Impact of Plagioclase on the Low Salinity EOR-Effect in Sandstone

Mar 11, 2014 - University of Stavanger, 4036 Stavanger, Norway. ABSTRACT: The mechanism of the low salinity EOR process in sandstone reservoirs has ...
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Impact of Plagioclase on the Low Salinity EOR-Effect in Sandstone Skule Strand,* Tor Austad, Tina Puntervold, Hakan Aksulu, Bjarne Haaland, and Alireza RezaeiDoust University of Stavanger, 4036 Stavanger, Norway ABSTRACT: The mechanism of the low salinity EOR process in sandstone reservoirs has been debated in the literature for more than a decade. We recently proposed a chemical wettability alteration mechanism for the process, well founded in experimental observations showing that the increase in pH as the high saline water is displaced by the low saline water is a key factor. Even though this chemical understanding is quite well described, there are parameters/factors that can disturb the main process like the following: combinations of certain minerals, temperature, salinity, and composition of formation water could have impact on the low salinity EOR processes. Plagioclase, a polysilicate mineral, which is often present in sandstone reservoir rock, can have a significant effect on the initial pH of the formation water, which will influence the initial wetting condition. In this experimental work, it is shown that the presence of plagioclase in reservoir rock and outcrop material responded differently on the low salinity EOR-effect. The experimental results are discussed in relation to the previously published chemical mechanism for the low salinity EOR process, where changes in pH are believed to promote the wettability alteration of the rock.

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INTRODUCTION In recent papers, we have pointed out the importance of pH in the chemical understanding of the low salinity EOR-mechanism in sandstone reservoirs.1−3 Numerous papers have appeared in the literature dealing with various reservoir parameters that may have impact on the low salinity EOR-effect. One important parameter is linked to wettability, and it is commonly accepted that the rock must be mixed-wet. The clays, as the main wetting minerals, are playing an important role in the wettability alteration process, triggering the low salinity EOR-effect. Without a balanced adsorption of active cations (mainly Ca2+ and H+) and basic and/or acidic organic material from the crude oil onto the clay minerals, it is hard to observe any tertiary increase in oil recovery when switching from an injection of high salinity (HS) brine to a low salinity (LS) brine. The presence of active polar components in the crude oil, which are the anchor molecules for adsorption of oil onto the rock surface, can be quantified by the acid and base number, AN and BN, given by mg KOH/g of oil. Clay minerals are chemically unique, because they act as cation exchangers due to the presence of permanent negative charges. The adsorption of basic and acidic material onto the clays depends on the pH, temperature, salinity, and composition of the formation water (FW). The protonated form of the basic material, R3NH+, and the undissociated carboxylic acid, RCOOH, appeared to be the most reactive species toward the negatively charged clay surface, meaning that the reservoir rock becomes less water-wet as the pH of the formation water is decreased below 7.1−3 Due to the presence of acidic gases, like CO2 and H2S, in the reservoir crude oil, the pH of the formation water in many oil reservoirs is in the range of 5−6, which is favorable for obtaining a reservoir rock of mixed wettability. Even though the maximum oil recovery by water flooding is obtained at neutral to slightly water-wet conditions, i.e. at low capillary pressure,4 tertiary low salinity EOR-effects can be observed if the LS brine increases the water wetness of bypassed clay containing pores. The microscopic sweep efficiency is then improved by spontaneous imbibition of the © 2014 American Chemical Society

LS brine into previously bypassed oil containing pores of low water wetness, and a new bank of oil is formed. When active cations, especially Ca2+, are desorbed from the clay surface as the HS formation water is exchanged by the LS water, a local increase in pH at the clay surface, due to adsorption of proton, H+, onto the clay, is suggested to promote desorption of organic material due to an ordinary acid−base reaction.2,3 The adsorbed organic material is then transformed to the basic form, i.e. R3N: and RCOO−, which has a much lower affinity toward the clay surface.5,6 Proton transfer reactions in aqueous solutions are, however, known to be very fast, mostly diffusion controlled. Therefore, the rate determining step for observing the LS EOR-effect is the desorption of active cations like Ca2+ from the clay surface, which is an exothermic process.1 Certain minerals, like plagioclase, could influence the pH of the formation water and affect the initial wetting condition of the reservoir as well as the increase in pH as the HS water is exchanged by the LS water. Therefore, plagioclase present in reservoir rock may act differently from plagioclase present in outcrop material. Plagioclase containing alkali metals, Na+ and K+, can in some cases exchange with protons, H+, depending on salinity and composition of the brine it is exposed to. In this paper, we will focus on the impact of plagioclase on the LS EOR-effect for both reservoir and outcrop sandstone core material and discuss the observations in relation to the newly proposed chemical mechanism for the LS EOR-effect.2,3

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EXPERIMENTAL SECTION

Core Material. In this experimental work, both reservoir and outcrop sandstone rock material were used. • The reservoir core RC2 was from a North Sea sandstone reservoir; it contained ∼15 wt % clay, mostly illite/mica and kaolinite. The content of plagioclase was ∼32 wt %. The porosity was 26.9%, and the permeability was 401 mD, Table 1. Received: December 10, 2013 Revised: March 11, 2014 Published: March 11, 2014 2378

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Table 1. Core Data core no.

illite/mica (wt %)

kaolinite (wt %)

chlorite (wt %)

tot. clay (wt %)

plagioclase (wt %)

porosity (wt %)

perm. (mD)

PV (cm3)

RC2 B02 B04 B14

9.3 8.4 8.4 8.1

2.6 0 0 0

3.6 1.9 1.9 1,8

15.5 10.4 10.4 9.9

32 30.4 30.4 32.6

26.9 20.1 ∼20 20.0

401 185 419

18.3 16.0 ∼16 16.0

• The outcrop sandstone core material was delivered by TOTAL. All cores contained ∼10 wt % clay, mostly illite, and no kaolinite. The content of the plagioclase albite was ∼25 wt %. A small amount of CaCO3 was present as cementing material. The outcrop material was very homogeneous, with permeability and porosity in the range of 200−400 mD and 20%, respectively, Table 1. Crude Oils. Two different stabilized crude oils were used, both low in acid number, AN, and with higher base number, BN, Table 2.

The core with initial Swi of 20% was mounted into a core flooding setup using a confining pressure of 30 bar and a back pressure of 10 bar. After a short evacuation, the core was saturated and flooded with CO2 saturated crude oil 1, 2 PV in each direction at 50 °C. The core was then aged in the core holder at the reservoir temperature, 90 °C, for 14 days. The outcrop core was treated in a similar way, but without any cleaning procedure. Oil Recovery Tests. The restored reservoir core RC2 was flooded successively by FW1, SW, and LS1 at reservoir temperature, at 90 °C. The flooding rate was 2PV/D, but the rate was increased to 4 and 8 PV/D at the end of the LS1 flood to detect end effects, if any. Oil recovery tests on the outcrop core material were performed with and without CO2 present in crude oil 2, on the cores B02 and B14, respectively. The cores were aged at 60 °C for 2 weeks prior to the testing. The oil recovery tests were performed at 40 °C by successively flooding with FW2 and LS2 brines. The effluent was sampled in a buret at ambient conditions, and the volume of produced oil was compensated for pressure, temperature, and gas liberation. The oil recovery and pH of the produced water were measured as a function of pore volume of brine injected. pH Screening of Core Material. The brine rock interactions for both the reservoir and outcrop core material were observed by using the pH screening technique.1 • After the oil recovery test, the reservoir core RC2 was cleaned by successively flooding with toluene and methanol and then dried to constant weight. • The core was saturated with FW1 brine and left overnight to equilibrate in the core holder at the test temperature with a confining pressure of 30 bar and a back pressure of 10 bar. Then the core was flooded at a constant rate of 4 PV/day, first with FW1 brine until stable pH in the effluent. The flooding fluid was then switched to Seawater, SW. After a stable pH was observed in the effluent, the injected fluid was switched to the LS1 brine (1000 ppm NaCl). The pH in the effluent was recorded against PVs of brine injected. • In a second test, the cleaned reservoir core, RC2, was subjected to a similar pH screening test, now at different temperatures, 40, 90, and 130 °C, using the FW2 and LS2 brine, 100 000 and 1000 ppm, respectively. • The outcrop core was tested in a similar way at the given temperatures using FW2 as the HS brine and LS1 as the LS brine. Chemical Analysis. During core flooding, samples of the effluent were collected, and the pH was measured at ambient conditions.

Table 2. Chemical and Physical Properties of Stabilized Crude Oils crude oil

AN (mg KOH/g)

BN (mg KOH/g)

viscosity (mPa s)

density @20 °C (g/cm3)

0.1

1.8

17.6 @20 °C

0.846

0.07

1.23

5.6 @30 °C

0.837

crude oil 1 crude oil 2

• Crude oil 1 is the stabilized reservoir crude oil that originally belonged to the same reservoir that core RC2 was taken from. • Crude oil 2 is a stabilized reservoir crude oil chosen for the outcrop core material experiments. • CO2 saturated crude oils: In some of the oil recovery experiments, the stabilized crude oils were saturated with CO2 prior to use. The crude oil was transferred to a recombination cell. CO2 gas was injected and dissolved into the crude oil until a saturation pressure of 6 bar was achieved at room temperature. All oil recovery experiments were conducted with a back pressure of 10 bar to avoid two phase flow of oil and gas. Brine. Different synthetic brines were used; two formation waters FW1 and FW2, two low salinity waters LS1 and LS2, and synthetic seawater, SW. The ion compositions and salinities are listed in Table 3.

Table 3. Chemical Composition and Salinity of the Brines Used ions

FW1 (mM)

FW2 (mM)

LS1 (mM)

LS2 (mM)

SW (mM)

Na+ K+ Li+ Mg2+ Ca2+ HCO3− Cl− SO42‑ TDS, g/L ionc strength pH

528.2 3.1 0.0 6.6 28.4 6.3 596.0 0.0 35.1 0.638 7.2

1540.0 0.0 0.0 0.0 90.1 0.0 1720.2 0.0 100.0 1.810 6.0

8.6 0.0 0.0 0.0 0.0 0.0 8.6 0.0 0.5 0.009 6.2

17.1 0.0 0.0 0.0 0.0 0.0 17.1 0.0 1.0 0.017 6.2

450 10.0 0 450 13.0 2.0 525 24 33.39 0.657 7.94

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RESULTS AND DISCUSSION Reservoir Core Containing Plagioclase, RC2. The reservoir core, RC2, was from a North Sea oil reservoir with a formation water salinity of 35 138 ppm (FW1), which is slightly higher than seawater (SW) salinity, 33 390 ppm, Table 3. In the oil recovery experiment, stabilized crude oil from the same reservoir was used, crude oil 1, with an AN and BN of 0.07 and 1.23 mg KOH/g, respectively. During the establishment of initial water saturation using the desiccator technique, the core was flooded with 5 times diluted FW1. The initial pH of the five times diluted formation brine was 7.6, but, surprisingly, the pH of the effluent was very high, slightly above 10. The pH remained at this level during the flooding of more than 10 PVs. The core with Swi = 0.20 was saturated and aged with crude oil 1 containing CO2. The CO2

Core Preparation. The preserved reservoir core RC2 was cleaned mildly by flooding it first with kerosene to remove initial crude oil and second with heptane to remove kerosene. At the end, the core was flooded with 1000 ppm NaCl solution to remove formation brine before it was dried to constant weight at 90 °C. The core was saturated and flooded with 5 times diluted FW1. The initial water saturation of 20% was established using the desiccator technique.7 2379

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albite, NaAlSi3O8, which is a common mineral of the plagioclase family, can be taken as a model compound. Albite, containing an exchangeable cation, Na+, can act as a buffer at moderate salinity conditions as shown by the following equilibrium:8

in the crude oil could then dissociate into the formation water and create a more acidic environment during core aging. In the oil recovery test, the aged core was flooded successively with the following: FW1→SW→LS1 brine (500 ppm NaCl) at 90 °C, Figure 1. An ultimate oil recovery close to

NaAlSi3O8 + H 2O ↔ HAlSi3O8 + Na + + OH−

(1)

The salinity of the FW1 water (35 138 ppm) is not high enough to move the equilibrium to the left and prevent an alkaline environment. Furthermore, the pH of the formation water did not decrease below 7 by adding CO2 to the system due to the buffering effect of the plagioclase as illustrated by the following equations: CO2 + H 2O ↔ H 2CO3

(2)

H 2CO3 + OH− ↔ HCO3− + H 2O

(3)

With an initial pH > 7 in the FW1 in core RC2, the adsorption of both basic and acidic organic material onto the clay minerals will drastically decrease.1,2,5,6,9,10 Thus, the reservoir rock becomes too water-wet for observing significant LS EOR-effects. Based on the following core data from previously published work,11 L = 6.12 cm, D = 3.8 cm, PV = 18.3 cm3, k = 401 mD, DP = 3 mbar (at Sorw after flooding with FW1), the end point permeability of water was calculated to krw = 0.19, which also is in line with water wet conditions. The pH increased when SW was exchanged with the LS1 brine, but with a negligible amount of organic material adsorbed onto the clay, no LS EOR-effects could be observed. Ion exchange at the surfaces of plagioclase, eq 1, and clay, eq 4, will contribute to the increase in pH as the LS1 water is injected, but the observed pH increase was rather small due to the buffering effect of CO2, which was still present in the crude oil.

Figure 1. Oil recovery vs PV injected for core RC2. The flooding sequence was FW1→SW→LS1. Flooding rate of 2 PV/D; Tres = 90 °C.11

50% of OOIP was obtained during flooding with FW1. A small increase in oil recovery, 2−3% of OOIP, was observed when switching to SW, but no improvement in oil recovery was noticed using the LS1 brine, even after the injection rate was increased 4 times. Thus, SW with a slightly lower salinity than FW1 appeared to act as a low salinity EOR fluid. It should be noticed that the concentration of Ca2+ in FW1 was 2−3 times higher than in SW, Table 3, but the concentration of Mg2+ in SW was much higher than that in FW1, by a factor of 6.4. Thus, the presence of a significant amount of Mg2+ in SW did not prevent a small EOR-effect. The initial pH of the first produced FW1 was well above 7 even though CO2 was added to the system, Figure 2. The salinities of FW1 and SW were quite similar, and the pH stayed slightly below 7 also during the flooding with SW. When switching to the LS1 water (500 ppm NaCl), the pH increased to about 8.3. The pH gradient was low due to the buffering effect of CO2.

After the oil recovery test, the core RC2 was cleaned with toluene and methanol. The pH gradient was studied using a 100% brine saturated core without CO2. The core was flooded successively with FW1→SW→LS2 (1000 ppm NaCl) at 90 °C, Figure 3. The effluent pH during the flooding with FW1 was even higher, close to 8, as expected. A small increase in pH, about 0.4 pH units, was observed when the injected fluid was switched from FW1 to SW. This could be explained by the

Figure 2. Produced water pH and salinity vs PV injected during the oil recovery test on core RC2.11

Figure 3. Effluent pH vs PV injected during brine flooding of core RC2 at 90 °C. The flooding sequence was FW1→SW→LS2 (1000 ppm NaCl).

Clay‐Ca 2 + + H 2O ↔ Clay‐H+ + Ca 2 + + OH− + heat (4)

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difference in the Ca2+ concentration between FW1 and SW, and it could also explain the small LS EOR-effect observed on a rather water-wet RC2 core, Figure 1. The increase in pH was more significant when SW was exchanged with LS2, about 0.8 pH units. A second pH-screening experiment was performed on core RC2. In this case, the formation water FW2 was used, with a much higher salinity of 100 000 ppm containing both Ca2+ and Na+ cations. The LS2 water contained only NaCl with a salinity of 1000 ppm, Table 2. As shown in Figure 4, the high salinity

According to these observations, it should be possible to observe the increased LS EOR-effect in core RC2 at 90 °C by using a formation water with higher salinities, like FW2 with a salinity of 100 000 ppm. A lower initial reservoir pH will increase adsorption of organic material onto the clay, and the potential for LS EOR-effect will increase. Outcrop Cores Containing Plagioclase. Two oil recovery tests and pH screening tests have also been performed on outcrop cores containing plagioclase. An initial water saturation of 20% was obtained by the desiccator technique. A stabilized crude oil, crude oil 2, with AN and BN of 0.1 and 1.8 mg KOH/g, respectively, was used. The cores were aged at 60 °C for 2 weeks. In order to observe effects of the initial pH, a second core was saturated and aged with the same crude oil, now containing CO2. The high salinity formation water contained CaCl2 and NaCl with a salinity of 100 000 ppm, FW2. The LS2 brine contained only NaCl with a salinity of 1000 ppm, Table 3. The oil recovery test was performed at 40 °C by successively flooding FW2 and LS2 at a rate of 4 PV/day, Figure 5. During the FW2 flooding, core B02 with CO2-saturated crude oil reached a recovery plateau of 46% of OOIP, while the recovery for core B14 without CO2 present in the crude oil was 41% of OOIP. 5% OOIP lower oil recovery indicates a more water-wet core.4 In addition to a wettability modification in the presence of CO2, also a decrease in viscosity of the oil may contribute to increased oil recovery. During the LS2 flooding, the oil recovery increased with 15% OOIP, from 46 to 61% of OOIP, for the core containing CO2saturated crude oil, core B02. The LS EOR response for the core without CO2 present was much less, only 6% OOIP, from 41 to 47% OOIP. For both cores, the pH of the first produced water was well below 7, and the pH from the core with CO2saturated crude oil was significantly lower than that from the core without CO2 present, Figure 5b. Thus, in line with the suggested LS EOR-mechanism, initial acidic conditions in the reservoir will improve the adsorption of organic material onto the clay minerals, which improves the LS EOR-potential. The response in pH, when switching from HS to LS brines, was tested on a third 100% water saturated outcrop core at 3 different temperatures. The same HS and LS brines were used, i.e. FW2 and LS2, Figure 6. In the first test at 40 °C, the pH of the effluent using the HS water was close to 6. For an outcrop core, the albite has initially been exposed to fresh water for a very long time, and it will partly be on the protonated form.

Figure 4. Effluent pH versus PV injected in core RC2 at 40, 90, and 130 °C. The brine flooding sequence was FW2-LS2-FW2. The switching points between injection fluids are indicated by the dashed lines. The slopes of the pH change are indicated by the straight lines.1

formation water decreased the ion exchange from the plagioclase, i.e. the equilibrium shown by eq 1 was moved to the left due to the high salinity of FW2, and the initial pH remained slightly below 7 for all the tested temperatures. As the LS2 fluid displaces the HS fluid, both plagioclase and clay will contribute to the increase in pH as described by eqs 1 and 4. As discussed previously, due to the strong hydration energy of Ca2+, the ion exchange at the clay surface appeared to be an exothermic process, which is confirmed by the decrease in pH gradient as the temperature is increased, Figure 4.1 In all cases, the pH stabilized at the initial pH when LS2 was exchanged with FW2, i.e. protons at the plagioclase and clay surface are replaced by active cations, Na+ and Ca2+, present in the FW brine.

Figure 5. a. Effect of initial pH on oil recovery in tertiary low salinity flood. T = 40 °C. Flooding sequence: FW2 and LS2.3 b. Change in pH of the effluent during oil recovery test for the cores with and without CO2 saturated crude oil.3 2381

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Some General Comments. As noticed in Figure 5a, the LS EOR-effect is doubled for the core containing CO2 but with a much longer response time. Due to the buffering effect of CO2, the pH gradient is lower, Figure 5b. Thus, the presence of an acidic gas like CO2 will enhance adsorption of organic material onto the clay minerals, decrease the water wetness of the rock, and increase the LS EOR potential, but the response time will be longer due to the decrease in the pH gradient. Thus, a large increase in the pH gradient as the HS water is replaced by the LS water will decrease the response time for the LS EOR-effect. In the pH range of 6 to 9, the concentration of H+ varies between 10−6 to 10−9 mol/L. Thus, only very small changes in the mineralogical properties of a reservoir rock could impose significant changes in pH, which has a drastic effect on the affinity of both acidic and basic organic material toward the clay surface. It is the plagioclase minerals with exchangeable alkali metal ions, Na+ and K+, which will have the greatest impact on the pH as the composition and salinity of the brine varies. In that way, outcrop and reservoir core material containing plagioclase could respond differently regarding potential LS EOR-effects. In a recently published paper by Quan et al.,12 it was observed that reservoir core material containing high amounts of both plagioclase and clay, in the range of 20 and 25 Wt %, respectively, responded extraordinarily well to the LS EOReffect with an increase in oil recovery of about 15% of OOIP. The salinity of the FW was about 60 000 ppm, and the initial pH was 6.5. As the HS water was exchanged with the LS water the pH increased rapidly to 9.5, i.e. a factor of 3 pH units. Obviously, in this case also the plagioclase contributed to the increase in pH in the LS EOR process. Also the salinity of the FW was high enough to keep the initial pH well below 7. Thus, the learning from this work is that plagioclase minerals, if present in the reservoir rock, can have both positive and negative effects on the LS EOR process depending on the salinity of the formation water.

Figure 6. Effluent pH versus PV injected into the outcrop core at 40, 90, and 130 °C. The brine flooding sequence was FW2-LS2-FW2. The switching points between injection fluids are indicated by the dashed lines.1

Therefore it will give an acidic solution when a HS brine is introduced, as shown by eq 5: HAlSi3O8 + Na + ↔ NaAlSi3O8 + H+

(5)

After passing through the HS→LS→HS flooding process at 40 °C, the temperature was increased to 90 °C. In this case, the pH stabilized close to 7 during the HS flood. Thus, it appeared that equilibrium between the cationic, NaAlSi3O8, and the protonated, HAlSi3O8, form of the albite was established. After the flooding cycle at 90 °C, the temperature was increased to 130 °C. In this case, it took some time to stabilize the pH during the HS flood, pH ≈ 6.5. For each of the test temperatures, 40, 90, and 130 °C, an increase in pH between 2 and 3 pH units was observed when switching from the HS to the LS brine. The effect of temperature on the pH gradient was less significant compared to the reservoir core, indicating that the cation exchange linked to the plagioclase, eq 1, is the main contributor to the pH increase. The contribution from the clay minerals could be explained by the mineral structure of kaolinite and illite. For kaolinite, the cations are adsorbed on the mineral surface. For illite, cations are adsorbed in between the layers and are not that easily desorbed. Only illite clay was present in the outcrop core, Table 1. Furthermore, the difference in hydration energy between Na+ and Ca2+ may also play a role. At high temperature, the reactivity of Ca2+ toward the negative charge on the clay surface is increased due to reduced hydration of the Ca2+ ion. The repeated discontinuity at high pH observed at all the tested temperatures could be explained by an increased time interval between effluent sampling and pH analyses during the night. The adsorption of CO2 from the air into the sample glasses will increase with alkalinity and time, even though the sampling glasses were sealed with septum. The reason why this outcrop core material from TOTAL responded so well for the low salinity EOR-effect can be explained in the following way: • The presence of albite gives an initial pH below 7 when exposed to the HS formation water, causing increased adsorption of organic material onto the clay surfaces. • The increase in pH by switching from HS to LS injection fluid will promote a large increase in pH, where both plagioclase and the clay minerals played an important role according to eqs 1 and 4.

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CONCLUSIONS Plagioclase present as a mineral in sandstone reservoirs could have a great effect on the LS EOR potential because it could influence the initial pH of the formation water both in a positive and negative way. The observations from this work can shortly be summarized as follows: • Plagioclase minerals present in reservoir core material can give an initial pH > 7 if the salinity of the FW is moderate, which will make the rock too water wet for observing larger LS EOR-effects. • With high salinity FW, the initial reservoir pH will be below 7, promoting a mixed wet wettability. In that case, plagioclase can contribute to the increase in pH as the HS water is displaced by the LS water, and significant LS EOR-effects could be obtained. • In outcrop sandstone the plagioclase/albite has been exposed to fresh water, and the mineral is therefore partly on the protonated form. When the outcrop core is exposed to HS formation water, the pH will go below 7, and the rock wettability will become mixed wet, which is the needed condition for observing LS EOR-effects. Furthermore, as the high salinity FW is exchanged by the LS water, the plagioclase will also contribute to the increase in pH, which is important for desorption of organic material from the clay minerals. • The experimental observations are completely in line with the newly proposed mechanism for the LS EOR-effect 2382

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involving an increase in pH as the HS water is displaced by the LS water.

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AUTHOR INFORMATION

Corresponding Author

*E-mail: [email protected]. Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS Petoro and TOTAL are acknowledged for supplying relevant core material and oil samples. REFERENCES

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