SPE 153869

Low Salinity EOR in Carbonates J. Romanuka, SPE, J.P. Hofman, D.J. Ligthelm, SPE, B.M.J.M. Suijkerbuijk, SPE; A.H.M. Marcelis, S. Oedai, N.J. Brussee, H.A. van der Linde, Shell GSI BV; H. Aksulu, T. Austad, SPE, University of Stavanger Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the Eighteenth SPE Improved Oil Recovery Symposium held in Tulsa, Oklahoma, USA, 14–18 April 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 Modifying the chemistry of injection water yields improved wettability behavior on carbonate rock surfaces. Previous work has focused on demonstrating the effect of modified brine formulation on particular carbonate samples. Here the results of a more general screening study consisting of Amott spontaneous imbibition experiments on the samples from oil-bearing zones and from outcrops of different carbonate formations are reported.

Tertiary incremental oil production due to increased water-wetness was observed upon transition to brine of lower ionic strength. Additional oil recovery from the spontaneous imbibition tests ranged from 4 to 20% of OIIP (Oil Initially In Place), reflecting a large variability in the response and indicating a high complexity of the mechanism(s). Consistent with numerous published reports, Stevns Klint outcrop chalk samples were a clear exception and exhibited increased oil recovery with increasing sulfate ion concentration. These did not respond to lowering the salinity of the imbibing brine. Tertiary oil recovery from samples containing evaporites occurred simultaneously with dissolution of salt minerals, as evident from brine analysis. However, incremental oil recovery in the same range was measured for samples without evaporites but from the same geological formation. Hence, mineral dissolution as a mechanism for enhanced oil recovery could not be confirmed.

The results show that injection of low salinity brine into carbonate reservoirs has potential as an EOR technology. However, additional research is needed to improve the understanding of the underlying chemical and physical mechanisms and improve a priori predictability. Introduction During the last two decades a significant body of evidence has accumulated, indicating that recovery from sandstone oil reservoirs could be improved by lowering the ionic strength of the injection brine (reviewed in Morrow and Buckley 2011). Benefits of low salinity as opposed to high salinity water flooding have been supported by numerous laboratory tests (reviewed in Sheng 2010), Log-Inject-Log trial (Webb et al. 2004), single well chemical tracer tests (McGuire et al. 2005), and historical data (Vledder 2010). An extensively discussed mechanism behind this low salinity phenomenon in sandstones is wettability alteration of the clay minerals towards a more water-wet state which in turn improves microscopic sweep by modifying oil and water relative permeabilities (Ligthelm et al. 2009). Despite growing interest in low salinity flooding, a consistent explanation of the wettability alteration mechanism has not yet emerged. However, it is generally accepted in the industry that injecting brine with TDS (Totally Dissolved Solids) below 5,000 ppm leads to additional oil recovery whereas injection of more saline water will not (Webb et al. 2005a). The threshold value is a balance between improvement of oil recovery by low salinity brine injection and prevention of formation damage due to swelling and/or deflocculation of salinity-sensitive clays present in sandstone rocks.

Currently, studies on improving oil recovery by modifying the chemistry of the injection brine are being extended to carbonate oil reservoirs as is apparent from an increasing number of related publications. Scientific interest in the topic was stimulated by the historical observation of unexpectedly high oil recoveries upon injection of seawater into the fractured chalk reservoirs under the North Sea (Hallenbeck et al. 1991; Sylte et al. 1988). A large part of the research on this topic was conducted in the laboratory of Prof. T. Austad at the University of Stavanger (Norway). During years of research into the effect of seawater on the wettability of Stevns Klint outcrop chalk, a widely used North Sea chalk reservoir analogue, Austad and his coworkers have identified that the effect can be attributable to the type and relative concentration of Potential Determining Ions (PDI), i.e. Mg2+, Ca2+, and SO4

2- (Austad et al. 2005; Zhang et al. 2006a, 2006b; Strand et al. 2006). It has been suggested that sulfate, which is abundantly present in seawater, will adsorb onto the positively charged sites on the chalk surface and thereby lower the positive surface charge. Because of a reduction in the electrostatic repulsion, excess Ca2+ will be localized closer to the chalk surface, where it may react with adsorbed oil polar compound, i.e., carboxylic acids.

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Then calcium carboxylate complex can be released from the surface. At high temperatures, Mg2+ may displace Ca2+ in the calcium carboxylate complex (Zhang et al. 2007). In addition, contact angle measurements performed by Gupta et al. (2011) showed that symbiotic action of Mg2+, Ca2+, and SO4

2- is necessary to alter the wettability of a calcite plate surface. Additional evidence of the ability of sulfate ions to displace carboxylic acids from the calcite surface was provided in the study by Rezaei Gomari et al. (2006). The authors determined water vapor adsorption isotherms of calcite powder and observed an appreciable reduction in adsorbed fatty acids in the presence of sulfate.

The above described studies were performed using clean outcrop chalk samples or crystalline calcite substrates. To verify these observations made in the model systems, Webb et al. (2005b) studied a core from a North Sea chalk reservoir under complete reservoir conditions, using live crude oil and brine. They observed enhanced oil recovery in the presence of sulfate in the imbibing brine, which was due to an increase in the positive part of the capillary pressure curve. Fjelde and Aasen (2009) also reported that a formation water/seawater mixture has more potential to increase oil recovery than pure formation water from the chalk reservoir material. Therefore, there is significant experimental evidence that sulfate could act as a wettability alteration agent for the chalk surface. On the other hand, a recent study by Ferno et al. (2011) showed that this approach cannot be applied to all types of chalks. The authors measured additional oil recovery in spontaneous imbibition tests from aged outcrop core plugs from three different chalk quarries (Stevns, Rordal, and Niobrara) that were placed into brine with and without sulfate. The results indicated that the effect of sulfate was dependent on the chalk type because increased oil recovery was only observed in the Stevns Klint outcrop chalk.

The possibility of using sulfate as a main wettability modifying ion for limestones was demonstrated by Strand et al. (2008) and Ligthelm et al. (2009). Strand et al. (2008) compared the imbibition behavior of two identically prepared limestone plugs: one plug imbibed with seawater and the other with seawater without sulfate. The oil recovery from the plug immersed into seawater was about 15% higher than from the plug immersed into seawater without sulfate. Ligthelm et al. (2009) demonstrated higher oil recovery with higher sulfate content in the brine by spontaneous imbibition tests on a microcrystalline limestone. In addition to sulfate, also phosphate and borate ions were demonstrated to increase oil recovery from limestone rock samples by coreflooding experiments (Gupta et al. 2011). The authors replaced SO4

2- in seawater by either BO3

3- or PO43- and measured absolute incremental oil recoveries of 15.6 and 21.3% OIIP (Oil Initially In Place) for

BO33- or PO4

3- respectively. Apart from increasing concentration of surface interacting ions in the injection water, another approach for wettability

modification was investigated. There is some experimental evidence suggesting that the wettability of carbonate rock can also be altered by a reduction of the ionic strength of the brine. Almehaideb et al. (2004) measured the contact angle between a limestone disk and crude oil in NaCl solutions of various ionic strengths at room temperature. The authors reported reduction in the contact angle from 48 ° to 29 ° when salinity was reduced from 50,000 ppm to 10,000 ppm. Also Alotaibi et al. (2010) observed a lower contact angle for aquifer water (TDS 5,436 ppm) than for formation water (TDS 230,000 ppm) or seawater (TDS 54,000 ppm) for both calcite crystal and Laurda limestone.

Yousef et al. (2011) took the next step in investigating the effect of salinity and ionic composition of the injection brine on the wettability of carbonate rocks. Two coreflooding experiments were performed giving consistent results: absolute incremental oil recovery of ∼7-8.5% was observed upon injection of twofold diluted seawater (TDS 28,835 ppm); followed by a ∼9-10% using 10 times diluted seawater (TDS 5,767 ppm), and a further ∼1-1.6% with 20 times diluted seawater, all in terms of OOIC (Original Oil In Cores). It was discussed that the driving mechanism for incremental recovery was wettability modification possibly due to alteration of the surface charge of the carbonate rock.

To summarize, currently there is laboratory evidence supporting two approaches that can be used to modify wettability of carbonate rocks under certain conditions:

1. Increasing concentration of surface interacting ions, i.e. SO42-, BO3

3- or PO43- in the injection brine

2. Lowering ionic strength of the injection brine The studies described above were usually limited to samples from only one or two carbonate oil reservoirs. This paper contains the results of a larger-scale screening study performed using samples from oil-bearing zones of four carbonate formations and two outcrops. Both approaches to modify wettability of the selected carbonate samples have been tested, i.e., manipulation of the ionic composition of the brine and application of low ionic strength brine. The method of choice was largely determined by the waterflood opportunities in the field under scrutiny.

The potential of various brines to change the wettability of carbonate rock samples and therefore increase oil production was assessed by the Amott Spontaneous Imbibition (SI) test that is a common tool for qualitative wettability measurement (reviewed in Anderson 1986, Ligthelm et al. 2009). The Amott SI test is the method of choice for screening studies because it does not require large amounts of core material, it is labor efficient, and it can be conducted using a large number of samples simultaneously.

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Materials and Methods Oil

Crude oil from three oil reservoirs was used for the experiments. Physical and chemical properties of the selected crude oils are listed in Table 1. Brines

Synthetic brines were prepared in the laboratory from distilled water and reagent-grade chemicals. The composition of the brines used in the experiments are listed in Table 2. Formation water is referred to as “FW”, synthetic seawater as “SSW”, various wettability modifying brines are referred as “WM”, and AW = Aquifer Water. Rock samples

For each rock type, samples were selected from one reservoir interval, when possible, to have similar geological and petrophysical properties between replicates/different experiments. Table 3 lists various properties of the rock samples used in the experiments. Each rock type is briefly described below.

Stevns Klint outcrop chalk. The rock material is a Maastrichtian high porosity, low-permeable coccolith chalk. The main porosity type is fine-interparticle porosity. The samples have a mudstone depositional texture. Three samples of Stevns Klint outcrop chalk were prepared using the FW1 brine and crude oil A. The test was conducted at 60 °C.

Limestone 1. The samples originate from the interval of wackestone/packstone depositional texture. The porosity consists of microporosity within the lime mud matrix and the leached micritic grains. Trace amounts of pyrite are present. Four samples were prepared with FW2 as initial water and crude oil from the same reservoir, here denoted A. Spontaneous imbibition tests were carried out at 70 °C.

Limestone 2. Samples Lim2.1, Lim2.2, Lim2.3, and Lim2.4 have pelloidal packstone depositional texture. X-Ray Diffraction (XRD) analysis revealed that this rock type contains 95% calcite and 4% quartz. It is consistently observed that larger pores and vugs are partially filled with dolomite and pyrite crystals (Fig. 1). The pore system is heterogeneous. Three types of porosities are observed: microporosity in the matrix, intraskeletal porosity and vuggy porosity. Samples Lim2.5 and Lim2.6 were plugged from a different lithostratigraphic reservoir layer. This layer is characterized by a highly heterogeneous macropore system. Algae pack/grainstone- boundstone depositional textures were observed. Spontaneous imbibition tests were carried out at two temperatures, 70 °C and 120 °C. Samples were prepared with the FW3 as initial water and crude oil from the same reservoir, here denoted B.

Limestone 3. The rock is a skeletal wackestone. The dominant pore type is represented by irregular shaped vugs (Fig. 2). The XRD analysis shows a composition of 97-98% calcite and 3-2% quartz, depending on the depth. The duplicate samples were prepared with the FW2 as initial water and crude oil denoted A. These are the same conditions as for the Limestone 1 and Silurian dolomite. Spontaneous imbibition tests were carried out at 70 °C on the duplicate samples to assess reproducibility of the results.

Dolostone 1. The rock is characterized as dolosparite with intercrystalline porosity. Various amounts of replacive anhydrite cement occur in the samples from different depths, as well as calcite cement between the dolo-rhombs (Fig. 3). Four samples were prepared with the high salinity FW4 brine and crude oil from the same reservoir, here denoted as C. The experiments were carried out at the reservoir temperature, i.e. 85 °C.

Dolostone 2 (Silurian outcrop dolomite). The rock is characterized as sucrosic dolomite with an intercrystalline porosity. According to XRD analysis, the rock contains 99% dolomite and 1% quartz. Trace amounts of pyrite were observed by Scanning Electron Microscope (SEM). Spontaneous imbibition tests were carried out at 70 °C. Samples were prepared with FW2 as connate water and crude oil denoted A.

Preparation of rock samples. All reservoir samples used for this study were restored, i.e., the samples were cleaned by solvents and subsequently dried. Outcrop samples were used without any prior cleaning. After measuring basic parameters such as porosity and permeability, the cores were saturated with formation water and centrifuged to obtain the desired initial water saturation. Samples which were too fragile to undergo centrifugation were brought to initial water saturation by the evaporation method. First, samples were fully saturated with diluted artificial formation brine in the vacuum vessel. Then samples were allowed to dry and the weight was monitored to reach the desired water saturation. Since the samples were saturated to 100% with the diluted brine, upon drying, water evaporated but concentration of ions increased and ultimately reached the concentration in the formation water. After reaching the target water saturation (Swi) the samples were wrapped in cling film, put in a humidified container (to prevent evaporation), and put away for a few days to allow even distribution of the brine inside the sample. Next, samples at initial water saturation were placed into a container with dead crude oil to bring them to initial oil saturation. Full replacement of the air by oil was achieved by pressurizing the container in a pressure vessel. Then the samples were aged at reservoir temperature for at least four weeks to restore wettability towards reservoir conditions. Fluid saturation was checked by material balance and electrical resistivity measurements. Amott Spontaneous Imbibition Tests

The experimental set-up is schematically shown in Fig. 4a. In a typical Amott spontaneous imbibition test, a plug, saturated with crude oil and highly saline formation water, was put in a glass container, i.e. an Amott cell, and surrounded by the same highly saline formation water. Oil production occurs by spontaneous imbibition until capillary equilibrium is reached. Subsequently, the surrounding formation brine is replaced by a WM-brine. The process of spontaneous imbibition is schematically shown in Fig. 4b. As Amott spontaneous imbibition tests were conducted at elevated temperatures (60, 70 and

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85 °C), it was important to minimize oil production due to its thermal expansion. Therefore each component (Amott sample holder, brine, and sample in crude filled jar) was heated to the experimental temperature before assembling. During the tests conducted at 120 °C, the core holders were assembled at room temperature, placed into an air circulation oven and heated up to 120 °C in four hours, while the pressure was maintained at 30 bar at all times. The imbibition time monitoring began as soon as the assembly of the Amott set-up was complete. The produced oil by capillary imbibition was measured regularly during the test by visual inspection at the top of the imbibition cell. The amount of oil recovered was recorded as a function of time as a percentage of OIIP. Results Amott spontaneous imbibition tests for the samples from the oil-bearing zones were performed at conditions as similar as possible to reservoir conditions, with respect to formation water composition, crude oil as well as temperature. Wettability modifying brines were designed based on the composition of these available for injection in the field. Initial water saturation is one of the parameters that will influence the rate of water imbibition into the rock samples (Anderson 1986). Therefore the aim was to prepare samples with a similar amount of initial water (Table 3).

Stevns Klint outcrop chalk

Spontaneous imbibition of the chalk samples placed in synthetic formation water (FW1) resulted in production of approximately 40% of OIIP (Fig. 5). When the capillary equilibrium was reached and oil production ceased, the formation water was replaced by “wettability modifying” brines (WM) with varying sulfate concentration. Samples placed into the brines with [SO4

2-] of 43 mM and 99 mM showed increases of 7 and 10% in oil production, respectively. The sample placed into brine WM1 with [SO4

2-] of 19 mM showed a lower additional oil recovery of 5% with an overall slower imbibition rate. It is important to note that wettability modification took place at lower ionic strength than the ionic strength of formation water, but the highest oil recovery was observed at the highest SO4

2- concentration and not at the lowest ionic strength. This observation is consistent with numerous literature reports stating that sulfate is able to render wettability of the Stevns Klint chalk towards a more water-wet state (Austad et al. 2005; Zhang et al. 2006a, 2006b; Strand et al. 2006; Fjelde and Aasen 2009). After completion of the spontaneous imbibition test of Chalk 2 with WM2 brine the sample was transferred into a pure NaCl solution with low salinity (1,050 mg/L; I = 0.02 mol/L), but no additional oil was recovered over a month of observation (data not shown).

Limestone 1

Oil recovery from the Limestone 1 samples due to the FW2 brine imbibition ranged from 6 to 10% of OIIP (Fig. 6). When FW2 was replaced by high salinity produced water (PW) (I = 3.75 mol/L), sample Lim1.1 produced an insignificant amount of 1% of OIIP. Replacement of PW brine by low salinity aquifer water with added Ca2+, Mg2+ and SO4

2-, up to concentrations found in seawater (AW_CaMgSO4), triggered oil production amounting to 3% OIIP of incremental oil recovery (Fig. 6a). The ionic strength of the AW_CaMgSO4 brine is significantly lower than that of produced water (IPW = 3.75 mol/L vs IAW_CaMgSO4 = 0.25 mol/L), hence it is not possible to determine whatever wettability alteration took place due to lowering ionic strength or due to increasing concentration of Ca2+, Mg2+, SO4

2- ions. Additional oil recovery of 3% OIIP was measured for imbibition of a brine containing no PDIs but with a low ionic strength (I = 0.14 mol/L) into sample Lim1.2 (Fig. 6b), indicating wettability alteration towards a more water-wet state. When Ca2+, Mg2+, SO4

2- were added to the same brine, no oil production occurred (Fig. 6b). Results of the test conducted with sample Lim1.3 further support the hypothesis that wettability of this limestone rock was altered by lowering the ionic strength of the imbibing brine rather than action of the Ca2+, Mg2+, SO4

2- ions. Incremental oil recovery of 4% OIIP was observed for the brine with I = 0.2 mol/L and [SO42-] =

0 mM, i.e. AW_0SO4, while adding sulfate to the same brine again had no effect on the wettability (Fig. 6c). Also Lim1.4 showed incremental oil recovery after a change from FW2 to a NaCl solution (I = 0.18 M, similar to the AW series). An incremental recovery of 3% OIIP was measured, and refreshment of the NaCl solution triggered additional oil production amounting to 2% OIIP (Fig. 6c). The additional oil recovery upon refreshment can be explained by mixing of the brines with a large contrast of salinities inside the porous media due to molecular diffusion. The difference in salinities for FW2 and NaCl solution is significant, so inside the plug, upon mixing, the effective salinity was still higher than 10,500 mg/L, which is the salinity of the NaCl solution used during the second stage of the experiment. It has been estimated that upon the first change salinity was still 30% higher than the salinity of the used NaCl solution. To conclude, it has been consistently observed that lowering the ionic strength of the imbibing brine leads to incremental oil recoveries (2-4% OIIP). However, the wettability shift towards a more water-wet is limited for the Limestone 1 rock material.

Limestone 2

Oil recovery from the Limestone 2 samples due to the FW3 brine imbibition was 3 and 4% OIIP for samples at 70 °C (Fig. 7a). For the samples at temperature of 120 °C, oil recovery ranged from 8.7 to 14.5% (Fig. 7b). It was estimated that on average some 15% of the oil production is assigned to thermal expansion when the SI tests were conducted at 120 °C. Therefore oil recovery is higher at a higher temperature.

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Oil production resumed from all samples and amounted to an additional recovery between 1 and 5% of OIIP when the samples were exposed to SSW. Hence, SSW caused a wettability change of the Limestone 2 rock towards a more water-wet state. It is not possible to decide on whether increased oil recovery was due to an increase in the PDI concentration, according to the mechanism proposed by Strand et al. (2006) or lowering the ionic strength of the brine as both parameters differ between the FW3 brine and SSW. Seawater contains 10 times higher concentration of sulfate but has more than 5 times lower ionic strength than the FW3 brine (Table 2). As these samples showed a response to SSW similar to Stevns Klint outcrop chalk, in the next step these samples were placed into SSW with NaCl removed, as this brine composition previously demonstrated the ability to modify the wettability of Stevns Klint samples (Jafar Fathi et al. 2011). There was oil production of 2% OIIP observed only for sample Lim2.6. As neither of the other samples exhibited oil production, incremental oil recovery from sample Lim2.6 is considered to be an experimental artifact. To conclude, removal of NaCl from the seawater (SSW_0NaCl) had no effect on the wettability of Limestone 2 (Fig. 7).

Limestone 3

Oil recovery for the Limestone 3 plugs imbibed with high salinity formation water ranged from 0 to 2% of OIIP, indicating a strong preference of these samples for oil (Fig. 8). Subsequently, the samples were exposed to several brines in order to induce further oil production by spontaneous imbibition.

There was hardly any imbibition of the SSW (I = 0.66 mol/L) into samples Lim3.1A and Lim3.1B, resulting in an incremental oil recovery of 0.2% OIIP for both samples (Fig. 8a). Imbibition of the brine that comprised FW2 and WM4 brines mixed at the ratio of 1:9 (1:9 FW2/WM4), with somewhat lower ionic strength of 0.46 mol/L, was more efficient (Fig. 8b). The incremental oil recoveries were 1.8 and 2.9% OIIP for the samples Lim3.2A and Lim3.2B, respectively. The highest recoveries were measured from the samples Lim3.3A and Lim3.3B which were placed into the WM4 brine, which was the brine with the lowest ionic strength (I = 0.02 mol/L) (Fig. 8c). Incremental oil recoveries of 19.3 and 18.5% OIIP were measured for samples Lim3.3A and Lim3.3B, respectively. The effect of low salinity WM4 brine on the wettability of Limestone 3 was further substantiated when the samples in the Lim3.1 and Lim3.2 series were also placed into the WM4. Significant oil recoveries of 13.2 and 21.1% of OIIP were measured (Fig. 8a). During this stage of the experiment, the WM4 brine was refreshed for the samples Lim3.3A and Lim3.3B. Another reduction in ionic strength took place upon refreshment triggering oil production because the brine inside the pores of the plugs Lim3.3A and Lim3.3B had still relatively high salinity due to mixing of the high salinity formation water and WM4 (Fig. 8c). Reproducibility of the results was good with the maximal difference between the total oil recoveries measured for the duplicate samples of 2% of OIIP. The experiment demonstrated that oil-wetness of this limestone rock could be lowered by reducing the ionic strength of the brine, while sulfate concentrations were low at 2 mM and identical for the wettability-modifying brine and formation water. However, one cannot exclude that the samples history, i.e., the presence of sulfate in the initial water or in the brine that had previously interacted with the sample, influenced the overall outcome of the experiment.

Dolostone 1

Dolostone is, differently from limestone, primarily composed of dolomite (CaMg(CO3)2) instead of calcite (CaCO3). The Dolostone 1 rock material used in this study is particular, as it contains evaporites, i.e. the minerals anhydrite (CaSO4) and halite (NaCl). Both minerals have a higher solubility than pure calcite or dolomite. The solubility product (Ksp) of anhydrite is 4.93 × 10-5 while Ksp of calcite is 3.36 × 10-9 and reported values of Ksp for dolomite range from 10-17 to 10-20 (Jingwa Hsu et al. 1963). According to the thin section analyses, samples Dol1.1 and Dol1.2 have abundant replacive anhydrite cement and samples Dol1.3 and Dol1.4 contain a moderate amount of anhydrite.

Oil production from the Dolostone 1 samples over time by spontaneous imbibition of various brines is shown in Fig. 9. One can expect dissolution when samples containing anhydrite are exposed to the brine undersaturated with respect to calcium sulfate. To monitor dissolution and to assess any other possible changes in the brine chemistry during the spontaneous imbibition tests, samples of the surrounding brine were taken upon completion of each imbibition step. Initial ionic compositions and the composition of the surrounding brine at the end of the imbibition step for four brines are shown in Fig. 10.

Oil recovery due to imbibition of the high salinity FW4 brine ranged from 3 to 10% OIIP (Fig. 9). Observed variation in the oil recovery from the four samples signifies compositional differences between the samples as they were plugged at various depths. When the brine was replaced by the lower ionic strength brine WM5, oil production resumed from all samples. Again, the spread in the observed incremental recoveries was large and ranged from 5 to 18% of OIIP (Fig. 9). Analyses of the surrounding brine revealed that there is an increase in ionic concentration due to mixing of the high salinity brine in the pores and the low salinity surrounding brine. However, the significant increase in Ca2+ and SO4

2- concentration cannot be explained only by mixing and is most likely due to anhydrite dissolution (Fig. 10b). The increase in calcium and sulfate concentration varies from sample to sample, corresponding to different anhydrite contents of the samples. To draw more refined conclusions, e.g. to determine degree of dissolution and mixing, numerical simulations coupled with rigorous water chemistry modeling are required.

Upon refreshment of the WM5 brine, additional oil production was observed from the samples Dol1.1, Dol1.2 and Dol1.4. Dissolution of anhydrite took place for the samples Dol1.1 and Dol1.2 as determined by analyses of the surrounding brine (Fig. 10c). Then all samples were transferred into the five times diluted WM5 brine. Again, oil production due to the

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1/5WM5 brine imbibition was observed for three out of four samples (Dol1.1, Dol1.2 and Dol1.4). The recoveries were lower than for the first imbibition of the WM5 brine and amounted to 3-4% of OIIP. Dissolution of anhydrite was evident in the samples Dol1.1 and Dol1.2 as observed by an increase in Ca2+ and SO4

2- concentration in the surrounding brine (Fig. 10d).

Next, to assess the contribution of the dissolution of anhydrite to the oil production, we compared the incremental oil recovery due to spontaneous imbibition from two samples: sample Dol1.1, that has abundant replacive anhydrite cement, and Dol1.3, that contains moderate amounts of anhydrite (Fig. 3). Dissolution of anhydrite was qualitatively evaluated by the absolute concentration of calcium and sulfate ions in the surrounding brine. As illustrated in Fig. 11, oil recovery, due to imbibition of WM5 brine, from the sample Dol1.3 was higher than for the sample Dol1.1, i.e., 18% OIIP and 15% of OIIP, respectively, while sample Dol1.3 exhibited only moderate anhydrite dissolution. However, during the two following imbibition steps, incremental recovery was higher from the sample Dol1.1 that also continued showing signs of anhydrite dissolution. Therefore, it is concluded that, in this case, anhydrite dissolution may be a contributing factor to the incremental oil recovery rather than a determining mechanism. Incremental oil recovery due to wettability alteration was observed in the absence of significant anhydrite dissolution.

Dolostone 2 (Silurian dolomite outcrop)

About 8% of OIIP and 6% of OIIP was recovered by spontaneous imbibition with FW2 from the samples Dol2.1 and Dol2.2 (Fig. 12). During progressive imbibition of SSW, low incremental recoveries of 1 and 2% OIIP were measured for the samples Dol2.1 and Dol2.2, respectively. When the samples were transferred into 10× diluted seawater, oil recovery resumed from both samples amounting to additional oil recovery of 9 and 14% OIIP for the samples Dol2.1 and Dol2.2, respectively. Therefore, wettability alteration of the Silurian dolomite outcrop surface took place upon lowering the ionic strength of the imbibing brine. However, one cannot dismiss that interaction between the dolomite surface and seawater prior to lowering its ionic strength could also have been a part of the wettability modification process as sample history is important.

Discussion and Conclusions This paper presents the results of a larger-scale screening study into the possibility of modifying the wettability of carbonate rock samples by the altering ionic composition and the ionic strength of the brine. Wettability modification was qualitatively assessed by performing spontaneous imbibition tests. The results of all spontaneous imbibition tests are summarized graphically in Fig. 13. Incremental oil recovery was calculated as the difference between oil production during wettability-modifying brine imbibition and formation water imbibition. It is plotted on the y-axis as a percentage of OIIP versus ionic strength (Fig. 13a) and sulfate molar concentration (Fig. 13b). Here only additional oil recovery measured after imbibition of formation water is plotted to exclude effects of the sample history and to identify advantages of wettability-modifying brines in comparison with formation water. The spontaneous imbibition tests show a significant scatter in the measured incremental oil production. This is due not only to variation in the experimental conditions but also to natural variability in the carbonate samples used in the experiments, i.e. mineralogy, pore texture, permeability, etc., even if taken from the same geological formation. Despite the scatter, it is clear that the majority of the higher incremental recoveries are observed for the brines with lower ionic strength (Fig. 13a). A clear exception is the experiment on the Stevns Klint samples, when higher oil recovery is observed for the sample with higher sulfate concentration rather than lower ionic strength (Fig. 13b).

As described in the introduction section there are two approaches that can be considered for the wettability modification of carbonate rocks to improve oil recovery under certain conditions:

1. Increasing concentration of surface interacting ions, i.e. SO42-, BO3

3- or PO43- in the injection brine

2. Lowering ionic strength of the injection brine The results of this study demonstrate that oil recovery from a number of carbonate rock samples could be increased by lowering the ionic strength of the brine, possibly due to the wettability shift towards a more water-wet state. An enhanced oil recovery method that is based on this approach has some practical benefits as opposed to injection of brines containing elevated concentration of surface-interacting ions, i.e. SO4

2-, BO33- or PO4

3-. For instance, injecting high sulfate seawater into reservoirs which have formation water containing barium and strontium increases the potential of scale formation in the production tubing and/or plugging of reservoir rock around the production well. Also there are examples of sweet oil fields that became sour upon water flood breakthrough following the injection of high sulfate seawater (Khatib and Salanitro 1997). Both issues could be overcome or reduced in severity when low salinity waterflooding is implemented in the field as discussed by Collins (2011) for sandstone oil reservoirs.

In this study the improved recovery was shown during the spontaneous imbibition experiments. Countercurrent imbibition is an oil recovery mechanism in fractured reservoirs. To estimate the potential benefits of this EOR method on field-scale waterflood in non-fractured reservoirs, information on water and oil relative permeability curves before and after wettability modification is required. Therefore, core flow experiments (including monitoring of profiles of differential pressure and insitu saturation) should be performed.

Currently conditions under which the wettability alteration takes place are unidentified. Greater advances in low salinity waterflooding in carbonates will result from development of a broad understanding of the factors that determine crude oil/brine/rock interactions using the right surface chemistry tools.

SPE 153869 7

Acknowledgments The authors would like to thank S. Berg, M. Golombok, C. van Kruijsdijk, and S. Masalmeh for their valuable comments while reviewing the manuscript. They are grateful to Royal Dutch Shell for permission to publish this work. C.M.S. Volery is acknowledged for the thin section analysis of the selected samples.

Nomenclature FW Formation Water I Ionic Strength (M) OIIP Oil Initially In Place PDI Potential Determining Ions SEM Scanning Electron Microscope SI Spontaneous Imbibition Swi Initial Water Saturation TAN Total Acid Number TBN Total Base Number TDS Totally Dissolved Solids WM Wettability Modifying brine XRD X-Ray Diffraction References Almehaideb, R.A., Ghannam, M.T., Zekri, A.Y. 2004. Experimental Investigation of Contact Angles of Crude Oil-Microbial Solution on

Carbonate Rocks. Pet. Sci. & Technol. 22 (3-4): 423-438. Alotaibi, M.B., Nasralla, R.A., Nasr-el-Din, H.A. 2010. Wettability Challenges in Carbonate Reservoirs. Paper SPE 129972 presented at

the SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, USA, 24-28 April. Anderson, W.G. 1986. Wettability Literature Survey - Part2: Wettability Measurement. J. Pet Tech 38(11): 1125-1144. Austad, T., Strand, S., Hognesen, E. J., Zhang, P. 2005. Seawater as IOR Fluid in Fractured Chalk. Paper SPE 93000 presented at the

International Symposium on Oilfield Chemistry, 2-4 February, The Woodlands, Texas. Collins, I.R. 2011. Holistic Benefits of Low Salinity Waterflooding. Paper presented at the 16th European Symposium on Improved Oil

Recovery in Cambridge, 12-14 April. Ferno, M.A., Gronsdal, R., Aheim, J., Nyheim, A., Berge, M., Graue, A. 2011. Use of Sulfate for Water Based Enhanced Oil recovery

during Spontaneous Imbibition in Chalk. Energ. Fuel. 25 (4): 1697-1706. Fjelde, I.F., Aasen, S.M.A. 2009. Improved Spontaneous Imbibition of Water in Reservoir Chalks. Paper presented at the 15th European

Symposium on Improved Oil Recovery in Paris (France), 27-29 April. Gupta, R. and Mohanty, K. 2011. Wettability Alteration Mechanism for Oil Recovery from Fractured Carbonate Rocks. Transport Porous

Med. 87 (2): 635-652. Gupta, R., Griffin, S., Willingham, T.W., Cascio, M.L., Shyeh, J.J., Harris, C.R. 2011. Enhanced Waterflood for Middle East Carbonate

Cores – Impact of Injection Water Composition. Paper SPE 142668 presented at SPE Middle East Oil and Gas Show and Conference, 25-28 September, Manama, Bahrain.

Hallenbeck, L.D., Sylte, J.E., Ebbs, D.J., Thamas, L.K. 1991. Implementation of the Ekofisk Field Waterflood, SPE Form Eval 6: 284-290. Jafar Fathi, S., Austad, T., Strand, S. 2011. Water-Based Enhanced Oil Recovery (EOR) by “Smart Water”: Optimal Ionic Composition for

EOR in Carbonates. Ener. Fuel. 25: 5173-5179. Jingwa Hsu, J. 1963. Solubility of Dolomite and Composition of Florida Ground Water. J. Hydrology 1: 288-310. Khatib, Z.I. and Salanitro, J.P. 1997. Reservoir Souring: Analysis of Surveys and Experience in Sour Waterfloods. Paper SPE 38795

presented at SPE Annual Technical Conference and Exhibition, 5-8 October, San Antonio, Texas. doi: 10.2118/38795-MS. Ligthelm, D.J., Gronsveld, J., Hofman, J.P., Brussee, N.J., Marcelis, F., van der Linde, H.A. 2009. Novel Waterflooding Strategy by

Manipulation of Injection Brine Composition, Paper SPE 119835 presented at the EUROPEC/EAGE Annual Conference and Exhibition, Amsterdam, 8–11 June. doi: 10.2118/119835-MS.

McGuire, P.L., Chatham, J.R., Paskva, F.K., Sommer, D.M., Carini, F.H. 2005. Low Salinity Oil Recovery: an Exciting New EOR Opportunity for Alaska’s North Slope, Paper SPE 93903 presented at the SPE Western Regional Meeting, Irvine, CA, U.S.A., 30 March – 2 April. doi: 10.2118/93903-MS.

Morrow N. and Buckley, J. 2011. Improved Oil Recovery by Low-Salinity Waterflooding. J. Pet Tech 63(5): 106-112. doi: 10.2118/129421-MS.

Rezai Gomari, K.A., Hamouda, A.A., Denoyel, R. 2006. Influence of Sulfate Ions on the Interaction between Fatty Acids and Calcite Surface. Colloid Surface A 287: 29-35.

Sheng, J. 2010. Modern Chemical Enhanced Oil Recovery: Theory and Practice. Gulf Professional Publishing. Strand, S., Hognesen, E.J., Austad, T. 2006. Wettability Alteration of Carbonates - Effects of Potential Determining Ions (Ca2+ and SO42-)

and Temperature. Colloid Surface A 275(1-3): 1-10. Strand, S., Austad, T., Puntervold, T., Hognesen, E.J., Olsen, M., Barstad, S.M.F. 2008. “Smart Water” for Oil Recovery from Fractured

Limestone: A Preliminary Study. Energ. Fuel. 22(5): 3126-3133. Sylte, J.E., Hallenbeck, L.D., Thamas, L.K. 1988. Ekofisk Formation Pilot Waterflood. Paper SPE 18276 presented at SPE Annual

Technical Conference and Exhibition, Houston, Texas, 2-5 October. Vledder, P., Fonseca, J.C., Gonzalez, I., Ligthelm, D. 2010. Low Salinity Water Flooding: Proof of Wettability Alteration on a Field Wide

Scale. Paper SPE 129564 presented at the SPE Improved Oil Recovery Symposium held in Tulsa, Oklahoma, USA, 24-28 April.

8 SPE 153869

Webb, K.J., Black, C.J.J., al-Ajeel, H. 2004. Low Salinity Oil Recovery – Log-Inject-log, Paper SPE 89379 presented at the SPE/DOE Symposium on Improved Oil Recovery, 17-21 April, Tulsa. doi: 10.2118/89379-MS.

Webb, K.J., Black, C.J.J., Tjetland, G. 2005a. A Laboratory Study Investigating Methods for Improving Oil Recovery in Carbonates. Paper IPTC 10506 presented at the International Petroleum Technology Conference in Doha, Qatar, 21-23 November.

Webb, K.J., Black, C.J.J., Edmonds, I J. 2005b. Low Salinity Waterflooding- The Role of Reservoir Condition Corefloods. Paper presented at the 2005 EAGE conference in Budapest, Hungary.

Yousef, A.A., Al-Saleh, S., A-Kaabu, A., Al-Jawfi, M. 2011. Laboratory Investigation of the Impact of Injection-Water Salinity and Ionic Content on Oil Recovery From Carbonate Reservoirs. SPE Form Eval 14 (15): 578-593. CSUG/SPE 137634.

Zhang, P., Austad, T. 2006. Wettability and Oil Recovery from Carbonates: Effects of Temperature and Potential Determining Ions. Colloid Surface A 279(1-3): 179-187.

Zhang, P., Tweheyo, M.T., Austad, T. 2006. Wettability Alteration and Improved Oil Recovery in Chalk: The Effect of Calcium in the Presence of Sulfate. Energ. Fuel. 20(5): 2056-2062.

Zhang, P., Tweheyo, M.T., Austad, T. 2007. Wettability Alteration and Improved Oil Recovery by Spontaneous Imbibition of Seawater into Chalk: Impact of the Potential Determining Ions Ca2+, Mg2+, and SO4

2−. Colloid Surface A 301(1): 199-208. Table 1. Physical properties and chemical composition of the used oils.

PropertiesCrude oil

0.843@70°C 3.93@70°C 0.920 0.160 <0.05

0.813/0.779@70°C/120°C 2.36/0.97@70°C/120°C 0.420 0.100 0.15

0.831@85°C 4.84@85°C 0.070 1.770 0.11

Asphaltenes [% m]

A

B

C

Density [g/cm3] Viscosity [mPa⋅s] TAN [mgKOH/g]

TBN [mgKOH/g]

Table 2. Composition of the synthetic brines used in the spontaneous imbibition experiments.

Unit: [mol/L]Ion

Brine

1.439 0.006 0.193 0.048 0.000 0.002 0.002 1.919 2.17 110.58

2.823 0.013 0.414 0.092 0.015 0.002 0.001 3.848 4.39 222.19

2.172 0.000 0.362 0.134 0.000 0.002 0.003 3.154 3.67 179.89

3.507 0.000 0.117 0.133 0.000 0.011 0.000 3.983 4.27 230.77

0.122 0.017 0.017 0.007 0.000 0.019 0.003 0.128 0.22 10.84

0.170 0.017 0.012 0.007 0.000 0.043 0.003 0.116 0.28 13.59

0.282 0.017 0.009 0.007 0.000 0.099 0.003 0.112 0.44 21.30

2.609 0.000 0.290 0.089 0.000 0.007 0.000 3.351 3.75 193.23

0.118 0.002 0.017 0.009 0.000 0.000 0.000 0.174 0.20 9.85

0.118 0.002 0.017 0.009 0.000 0.019 0.000 0.136 0.22 10.33

0.135 0.002 0.000 0.000 0.000 0.000 0.003 0.133 0.14 8.07

0.051 0.002 0.013 0.045 0.000 0.024 0.003 0.118 0.25 9.51

0.180 0.000 0.000 0.000 0.000 0.000 0.000 0.180 0.18 10.52

0.450 0.010 0.013 0.045 0.000 0.024 0.002 0.525 0.66 33.39

0.045 0.001 0.001 0.004 0.000 0.002 0.000 0.053 0.07 3.34

0.057 0.010 0.013 0.045 0.000 0.024 0.002 0.133 0.27 10.48

0.289 0.001 0.043 0.011 0.001 0.002 0.003 0.391 0.46 23.07

0.008 0.000 0.002 0.002 0.000 0.002 0.003 0.007 0.02 0.94

0.075 0.000 0.001 0.001 0.000 0.001 0.016 0.061 0.08 4.93

0.015 0.000 0.000 0.000 0.000 0.000 0.003 0.012 0.016 0.99

WM5

Ionic strength [mol/L]

TDS [g/L]

FW1

PW

AW_0CaMgSO4

HCO3-Na+ K+ Ca2+ Mg2+ SO4

2-

AW_0SO4

AW_SO4

1/5WM5

WM1

WM2

WM3

Cl-

FW2

FW3

FW4

Sr2+

1/10SSW

WM4

AW_CaMgSO4

NaCl

SSW

SSW_0NaCl

1:9 FW2/WM4

SPE 153869 9

Table 3. Geological description, basic petrophysical properties and saturation history of the rock samples.

PropertiesSample

0.50 5.5 2.700 0.15

0.51 6.0 2.700 0.15

0.49 6.2 2.700 0.15

0.29 3.9 2.700 0.15

0.31 3.8 2.700 0.15

0.29 3.4 2.700 0.14

0.29 3.5 2.700 0.15

0.29 4.9 2.720 0.11

0.28 2.5 2.710 0.10

0.29 4.1 2.720 0.12

0.27 1.9 2.700 0.11

0.26 24.0 2.700 0.11

0.23 30.0 2.700 0.14

0.24 47.3 2.701 0.18

0.24 52.8 2.701 0.16

0.23 43.4 2.701 0.16

0.23 50.2 2.703 0.15

0.24 56.5 2.703 0.15

0.23 27.0 2.702 0.2

0.12 15.5 2.759 0.12

0.12 15.8 2.759 0.15

0.18 12.2 2.839 0.17

0.25 10.8 2.843 0.11

0.19 201 2.842 0.15

0.20 235 2.842 0.12

Lim3.1A

MicroporosityWackestone/ packstone

Sucrosic dolomite

A/FW2

A/FW2

C/FW3Dol1.3

Dol1.4

Dol2.1

Dol2.2

Dol1.1

Dol1.2

Lim2.6

Lim1.3

Swi Oil/FW

Chalk1

Dunham class Pore type Porosity [fr] Permeability [mD]

Grain density

/ 3

Fine-interparticleChalk2 A/FW1Mudstone ("Chalk")

Chalk3

A/FW2Lim1.2

Lim1.1

Lim1.4

Lim2.3

Lim2.4

Lim2.1

Lim2.2

Intercrystalline

Dolosparite Intercrystalline

B/FW3

Lim3.3B

Lim3.1B

Lim3.2B

Skeletal w ackestone

Irregular-shaped vugs

Highly heterogen. macropore

system

Algae pack/grainstone-

boundstone

Peloidal packstone

Mixed to microporous pore

netw ork

Lim3.2A

Lim3.3A

Lim2.5

10 SPE 153869

100 μm 200 μm

Fig. 1. Thin sections of the Limestone 2 rock samples under transmitted light. Pyrite (red arrow) and dolomite crystals are visible in the larger pores.

200 μm

200 μm

Cem

Cem

Fig. 2. Thin sections of the Limestone 3 rock samples under transmitted light: (a) sample Lim3.1 and (b) sample Lim3.3.

500 μm

Anhydrite

500 μm

Anhydrite

a b

a b

a bPPL XPL

SPE 153869 11

500 μm

Anhydrite

500 μm

Anhydrite

Fig. 3. Thin sections of the Dolostone 1 rock samples under transmitted light: (a), (b) sample Dol1.1 and (c), (d) sample Dol1.4. PPL = Plane Polarized Light; XPL = Cross Polarized Light.

Cum

ulat

ive

oil

Time

Change brineIncremental oil recovery

po

pw

pc= po - pw

pc

sw

100

90

80

70

60

50

40

30

20

10

0

Fig. 4. (a) A schematic depiction of the core plug saturated with oil and connate water in the Amott glass container. The produced oil is seen on the surface of the plug and is collected in the measuring cylinder. (b) A schematic representation of the Amott spontaneous imbibition test.

c dPPL XPL

(a) (b)

12 SPE 153869

0

10

20

30

40

50

60

0 100 200 300 400

Rec

over

y [%

OIIP

]

Imbibition time [days]

Stevns Klint outcrop chalk

WM3; [SO42-] = 99 mM;

I = 0.44 mol/L

WM2; [SO42-] = 43 mM;

I = 0.28 mol/L

WM1; [SO42-] = 19 mM;

I = 0.22 mol/L

FW1; [SO42-] = 2 mM;

I = 2.17 mol/L

Chalk1

Chalk2

Chalk3

Fig. 5. Spontaneous imbibition into the oil-saturated Stevns Klint chalk cores at 60 °C using brines with various sulfate concentrations. Dashed line represents brine changeover.

0

5

10

15

20

25

30

35

0 20 40 60 80

Rec

over

y [%

OIIP

]

Imbibition time [days]

Limestone 1

Lim1.1

FW2; [SO42-] = 2 mM; I = 4.39 mol/L

PW; [SO42-] = 7 mM; I = 3.75 mol/L

AW_CaMgSO4; [SO42-] = 24 mM; I = 0.25 mol/L

0

5

10

15

20

25

30

35

0 20 40 60 80

Rec

over

y [%

OIIP

]

Imbibition time [days]

Limestone 1 FW2; [SO42-] = 2 mM; I = 4.39 mol/L

AW_0CaMgSO4; [SO42-] = 0 mM; I = 0.14 mol/L

AW_CaMgSO4; [SO42-] = 24 mM; I = 0.25 mol/L

Lim1.2

0

5

10

15

20

25

30

35

0 20 40 60 80

Rec

over

y [%

OIIP

]

Imbibition time [days]

Limestone 1FW2; [SO4

2-] = 2 mM; I = 4.39 mol/L

AW_0SO4; [SO42-] = 0 mM; I = 0.2 mol/L

AW_SO4; [SO42-] = 19 mM; I = 0.22 mol/L

Lim1.3

0

5

10

15

20

25

30

35

0 20 40 60 80

Rec

over

y [%

OIIP

]

Imbibition time [days]

Limestone 1 FW2; [SO42-] = 2 mM; I = 4.39 mol/L

NaCl; [SO42-] = 0 mM; I = 0.18 mol/L

Lim1.4

Fig. 6. Spontaneous imbibition experiment on Limestone 1 rock material at 70 °C using various brines. Dashed lines represent brine changeover.

a b

c d

SPE 153869 13

0

5

10

15

20

25

30

35

0 20 40 60 80

Rec

over

y [%

OIIP

]

Imbibition time [days]

Limestone 2; 70 °C

Lim2.2

Lim2.1

SSW; [SO42-] = 24 mM; I = 0.66 mol/L

SSW_0NaCl; [SO42-] = 24 mM; I = 0.27 mol/L

FW3; [SO42-] = 2mM; I = 3.67 mol/L

0

5

10

15

20

25

30

35

0 5 10 15 20 25 30 35 40

Rec

over

y [%

OIIP

]

Imbibition time [days]

Limestone 2; 120 °C

Lim2.3

Lim2.4

Lim2.5

Lim2.6

SSW; [SO42-] = 24 mM; I =0.66 mol/L

SSW_0NaCl; [SO42-] = 24 mM; I = 0.27 mol/L

FW3; [SO42-] = 2mM; I = 3.67 mol/L

Fig. 7. Spontaneous imbibition experiment on Limestone 2 rock material at 70 °C (a) and 120 °C (b) using various brines. Dashed lines represent brine changeover.

0

5

10

15

20

25

30

35

0 20 40 60 80 100 120 140

Rec

over

y [%

OIIP

]

Imbibition time [days]

Limestone 3 WM4; [SO42-] = 2 mM; I = 0.02 mol/L

SSW; [SO42-] = 24 mM; I = 0.66 mol/L

FW2; [SO42-] = 2 mM; I = 4.39 mol/L

Lim3.1a

Lim3.1b

0

5

10

15

20

25

30

35

0 20 40 60 80 100 120 140

Rec

over

y [%

OIIP

]

Imbibition time [days]

Limestone 3

Lim3.2a

Lim3.2b

WM4; [SO42-] = 2 mM; I = 0.02 mol/L

1:9 FW2/WM4; [SO42-] = 2 mM; I = 0.46 mol/L

FW2; [SO42-] = 2 mM; I = 4.39 mol/L

0

5

10

15

20

25

30

35

0 20 40 60 80 100 120 140

Rec

over

y [%

OIIP

]

Imbibition time [days]

Limestone 3

WM4; [SO42-] = 2 mM; I = 0.02 mol/L

FW2; [SO42-] = 2 mM; I = 4.39 mol/L

Lim3.3b

Lim3.3a

Fig. 8. Spontaneous imbibition experiment on Limestone 3 rock material at 70 °C using various brines. Dashed lines represent brine changeover.

a b

a b

c

14 SPE 153869

0

5

10

15

20

25

30

35

40

45

50

55

60

0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 160

Rec

over

y [%

OIIP

]

Imbibition time [days]

Dolostone 1 WM5; [SO42-] = 1 mM; I = 0.08 mol/L

1/5WM5; [SO42-] = 0.2 mM; I = 0.02 mol/L

FW4; [SO42-] = 11 mM; I = 4.27 mol/L

Dol1.1

Dol1.3

Dol1.4

Dol1.2

Fig. 9. Spontaneous imbibition experiment on Dolostone 1 rock material at 85 °C using various brines. Dashed lines represent brine changeover.

0

2

4

6

8

10

12

14

16

18

20

1

100

10000

FW4 Dol1.1 Dol1.2 Dol1.3 Dol1.4

Incr

emen

tal o

il rec

over

y [%

OIIP

]

Mol

ar c

once

ntra

tion

[mM

]

Sample IDSodium Potassium Calcium Magnesium Chloride Sulfate Oil recovery

0

2

4

6

8

10

12

14

16

18

20

1

10

100

1000

WM5 Dol1.1 Dol1.2 Dol1.3 Dol1.4

Incr

emen

tal o

il re

cove

ry [%

OIIP

]

Mol

ar c

once

ntra

tion

[mM

]

Sample IDSodium Potassium Calcium Magnesium Chloride Sulfate Oil recovery

0

2

4

6

8

10

12

14

16

18

20

1

10

100

1000

WM5 refr. Dol1.1 Dol1.2 Dol1.3 Dol1.4

Incr

emen

tal o

il re

cove

ry [%

OIIP

]

Mol

ar c

once

ntra

tion

[mM

]

Sample IDSodium Potassium Calcium Magnesium Chloride Sulfate Oil recovery

0

2

4

6

8

10

12

14

16

18

20

1

10

100

1000

1/5WM5 Dol1.1 Dol1.2 Dol1.3 Dol1.4

Incr

emen

tal o

il rec

over

y [%

OIIP

]

Mol

ar c

once

ntra

tion

[mM

]

Sample IDSodium Potassium Calcium Magnesium Chloride Sulfate Oil recovery

Fig. 10. Surrounding brine analysis during spontaneous imbibition tests using Dolostone 1 samples showing increase in Ca2+ and SO4

2- concentration.

a b

c d

SPE 153869 15

0

2

4

6

8

10

12

14

16

18

20

0

2

4

6

8

10

12

14

16

18

20

Incr

emen

tal o

il re

cove

ry [%

OIIP

]

Mol

ar c

once

ntra

tion

[mM

]

Ca2+SO42-Ca2+ invaiding brineSO42- invading brineOil recovery

Ca2+

SO42-

Ca2+ initialSO4

2- initialOil recovery

Fig. 11. Comparison of Ca2+ and SO4

2- concentration in the initial brine and after the interaction with two samples, Dol1.1 and Dol1.3. Incremental oil recoveries are also shown.

0

5

10

15

20

25

30

35

0 10 20 30 40 50 60

Rec

over

y [%

OIIP

]

Imbibition time [days]

Silurian dolomite outcropSSW; [SO4

2-] = 24 mM; I = 0.66 mol/L

1/10SSW; [SO42-] = 2.4 mM; I = 0.07 mol/L

FW2; [SO42-] = 2 mM; I = 4.39 mol/L

Fig. 12. Spontaneous imbibition experiments using Silurian dolomite outcrop rock at 70 °C.

16 SPE 153869

0

2

4

6

8

10

12

14

16

18

20

0 0.5 1 1.5 2 2.5 3 3.5 4

Incr

emen

tal r

ecov

ery

[% O

IIP]

Ionic strength [mol/L]

Stevns Klint outcrop chalkLimestone 1Limestone 2Limestone 3Dolostone 1Silurian dolomite outcrop

0

2

4

6

8

10

12

14

16

18

20

0 20 40 60 80 100

Incr

emen

tal r

ecov

ery

[% O

IIP]

Sulfate molar concentration [mM]

Stevns Klint outcrop chalkLimestone 1Limestone 2Limestone 3Dolostone 1Silurian dolomite outcrop

Fig. 13. Ionic strength (a) and concentration of sulfate ions (b) in the wettability modifying brines plotted versus incremental oil recovery measured during the Amott spontaneous imbibition experiments.

a b