Chromatography Analysis of Advanced Ion Management Carbonate Coreflood Experiments. Paper SPE 161821 presented at Abu Dhabi International Petroleum Conference and Exhibition, Abu Dhabi, UAE, 11–14 November. http://dx.doi.org/10.2118/161821-MS.

Yousef, A.A., Liu, J.S., Blanchard, G.W., Al-Saleh, S., Al-Zahrani, T., Al-Zahrani. R., and Al-Mulhim, N. 2012. Smart Waterflooding: Industry's First Field Test in Carbonate Reservoirs. Paper SPE 159526 presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8–10 October . http://dx.doi.org/10.2118/159526-MS.

Yousef, A.A., Al-Saleh, S., Abdulaziz, A.-K., and Mohammed, A.-J. 2010. Laboratory Investigation of Novel Oil Recovery Method for Carbonate Reservoirs. Paper SPE 137634 presented at Canadian Unconventional Resources and International Petroleum Conference, Calgary, Alberta, Canada, 19–21 October. http://dx.doi.org/10.2118/137634-MS.

Zhang, Y., Xie, X. and Morrow, N.R. 2007. Waterflood Performance by Injection of Brine with Different Salinity for Reservoir Cores. Paper SPE 109849 presented at the SPE Annual Technical Conference and Exhibition, Anaheim, California, 11–14 November. http://dx.doi.org/10.2118/109849-MS.

.

8 SPE 169088

Table 1: Rock properties. Ko @ Sw,i (mD) 20 L (cm) 30 A (cm2) 11.4 Φ (% PV) 25 μw (cP) (base brine)

0.42

μw (cP) (AIM brine)

0.42

μo (cP) 1 Swir 0.1 Sorw 0.2

Table 2: Flow rate corresponding to the water fractional flow at 100 psi pressure drop. Fw (%)

Flow Rate (cc/min)

0 2.76 1.5 1.58 5 1.19 10 0.98 20 0.80 45 0.67 70 0.68 92 0.92 100 4.65

SPE 169088 9

Diagram 1: Schematic diagram of a lab test apparatus.

Diagram 2: Schematic diagram of a two phase separator.

Brine out

Effluent in Calibration ring

Transducer Assembly

Oil out

Measurement limb Collection limb

10 SPE 169088

1(a)

1(b)

Figure 1: New method example, (a) fractional flow curves, and (b) imbibition capillary pressure curves.

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 0.2 0.4 0.6 0.8 1

Fw

Sw

Base Brine

AIM Brine

-40

-30

-20

-10

0

10

20

30

0 0.2 0.4 0.6 0.8 1

Pc (p

si)

Sw

Base BrineAIM Brine

SPE 169088 11

2(a)

2(b)

Figure 2: Response sensitivity with water fractional flow.

0%

2%

4%

6%

8%

10%

12%

0 0.2 0.4 0.6 0.8 1

Δ Sw

aft

er 1

PV

Inje

ctio

n

Fw

0

2

4

6

8

10

12

14

16

18

0 0.2 0.4 0.6 0.8 1

% Δ

Sw @

PVI

*Fw

*Vel

ocity

Fw

Maximum at 45%

Maximum at 92%

12 SPE 169088

3(a)

3(b)

Figure 3: Water saturation profiles at Fw of (a) 92%, and (b) 100%.

0.2 0.25 0.3 0.35 0.4 0.45 0.50

5

10

15

20

25

30

Sw

Leng

th(c

m)

0.05 cc/min0.1 cc/min0.2 cc/min0.8 cc/min1.5 cc/min

0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 10

5

10

15

20

25

30

Sw

Leng

th(c

m)

0.2 cc/min0.5 cc/min1 cc/min2 cc/min4 cc/min6 cc/min

Outlet

Inlet

Outlet

Inlet

SPE 169088 13

Figure 4: Imbibition relative permeability curves obtained from the new method.

1.0E-04

1.0E-03

1.0E-02

1.0E-01

1.0E+00

0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0

Rel

ativ

e Pe

rmea

bilit

y (fr

ac K

ocw

)

Water Saturation (frac PV)

Steady-state KrwSteady-state KroJBN KrwJBN KroTheoretical Krw (Base Brine)Theoretical Kro (Base Brine)Theoretical Krw (AIM brine)Theoretical Kro (AIM brine)

14 SPE 169088

Figure 5: Fractional flow curves obtained from the new method example.

Figure 6: Water cut versus AIM brine pore volumes injection after switch the brines at Fw=92%.

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 0.2 0.4 0.6 0.8 1

Fw

Sw

Base Brine (Theoretical)AIM Brine (Theoretical)JBN (AIM brine)Steady-state

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0 0.2 0.4 0.6 0.8

Wat

er C

ut a

t the

out

let

AIM brine PV Injected

SPE 169088 15

Figure 7: Fractional flow curves for the base and AIM brines, (a) saturation difference at Fw=0.9999, (b) Saturation

difference at Fw=0.92.

Figure 8: Comparison of water saturation profile with the base brine and the AIM brine at Fw of 92% and 100%.

0.9

0.92

0.94

0.96

0.98

1

0.4 0.5 0.6 0.7 0.8

Fw

Sw

Base Brine

AIM Brine

∆Sw at Fw=0.92

∆Sw at Fw=0.9999

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 10

5

10

15

20

25

30

Sw

Leng

th(c

m)

Fw=100% (Base brine)Fw= 92% (Base brine)Fw=100% (AIM brine)Fw= 92% (AIM brine)

10%

~2.5%

Inlet

Outlet

16 SPE 169088

Figure 9: Fractional flow curves for case study 1.

10(a)

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9

Fw

Sw

Base brineAIM brine∆Sw at Fw=0.9 ∆Sw at fw=0.9999

0%

10%

20%

30%

40%

50%

60%

70%

80%

0 10 20 30 40 50

Oil

Reco

very

(% O

OIP

)

PV Injected

Brin

e Sw

itch

-1.3%

5.6%

SPE 169088 17

10(b)

Figure 10: EOR test response for mixed-wet system in case study 1(a) conventional method (Fw=100%), and (b) the new

method (Fw=90%).

Figure 11: Steady-state water saturation profile in a half foot core at 1ft/day injection rate.

60%

65%

70%

75%

80%

85%

90%

95%

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9

Wat

er C

ut

AIM brine PV Injected

0.1 0.2 0.3 0.4 0.5 0.6 0.70

5

10

15

Sw

Leng

th(c

m)

Fw= 100% (Base brine)Fw= 100% (AIM brine)

Inlet

Outlet

18 SPE 169088

Figure 12: Steady-state water saturation profile at variable lengths (normalized) at 1ft/day injection rate.

Figure 13: Steady-state water saturation profile at different water fractional flows (case study 2).

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 10

0.2

0.4

0.6

0.8

1

Sw

Nor

mal

ized

Len

gth

L= 1ftL= 10ftL=1000 ft

0.2 0.3 0.4 0.5 0.6 0.7 0.80

5

10

15

20

25

30

Sw

Leng

th(c

m)

Fw=25%Fw=50%Fw=90%Fw=100%

Inlet

Outlet

Outlet

Inlet

SPE 169088 19

14(a)

14(b)

Figure 14: Fractional flow curves for the base brine and the AIM brine, where (a) both brines have similar viscosity, and (b) AIM brine has lower viscosity.

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 0.2 0.4 0.6 0.8 1

Fw

Sw

Base Brine

AIM Brine

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 0.2 0.4 0.6 0.8 1

Fw

Sw

Base Brine

AIM Brine

20 SPE 169088

Figure 15: Separator oil volume response with time (case study 4).

0

2

4

6

8

10

12

14

16

18

20

0 25 50 75 100

Sepa

rato

r Oil

Volu

me

incr

ease

(cc)

Tme (minutes)

Low salinity brine injection (0.9 cc/min)

No flow