ARTICLE pubs.acs.org/EF
Use of Sulfate for Water Based Enhanced Oil Recovery during Spontaneous Imbibition in Chalk M. A. Fernø,* R. Grønsdal, J. Åsheim, A. Nyheim, M. Berge, and A. Graue Department of Physics and Technology, University of Bergen, Norway ABSTRACT: The effect of increased sulfate concentration in the imbibing water during oil recovery by spontaneous imbibitions in different outcrop chalks at various wettability conditions at 130 C has been determined. Core plugs from three chalk outcrops, Rørdal, Niobrara, and Stevns, were aged in crude oil and included in this study. Stevns chalk exhibited increased oil recovery during spontaneous imbibition with increased concentration of sulfate in the imbibing water phase. The effect was less than reported by others and was wettability dependent. Spontaneous imbibition tests showed that the added oil recovery was greatest at Amott water indices below 0.2, and tests at and above 0.25 showed only minor effects from sulfate. Niobrara and Rørdal chalk did not show increased oil recovery with increased sulfate concentration in the brine. These core plugs reflected more water-wet imbibition characteristics at elevated temperature, and the effect of sulfate could not be isolated. Measurements of Amott water indices before and after spontaneous imbibition at 130 C exhibited increased water-wetness for Niobrara chalk at this elevated temperature. The wetting preference for Stevns and Rørdal chalk did not change after spontaneous imbibition at elevated temperature and maintained less water-wet spontaneous imbibition characteristics at ambient temperature, regardless if sulfate was present or not. The Rørdal core plugs exhibited increased oil recovery by imbibition at elevated temperature, but the measured Amott wettability preference was stable. The results demonstrate that the effect from sulfate on spontaneous imbibition in chalk is dependent on the chalk type (i.e., rock mineral composition) and the wettability of the rock.
’ INTRODUCTION Oil production from naturally fractured carbonate reservoirs by spontaneous imbibition during waterflooding is an important recovery mechanism. Highly permeable fractures act as conduits for flow, and the injected water will mainly be transported along the fractures. Hence, with the majority of flow taking place in the fractures, the viscous forces and the pressure drops across matrix blocks are limited, and the oil production is governed by other recovery mechanisms. The oil recovered by spontaneous, or capillary, imbibition is determined by the capillary pressure, which is strongly coupled with the matrix wettability. If the matrix is strongly water-wet, there will be a positive capillary pressure that drive imbibition and may produce oil by countercurrent or cocurrent water imbibition from the fractures. The imbibition rate and total production are dramatically reduced when the wettability of the matrix becomes less water-wet1 and stops altogether when the matrix is oil-wet. Unfortunately, most reservoirs are believed to have wettabilities other than strongly water-wet, and most carbonate reservoirs exhibit oil-wet wettabilities. Because capillary imbibition is an important recovery mechanism in naturally fractured reservoirs, several approaches to alter the reservoir wettability toward more water-wet have been proposed, including surfactants.25 Others have focused on the ions present in the injected water phase such as reduced water salinity6,7 and the use of seawater.8 An induced wettability change in an ion-exchange with the potential determining ions including calcium, magnesium, and sulfate ions have been shown to increase production by spontaneous imbibition in chalk.912 Negatively charged sulfate ions may interact with the positively charged chalk surface to mobilize carboxylic groups that reduce the surface wettability. r 2011 American Chemical Society
The mechanisms and chemical interactions were studied using clean, outcrop chalk samples or crystalline calcite substrates. To verify observations made in model systems, Webb et al. 200513 used a reservoir core from a North Sea carbonate reservoir under full reservoir conditions using live crude oil and brine. They observed that the presence of sulfate in the imbibing brine enhanced oil recovery by measuring an increase in the positive part of the capillary pressure curve. Sulfate concentrations in core plugs from two fractured chalk reservoirs14 were higher than earlier reported sulfate concentrations required to alter wettability in clean chalk outcrops.15 Recently, a chemical model to predict the surface potential of calcite and the adsorption of sulfate ions from the pore water was reported.16 They also provided a detailed review of reported experimental work on the effect of determining ions on spontaneous imbibition in Stevns Klint outcrop chalk. This work focuses on the use of sulfate for enhanced oil recovery during spontaneous imbibition at elevated temperatures in different types of chalk at various wettability conditions. The motivation was to test the conclusions previously observed in Stevns outcrop chalk and to investigate if similar effects could be observed in other outcrop chalks. Additionally, the scope was also to extend the range of wettabilities investigated to determine if the added benefit from sulfate is influenced by the initial wetting preference of the core. Three outcrop chalks were investigated: Niobrara chalk, Rørdal or Portland chalk, and Stevns chalk. Received: January 24, 2011 Revised: March 18, 2011 Published: March 25, 2011 1697
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Table 1. Brine Compositionsa CaCl2 3 2H2O
NaCl
a
MgCl2 3 6H2O
NaHCO3
chalk brine
50.0
50.0
reservoir brine
40.0
34.0
synthetic seawater
23.38
1.91
9.05
0.17
synthetic seawater, 0xS
26.79
1.91
9.05
0.17
synthetic seawater, 4xS
13.15
1.91
9.05
0.17
Na2SO4
KCl
NaN3 0.01
5.0
0.01 3.41
0.75 0.75
13.4
0.75
All numbers in g/L distilled water.
Table 2. Oil Properties density at 20 C (g/cm3)
density at 80 C (g/cm3)
viscosity at 20 C (cP)
viscosity at 80 C (cP)
decane decahydronaphthalene
0.73 0.89
0.68
0.92 0.85
0.40
crude oil
0.85
0.85
14.3
2.7
Table 3. Crude Oil Analysis AN
BN
RI
API
saturates [%]
aromates [%]
resins [%]
asphaltenes [%]
0.41 ( 0.02
1.4 ( 0.1
1.4834
27 ( 3
61 ( 3
20 ( 1
19 ( 1
0.59 ( 0.03
’ EXPERIMENTAL PROCEDURES Core Preparation. Chalk core plugs were cut from larger slabs of rocks obtained at three outcrop locations. To avoid microfractures during drilling, the cores were turned on the lathe to obtain cylindrical core plugs. The core plugs were dried at 90 C for at least 3 days. Dry weight and dimensions were measured before core plugs were vacuum evacuated and saturated with brine. Porosity was determined by material balance calculations. Absolute permeability to brine was determined by measuring the pressure drop across the rock sample at different flow rates in a biaxial core holder with a slight confinement pressure. Each rock type is briefly described below. Rørdal Chalk. The rock was obtained from the Portland cement factory at Rørdal, Denmark. The rock formation was of Maastrichtian age and consisted mainly of coccolith deposits, and the composition was calcite (99%) with some quartz (1%). Porosity and permeability range from 45 to 47% and 38 mD, respectively. Further geological characterization may be found elsewhere.1720 Stevns Chalk. The Stevns chalk was obtained from Stevns Klint south of Copenhagen, Denmark. The chalk is of Maastrichtian age soft and generally homogeneous with >96% fine graded coccolithic matrix. The rock is soft with a BET surface area of 2 m2/g. Porosity and permeability ranges from 45 to 50% and 25 mD, respectively. Further geological characterization may be found in refs 2022 Niobrara Chalk. The Niobrara chalk was obtained from an outcrop in Kansas. The chalk is fine grained micrite representing a mixture of calcareous, organic, and terrigenous components (7080% carbonate). The carbonate constitute macrofossils and nanofossils (6090%) including coccoliths (golden-brown algae) and lesser Foraminifera and calcispheres. Local diagenetic reactions lead to authigenic minerals such as pyrite and kaolinite. Porosity and permeability ranges from 40 to 50% and 0.13 mD, respectively. Further geological characterization may be found elsewhere.23,24 Fluids. Brines denoted “Chalk brine” (F = 1.05 g/cm3, μ = 1.09 cP) and “Reservoir brine” (F = 1.05 g/cm3, μ = 1.09 cP) were the initial water phases used to saturate core plugs samples. Brine compositions are listed in Table 1. Brine composition reflects a reservoir of interest. Synthetic seawater was used as the imbibing fluid during spontaneous imbibition tests. Two sulfate concentrations were used: synthetic seawater without
sulfate, denoted SSW-0S, (F = 1.024 g/cm3, μ = 1.09 cP) and 4 times the sulfate concentration compared to regular synthetic seawater, denoted SSW-4S, (F = 1.024 g/cm3, μ = 1.09 cP). Wettability Alteration. The wettability of outcrop rocks is generally strongly water-wet and was altered to less water-wet conditions by dynamic aging in a North Sea crude oil at an elevated temperature to reflect typical chalk reservoir wetting conditions. The core plugs were oilflooded with crude oil at constant differential pressure (2 Bar/cm) at 80 C. At irreducible water saturation, the flow of crude oil was reduced to a constant injection rate of 1.5 cm3/h, continuously injecting crude oil through the core during the entire aging time. The direction of flow was reversed midway. After aging, the crude oil was displaced from the core at elevated temperature by injecting 5 PV of decahydronaphthalene followed by 5 PV of decane to avoid asphaltene precipitation, to stop the aging, and to establish more reproducible experimental conditions by using decane as the oleic phase throughout the experiments.2527 The oil properties are listed in Table 2. A summary of crude oil chemical analysis including SARA components, API, refractive index, and acid and base numbers is tabulated in Table 3. This analysis represents crude oil without evaporation and oxidation at 90 C. Spontaneous Imbibition Tests. The initial wettability preference of core plugs aging in crude oil were measured using the Amott method28 with spontaneous imbibition of water at room temperature. The effect of sulfate in the imbibing water on oil recovery by spontaneous imbibition was studied at elevated temperatures, 130 C. The water in the imbibition cell was pressurized to between 52 and 58 psi (3.64.0 bar) to avoid boiling using custom-made high-pressure glass imbibition cells. The produced oil by capillary imbibition was measured regularly during the test by visual inspection at the top of the imbibition cell.
’ EXPERIMENTAL RESULTS Baseline at Strongly Water-Wet Conditions. The effect of sulfate as a wettability reversal agent is influenced by the ions present at the rock mineral surface. If sulfate is initially present in the core, the added effect of sulfate as a water additive may be significantly reduced by 1698
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Table 4. Rock Properties and End Point Water Saturations during 130 C Spontaneous Imbibition at Strongly Water-Wet Conditions core rock type L (cm) D (cm) j (%) K (mD) Imb. fluid Swi Swspont Rf SR9 SR11 SR17 NR26 NR27 NR29 PCR7 PCR8
Stevns Stevns Stevns Niobrara Niobrara Niobrara Rørdal Rørdal
6.01 5.99 6.06 6.01 6.02 6.02 5.78 6.01
3.81 3.81 3.82 3.81 3.82 3.82 3.80 3.82
46.3 46.4 46.0 36.3 37.1 36.4 46.6 46.1
4.3 3.7 5.0 2.5 2.8 2.7 8.0 5.2
SSW-0S SSW-0S SSW-4S SSW-4S SSW-4S SSW-0S SSW-0S SSW-0S
0.32 0.39 0.33 0.34 0.32 0.32 0.30 0.28
0.63 0.69 0.67 0.72 0.73 0.73 0.73 0.66
0.45 0.49 0.50 0.58 0.61 0.61 0.61 0.53
Figure 1. Spontaneous imbibition characteristics for strongly water-wet Rørdal (PCR7 and PCR8), Stevns (SR11 and SR17), and Niobrara (NR27 and NR29) core plugs at 130 C. Sulfate in the imbibing brine shows no effect on the oil recovery in Stevns and Niobrara. The difference between two Rørdal cores without sulfate relates to core properties. precipitation of anhydrite.15 Anhydrate precipitates when the sulfate and calcium concentrations exceed the solubility product, which is temperature dependent. Two core samples from each chalk type (Stevns, Rørdal, and Niobrara) were saturated with distilled water to check for the presence of sulfate in the cores prior to spontaneous imbibition tests. Each core was waterflooded with two pore volume distilled water, and barium chloride (BaCl2) was added to the effluent. If sulfate is present, barium sulfate will precipitate. Because no precipitation was observed in the three chalk outcrops, it was assumed that the concentration of sulfate was zero or lower than precipitation levels prior to the spontaneous imbibition tests. Spontaneous imbibition tests at 130 C at strongly water-wet wettability conditions were performed for all three rock types with sulfate (SSW-4S) and without sulfate (SSW-0S) in the imbibing water. A total of 10 core plugs were prepared and saturated with Reservoir brine. Each core plug was oilflooded with decane to irreducible water saturation using a constant differential pressure. A total of 5 PV of oil was injected. Rock properties and end point water saturations are listed in Table 4. Figure 1 shows the spontaneous imbibition curves for six strongly water-wet core plugs. Rørdal Chalk. Two Rørdal core plugs at irreducible water saturation imbibed brine without sulfate (SSW-0S). Production of oil during spontaneous imbibition at 130 C was initially fast, with most of the mobile oil produced within 1 h. The difference in total oil production for the two plugs, 61% OIP for PCR7 and 53% OIP for PCR8, may be related to the difference in absolute permeability for the two core plugs. Stevns Chalk. Three strongly water-wet Stevns core plugs showed similar end points for spontaneous imbibition and oil recovery. No additional oil recovery or increase in end point water saturation and change in the rate of spontaneous imbibition was observed as a result of sulfate in the imbibing brine. Niobrara Chalk. Three strongly water-wet Niobrara chalk core plugs showed similar end points for spontaneous imbibition and oil recovery and were not sensitive to the presence of sulfate in the imbibing water phase. Oil recovery for the core plugs NR26, NR27, and NR29 were for all 60 ( 2% OIP. No difference in oil production was observed for cores imbibing in SSW-4S compared with SSW-0S.
Spontaneous Imbibition at 130 C Less Water-Wet Rørdal, Stevns, Niobrara Chalk Core Plugs. Spontaneous im-
bibition tests at 130 C were performed on aged Stevns (13 core plugs), Rørdal (6 core plugs), and Niobrara (7 core plugs) chalk using brine with
Figure 2. Spontaneous imbibition curves at 130 C for five Rørdal chalk core plugs aged to less water-wet conditions (IW = 0.050.23) with and without the presence of sulfate in the imbibing brine. (SSW-4S) and without (SSW-0S) sulfate present. Rock properties, initial water saturations, wettability, and oil recovery are presented in Table 5. Spontaneous imbibition characteristics are found in Figures 25x. Rørdal Chalk. The wettabilities for six Rørdal chalk aged for 6 or 8 days varied between IW = 0.050.23. All core plugs were aged with Reservoir brine as the initial water phase. Core plugs PCR2, PCR3, PC2, and PC4 imbibed in brine without sulfate (SSW-0S), whereas core plugs PC19 and PC20 imbibed in brine with sulfate (SSW-4S). Figure 2 shows the spontaneous imbibition characteristics for six aged Rørdal chalk core plugs. Table 6 summarizes the oil recovery and water saturations. The oil recoveries during high temperature spontaneous imbibition without sulfate were similar for core plugs PCR2, PCR3, PC2, and PC4 with an average recovery of 52.0% OIP. Oil recoveries for core plugs imbibed in brine with sulfate (PC19 and PC20) exhibited slightly higher oil recovery (54.657.0% OIP), but no significant effect of sulfate on the spontaneous imbibition end points could be observed. Figure 2 shows the imbibition characteristics during high-temperature spontaneous imbibition and demonstrated the similarity between core plugs imbibed in brine with sulfate and core plugs imbibed in brine without sulfate. The oil recovery during room temperature imbibition ranged from 7.4 to 13.9% OIP for all six cores, compared with 51.357.0% OIP recovery at 130 C. Hence, significant additional oil was produced during spontaneous imbibition without sulfate present in the imbibing water phase when the temperature was increased to 130 C. Stevns Chalk. Dynamic crude oil aging of 13 Stevns chalk core plugs for 4 or 6 days established reduced water indices ranging from IW = 0.080.31. In the following subsections, core plugs with a wetting preference of less or equal to IW = 0.20 are described separately to core plugs with higher water indices. 1699
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Table 5. Rock Properties, Initial Water Saturations, and Oil Recovery for Less Water-Wet Stevns, Rørdal, and Niobrara Chalk Core Plugs during Spontaneous Imbibition at 130 Ca core
rock type
j (%)
K (mD)
aging time (days)
Iw
initial fluid
Swi
imbibing fluid
Rf (% OIP)
A2
Stevns
42.5
2.9
4
0.20
Chalk b
0.25
SSW-4S
43.2
A3 A7
Stevns Stevns
42.5 43.2
2.8 3.6
4 4
0.18 0.14
Chalk b Chalk b
0.29 0.28
SSW-4S SSW-0S
41.9 30.5
7C
Stevns
47.0
7.4
4
0.15
Chalk b
0.28
SSW-0S
27.7
SR1
Stevns
45.1
3.4
6
0.31
Res br.
0.28
SSW-0S
44.9
SR2
Stevns
45.8
4.1
6
0.23
Res br.
0.24
SSW-0S
32.5
SR4
Stevns
46.2
4.6
4
0.26
Res br.
0.24
SSW-4S
41.3
SR6
Stevns
47.7
6.5
4
0.26
Res. br.
0.29
SSW-4S
51.3
S8
Stevns
46.8
3.9
4
0.25
Res. br.
0.12
SSW-0S
52.6
S11 S12
Stevns Stevns
49.9 48.5
4.4 4.3
6 6
0.08 0.11
Res. br. Res. br.
0.10 0.16
SSW-0S SSW-0S
31.4 36.7
S14
Stevns
49.7
4.8
6
0.14
Res. br.
0.24
SSW-4S
68.7
S16
Stevns
48.8
4.8
6
0.09
Res.br.
0.25
SSW-4S
61.6
PCR2
Rørdal
45.9
6.3
8
0.23
Res. br.
0.24
SSW-0S
51.7
PCR3
Rørdal
47.1
4.9
8
0.20
Res. br.
0.26
SSW-0S
51.3
PC2
Rørdal
46.4
4.4
6
0.05
Res. br.
0.22
SSW-0S
53.4
PC4
Rørdal
46.5
5.1
6
0.11
Res. br.
0.18
SSW-0S
51.7
PC19 PC20
Rørdal Rørdal
46.7 45.5
3.7 5.2
6 8
0.15 0.11
Res. br. Res. br.
0.29 0.23
SSW-4S SSW-4S
54.6 57.2
NR11
Niobrara
36.6
3.0
6
0.23
Res. br.
0.24
SSW-4S
49.7
NR12
Niobrara
36.9
2.6
6
0.32
Res. br.
0.22
SSW-0S
51.6
NR14
Niobrara
37.8
2.5
6
0.26
Res. br.
0.26
SSW-4S
53.7
NR15
Niobrara
37.2
2.4
6
0.34
Res. br.
0.24
SSW-0S
48.5
NR19
Niobrara
37.3
2.7
4
0.32
Res. br.
0.25
SSW-4S
56.2
NR20
Niobrara
38.8
2.7
4
0.48
Res. br.
0.20
SSW-0S
51.6
NR22
Niobrara
37.5
2.6
4
0.40
Res. br.
0.19
SSW-4S
50.4
a
Iw, Amott water index; Swi, initial water saturation; SSW-4S, synthetic seawater with 4 times concentration of sulfate; SSW-0S, synthetic seawater without sulfate. Stevns Chalk Cores Aged to 0.08 e IW e 0.20. Figure 3 shows oil recovery by spontaneous imbibition at 130 C for eight Stevns core plugs aged at 0.08 e IW e 0.20. Core plugs imbibing brine with and without sulfate added are included. The effects of sulfate on total oil recovery and imbibition characteristics were significant; however, the early imbibition rates for all cores were initially (90 C. The work herein focus on the presence of sulfate and its effect on spontaneous imbibition in different outcrop chalks aged to different wettabilities, without investigating the concentration of sulfate needed (a constant concentration of 4 times the sulfate in seawater was used in every test) and the sensitivity to temperature (a constant temperature of 130 C was used in every test). Puntervold et al.15 found that Stevns outcrop chalk (a widely used North Sea chalk reservoir analogue) contains sulfate at the native state. The presence of sulfate has an adverse effect during the aging process to change the strongly water-wet wetting of outcrop cores by contact with crude oil. Sulfate was also observed in two chalk reservoirs in trimmings and core plugs extracted from wells which were not used for injection of
seawater.14 The sulfate concentration in chalk reservoir core plugs were higher than the sulfate concentrations reported to affect spontaneous imbibition in Stevns outcrop chalk.37 When sulfate was removed from the core by waterflooding with distilled water prior to aging (cores S11, S12, S14, and S16 in Figure 3), the effect of sulfate on the oil recovery was greater compared with core plugs where the sulfate was initially present (A2, A3, A7, and 7C in Figure 3). However, the final oil recoveries between these core plugs are not directly comparable because of the short imbibition time for the latter four cores. Although a large body of experimental data exists on the effect of potential determining ions and the effect on enhanced oil recovery, there is still no general consensus regarding the mechanisms behind the observed effect. A chemical model16 was recently proposed to study the surface potential of calcite and the adsorption of sulfate ions from the water phase. The model demonstrates that a change in the surface potential is inadequate to explain the changes in oil recovery and that mineral dissolution of calcite appears to be the controlling factor. Increased oil recoveries during waterfloods with sulfate in the injected water compared without sulfate were reported for strongly water-wet Stevns chalk cores.38 The increased oil recovery was attributed to mechanisms other than wettability alteration. Wetting Preference. The stability in wettability preference of core plugs from each chalk type (Stevns, Niobrara, and Rørdal) was studied by comparing measured Amott-Harvey wettability indices at room temperature before and after spontaneous imbibition at 130 C. The results show that the isolated effect of sulfate with regards to the change in wetting preference was small for all rock types. Table 9 shows the measured AmottHarvey indices for Stevns, Niobrara, and Rørdal. It is evident that the high temperature alone rendered the Niobrara cores almost strongly water-wet and no additional effect from sulfate was observed. Interestingly, the measured wettability preference of Rørdal chalk core plugs maintained its values from before the spontaneous imbibition at 130 C, although the spontaneous imbibition curves and water saturation end points at 130 C suggested that the wettability was strongly water-wet. This suggests that the wetting in Rørdal chalk, established by dynamic aging, did not change after high-temperature imbibition. Stevns core plugs exhibited similar behavior, with unchanged wettability values for core plugs having imbibed brine without sulfate. Core plugs having imbibed brine with sulfate at 130 C showed on average stronger water wetting; however, one core showed no difference while another showed an increase in the Amott water index of 0.12. Formation of anhydrate, because of the high temperature and high concentration of sulfate, may have reduced the changes in wettability by mechanisms involving changes in surface charges. This implies that the increased oil production observed in Stevns cores arise from an increase in water-wetness and that other mechanisms other than changes in surface charges may also play a role. The initial wetting of these two core plugs were both IW = 0.26, with less effect from sulfate compared with core plugs aged to IW < 0.2. The use of decane as the oil phase may also have influenced the effect of sulfate as an active wettability reversal ion. The desorbed polar components from the calcite surfaces, by dissolution and/or ion exchange, must have a bulk fluid to dissolve in to avoid readsorption on the surface. Compared with crude oil, decane is a poor solvent and may contribute to readsorption of the liberated polar components resulting in no or little change in the global wettability of the medium.39 Close comparison between imbibition curves at room temperature before and after spontaneous imbibition 1704
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Energy & Fuels at 130 C show equal induction times and imbibition rates which support this argument. The water-wet area, measured by the chromatographic test, increased only slightly when flooded with seawater with sulfate compared with the baseline water without sulfate in aged chalk reservoir cores.37 These results corroborate trends observed for outcrop Stevns cores herein. Nevertheless, a strong effect from sulfate present in the imbibing brine was observed for Stevns cores with decane as the oleic phase. Mineral oil was used as the oil phase throughout the study to ensure reproducibility and avoid continued aging during the elevated temperature imbibition experiments. It remains to be seen if the lower solubility of sulfate in mineral oil will impact the results. A study of this is ongoing. Use of Reservoir Rock Analogues. Outcrop rocks are widely used as reservoir rock analogues to study fluid flow in oil reservoirs because of low cost, excellent rock characterization, and easily accessible rock material. Nevertheless, care should be taken when applying laboratory observations to petroleum reservoirs, especially when studying the chemical interaction between the rock surface and the fluids present such as brine solid interactions. Comparison of the distribution of silica (opalCT) and clay minerals in outcrop Rørdal and Stevns chalk samples showed that Rørdal chalk was richer in silica.19 It was observed that silica produced opal-CT lepispheres in larger pores and irregular, bladed structures in narrow pores which may reduce permeability locally. The effect on wettability alteration during aging was studied in detail,20 showing that the chromatographic wettability test40 demonstrated a strongly water-wet rock for Rørdal chalk (termed Aalborg chalk in their work), whereas the Amott-Harvey wettability index showed neutral wettability. The water-wet fraction, measured by chromatographic wettability test must exceed 0.6 for spontaneous imbibition of brine to occur in chalk.41 A strong correlation between a shift in the NMR T2 relaxation times with a change in Amott-Harvey indices was reported by measuring the location of oil and water in the pore space at different wettability conditions in Rørdal chalk.42 The apparent discrepancy between the measured chromatographic water-wet fraction and the spontaneous imbibition curves above was attributed to small fractions of the chalk surface becoming oil wet only close to the pore throats, thus limiting spontaneous imbibition of both water and oil at the residual saturations.20 However, this does not explain why the spontaneous imbibition curves in aged Rørdal cores exhibited increased end points and imbibition rates at elevated temperature and returned to the previously observed end points and imbibition rates at room temperature in the subsequent wettability measurement test. The potential for oil recovery by spontaneous imbibition into chalk cannot be predicted from the water-wet fraction index using the chromatographic technique, unless the chalk has the same mineral properties regarding Si-content.20 The correlation between the chromatographic wetting index, the oil recovery by spontaneous imbibition, and the Amott-Harvey index was exponential.41 The displacement of sulfate present in outcrop chalk was reported to increase the effect from sulfate during spontaneous imbibition.15 The validity of removing sulfate present in the core plugs prior to aging with the scope of studying processes in chalk fields may be questioned if the high concentrations of sulfate in two chalk fields14,37 are representative for chalk fields in general. Nevertheless, increased water-wet behavior with the presence of sulfate at full reservoir conditions in a core plug from a North Sea chalk reservoir has been reported.13 These results demonstrate that the success of altering the wettability to increase oil recovery by spontaneous imbibition is a process that requires great care
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when implemented in the field. Detailed knowledge of the formation brine is crucial to design water that will maximize recovery. They also demonstrated that the reported trends and results for outcrop rocks do not necessarily reflect the actual behavior of the fields in question.
’ CONCLUSIONS Additional oil recovery was observed during spontaneous imbibition tests at 130 C in aged outcrop core plugs with sulfate in the imbibing brine compared with brine without sulfate. Core plugs from three different quarries were tested and the effect from sulfate was dependent on the chalk type as increased oil recovery was only observed for one chalk type. Mineral depositions and compositional differences are believed to be key features responsible for the observed differences in the benefit of sulfate interacting with the calcite surface for the three chalk types. The initial wettability preference of the rock surface influenced the added recovery from sulfate in the imbibing water phase, and the effect becomes less significant as the initial wettability of the rock becomes more water-wet. The following key observations were made: (1) No added oil recovery effect from sulfate in the imbibing brine was observed in aged Niobrara outcrop chalk during spontaneous imbibition tests at 130 C. (2) The wettability of four Niobrara chalk cores aged to less water-wet conditions changed toward strongly water-wet conditions after spontaneous imbibition at 130 C regardless if sulfate was present in the imbibing water phase or not. (3) No added effect from sulfate on oil recovery during spontaneous imbibition at 130 C was observed in aged Rørdal outcrop chalk. All Rørdal core plugs, imbibing brine with or without sulfate, exhibited strongly water-wet recoveries, imbibition rates, and water saturation end points during spontaneous imbibition at 130 C. The effect from sulfate could not be isolated. (4) Added oil recovery from sulfate in the imbibing brine was observed in aged Stevns outcrop chalk cores during spontaneous imbibition tests at 130 C. The process was less efficient than previously reported and shows that the sulfate effect is sensitive to the oil/brine/rock system used. The effect was greatest in core plugs with Amott water indices below 0.2, whereas the effect was less significant when the initial wettability was 0.25 or above. (5) The wettability preferences in two aged Rørdal chalk cores did not change during spontaneous imbibition tests at 130 C as the Amott water indices measured at room temperature before and after tests at elevated temperature were equal. (6) The wettability preferences of two aged Stevns chalk cores plugs remained the same before and after spontaneous imbibition at 130 C without sulfate in the imbibing water phase. The wettability preferences of two aged Stevns chalk cores plugs imbibed with sulfate exhibited a slightly higher Amott water index for one core and a stable water index for the other core. ’ AUTHOR INFORMATION Corresponding Author
*E-mail:
[email protected].
’ ACKNOWLEDGMENT The authors would like to thank the Royal Norwegian Research Council, BP, Statoil, Maersk, and ConocoPhillips for financial support. Thanks to ConocoPhillips for access to laboratory facilities at their Technology Center in Bartlesville, OK, and Jim Stevens for invaluable laboratory assistance. 1705
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