Adsorption of Acidic Crude Oil Components onto Outcrop Chalk at

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Adsorption of acidic crude oil components onto outcrop chalk at different wetting conditions during both dynamic adsorption and aging processes Paul Andrew Hopkins, Kenny Walrond, Skule Strand, Tina Puntervold, Tor Austad, and Abdi WakWaya Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.6b01583 • Publication Date (Web): 03 Aug 2016 Downloaded from http://pubs.acs.org on August 10, 2016

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Adsorption of acidic crude oil components onto outcrop chalk at different wetting conditions during both dynamic adsorption and aging processes P. A. Hopkins, K. Walrond, S. Strand, T. Puntervold, Tor Austad and A. Wakwaya University of Stavanger, 4036 Stavanger, Norway

Abstract Restoration of carbonate reservoir core material for special core analysis has been debated in the literature for some time. An important goal of core restoration is to reproduce initial reservoir wetting properties because wettability dictates important reservoir parameters like capillary pressure and relative permeability of oil and water. It has previously been found that acidic polar components in crude oil dictates the wetting properties in carbonate core material. In this paper, the effects on chalk wettability from crude oil flooding, core aging, and mild core cleaning were investigated experimentally. The experimental results confirmed that adsorption of acidic polar components are an instantaneous process and that a dynamic equilibrium was achieved with a specific adsorption capacity of the initially very water wet chalk surface. The crude oil flooding reduced the water-wet surface area. Core aging for 2 weeks at the test temperature reduced the water-wet surface area even further, which appeared to be closer to a thermodynamic equilibrium. Spontaneous imbibition tests confirmed mixed-wet conditions, regardless ageing or not. A second oil flooding was performed on a mildly cleaned, initially mixed-wet chalk core. The dynamic adsorption equilibrium of polar organic components were now drastically reduced. Based on the results from this experimental study, the wetting in outcrop chalk is dependent on the amount of crude oil allowed to contact the rock surface, and the time period of contact, i.e. the aging period. A core restoration procedure involving mild core cleaning and a controlled small volume of crude oil injection could be a more optimal core restoration procedure for reservoir chalk and limestone cores.

Introduction Special Core Analysis (SCA) related to carbonate oil reservoirs have been, and are still a topic for discussion in the literature, especially when it comes to core preparation to mimic reservoir conditions. Core cleaning and core restoration are important when SCA involving wettability-dependent experiments like capillary pressure, relative permeability and Smart Water EOR effects.

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Hot Soxhlet extraction has been used to clean both sandstone and carbonate reservoir core samples, to completely water wet conditions. The cores have then been dried and saturated with Formation Water (FW). Initial water saturation are normally established by displacing FW with several pore volumes (PV) of crude oil at increasing injection rates until residual water saturation (Swr) is reached. At the end the core has been aged at reservoir temperature. This core restoration procedure may still be a reasonable technique for sandstones, but due to very strong bonding between negatively charged carboxylic acids in the crude oil and the positively charged calcite surface, experiments have shown that the removal of adsorbed acidic material is incomplete.1 In a previous study,2 water-wet reservoir limestone cores sampled in water zone were restored with formation water (FW) and reservoir crude oil. Oil recovery tests by spontaneous imbibition (SI) gave recoveries of about 40 %OOIP. Core cleaning of the same cores by successively flooding with Toluene, Methanol, and at the end deionized (DI) were performed. After a second core restoration, the oil recovery by SI dropped below 10 %OOIP, giving significant differences in wetting conditions after the first and second core restoration. Masalmeh and Jing3 investigated the difference between mercury injection and oil-brine centrifuge capillary pressure (Pc) curves after cleaning reservoir limestone cores with different solvents. Based on a hot Soxhlet extraction followed by a flow through cleaning using different types of solvents, they were able to achieve uniformly water-wet samples. The water-oil drainage Pc curve measured by centrifuge matched the Pc curve obtained by mercury injection. Based on certain SCA experiments, they claimed that they were then able to convert the primary drainage Pc curves to imbibition Pc curves by calculations taking into account the effect of wettability. Thus, it is possible to obtain imbibition Pc curves by modelling provided that Pc drainage curves for completely water-wet cores were available. As a consequence of the above listed examples, two interesting questions arise: (1) “is it possible to use completely water-wet outcrop carbonate core material for SCA in experiments involving water-based EOR by wettability modification”, and (2) “is completely water-wet cores the best starting point for obtaining wetting properties similar to actual reservoir conditions in the laboratory?” Acidic carboxylic organic material in the crude oil is the most important wetting parameter for carbonates.4 The amount of acidic material in the crude oil can be quantified by the acid number (AN), which has the unit mgKOH/g oil. For AN = X, it means that X mg KOH is needed to neutralise the acidic material present in 1 g of oil. In a recent publication,5 it was confirmed that the adsorption of acidic crude oil material onto outcrop chalk surfaces was very fast. Crude oil with AN = 0.34 mgKOH/g was injected at 50 °C with a rate of 4 PV/D into a chalk core with Swi=0.1. The AN in the eluted crude oil from the core, was monitored as a function of PVs injected. The adsorption of acidic organic compounds reached a dynamic equilibrium after 10 PV crude oil injected in the first core restoration. The mild core cleaning (kerosene/heptane/DI-water) preserved approximately 3/4 of the polar components initially adsorbed onto the pore surface. In the second core restoration, the adsorption equilibrium for acidic material was reached after only 6 PV of crude oil, and the water-wet surface area was reduced compared to that of the first restoration.


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Zahid et al.6 claimed in their study that cores that had been saturated with crude oil, but had not been aged, were water-wet. Based on previously published experimental data,5 aging was not a necessary condition to obtain mixed wettability, as immediate adsorption of polar components onto the chalk surface took place upon contact and the core material behaved mixed-wet. However, aging may have an effect on wetting because of the increased time of contact between the oil components and the rock surface. The objective of this paper was to observe changes in wetting properties as a function of initial wetting condition; completely water-wet and mixed-wet, by dynamic crude oil flooding and with and without a static aging process. The aim was to observe any changes in adsorption of polar organic acidic components in the crude oil onto the outcrop chalk surface under the different wetting conditions. The experimental test program was as follows: • •

•

•

Two completely water-wet outcrop chalk cores, P1 and P2, were used. The cores with Swi=0.10 was flooded with crude oil at 50 °C until a dynamic equilibrium was reached. The AN of the eluted oil was monitored and presented versus PV injected. The total amount of acidic components adsorbed onto the chalk surface was determined, spontaneous imbibition and a chromatographic wettability test were performed to evaluate wettability and fraction of water-wet surface area inside the core. After the crude oil flooding, but before the spontaneous imbibition or chromatographic wettability tests, core P1 was not aged, but core P2 was aged for 2 weeks at 50 °C. After the first test series the cores were mildly cleaned, restored again with Swi=0.10 and a new crude oil flooding was performed, monitoring acid adsorption. Again, spontaneous imbibition and a chromatographic wettability test were performed to evaluate wettability and fraction of water-wet surface area inside the core. Core P1 was not aged, but P2 was aged for 2 weeks at 50 °C.

Experimental Core material Outcrop chalk material from Stevns Klint (SK) close to Copenhagen, Denmark, was used. The outcrop chalk core consists of 98% pure biogenic CaCO3, determined by SEM-EDS. The chalk has high porosity (42-50%) and low permeability (3-5 mD). Cores from the same block used in wettability experiments has shown very good reproducibility and are often used as a model rock and is considered an analogue of North Sea chalk reservoirs.7. The cores were drilled from the same block in the same direction and prepared following the procedure set by Puntervold et al.8 All cores were initially flooded with 5 pore volumes (PV) of de-ionized (DI) water to remove easily dissolvable salts, especially sulphate. The cores were dried at 90 °C to a constant weight. The core properties are given in Table 1. The cores were restored several times, to different wetting conditions. In those tests the cores were renamed to e. g. P1:R1, referring to core P1 being restored for the first time R1. 3 ACS Paragon Plus Environment

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Table 1. Physical properties of the SK outcrop cores used Core P1 P2 P8 Length, cm 5.96 5.96 5.91 Diameter, cm 3.77 3.8 3.75 Bulk Volume, cm3 66.53 67.62 65.05 Dry weight, g 93.12 94.6 89.58 Saturated weight, g 122.00 126.75 117.00 3 Density of d10FW, g/cm 1.003 1.003 1.003 Pore Volume, ml 27.74 32.054 27.33 Porosity % 42 47 42

Brine Composition Synthetic formation water (FW), similar to a Norwegian offshore chalk reservoir, was used as FW in core restoration, and also as imbibing fluid in spontaneous imbibition experiments. SW0T and SW½T were used in the chromatographic wettability test.9 Brine compositions are reported in Table 2.

Table 2. Chemical composition of brines used as FW and during the chromatographic wettability tests. Brines Ions Na+ K+ Li+ Ca2+ Mg2+ ClHCO3SO42SCNIS TDS g/l

FW mM 997 5 0 29 8 1066 9 0 0 1.112 62.83

SW0T mM 0.46 0.01 0 0.013 0.045 0.583 0.002 0 0 0.643 33.39

SW½T mM 0.427 0.022 0.012 0.013 0.045 0.538 0.002 0.012 0.012 0.644 33.39

Crude Oil A crude oil was diluted with heptane in a volume ratio of 60/40, respectively, centrifuged and filtered through a 5µm Millipore filter. This base oil had an acid number (AN) of 1.8 mgKOH/g and a base number (BN) of 0.74 mgKOH/g. Silica gel was added to the base oil and surface active components were removed, resulting in an oil with an AN and BN of ~0 and 0.03 mgKOH/g, respectively. By mixing base crude oil (high AN) and crude oil without surface active compounds (low AN), an Oil A with AN of 0.34 mgKOH/g and BN 0.24


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mgKOH/g was formed. No precipitation of asphaltenes was observed during storage. Oil properties are reported in Table 3. Table 3. Chemical and Physical properties of the crude oil used. Crude oil Oil A

AN (mgKOH/g) 0.34±0.01

BN (mgKOH/g) 0.24±0.01

Viscosity (cP) 25 oC 3.25

Density (g/cm3) 25 oC 0.808

Analyses of polar components in oil samples The Acid Number (AN) and Base Number (BN) of the crude oil samples were analysed by potentiometric titration. The methods used are modified versions of ASTM 664 and ASTM 2898.10

Establishing initial water saturation Initial water saturation (Swi) of 10% with FW was established using the desiccator technique. 11 After the desired water saturation was obtained, the core was equilibrated in a closed container for minimum 3 days to secure an even distribution inside the core.

Oil injection and dynamic adsorption of acidic polar components The core with Swi = 0.1 was mounted in a Hassler core holder with a confining pressure of 25 bar and with a back pressure of 7 bar. The core was flooded at 50 °C with Oil A in one direction at a rate of 0.1 ml/min (4 PV/D) for 15 PV. Effluent oil samples were collected and analysed for AN.

Core aging The core saturated with Oil A was wrapped in Teflon tape, placed on marble balls in a closed aging cell surrounded by the same crude oil. The Teflon wrapping is used to avoid unrepresentative adsorption of active polar components on the outer core surface, which could prevent spontaneous imbibition.4 The core was aged for 2 weeks at 50 °C.

Wettability by spontaneous imbibition (SI) tests Core wettability of oil saturated cores with Swi = 0.1 was tested by spontaneous imbibition (SI) tests using an Amott cell. For cores saturated with Oil A containing polar components, the core was also spontaneously imbibed with FW, to avoid any possible chemical wettability alteration. The cumulative produced oil was monitored versus time until the recovery plateau had been reached.

Chromatographic wettability test Chromatographic wettability tests9 were performed in a Hassler core holder at ambient temperature with a confining pressure of 25 bar and with a back pressure of 7 bar. The chalk core was successively flooded with SW0T to obtain residual oil saturation, Sorw, then flooding 5 ACS Paragon Plus Environment

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followed by SW½T, containing tracer, SCN-, and sulphate, SO42-. Effluent brine samples were collected and analysed. The separation of sulphate and a non-adsorbing tracer is taking place at the water-wet surface, and the area between the two elution curves is proportional to the water-wet surface area in the core. Reproducibility of the experiment is within 5 %.9 A completely water-wet core was used as a reference core.

Ion analyses Chemical ion analyses of effluent brine samples were performed on an Dionex IC 3000. Ion concentrations were calculated based on the External Standard method.

Mild core cleaning A mild core cleaning was performed to remove the residual oil, but not the oil components adsorbed on the chalk surface. The first step of the procedure is a miscible fluid displacement using kerosene. When the core is clean and the effluent is clear or consistent in colour, the second step of the procedure is to displace the kerosene with n-heptane. As the final step, the core was flooded with DI water to displace heptane and remove easily dissolvable salts. Eventually water and remaining heptane were evaporated in a standard heating chamber at 90°C until constant weight.

Results and discussion In this experimental work, the adsorption of acidic polar components in the crude oil on outcrop chalk pore surface have been monitored. In addition, the effect of dynamic acid adsorption and static core aging on chalk surface wettability has been determined.

Initial adsorption of acidic crude oil components on a water-wet chalk core The initially water-wet chalk core P1 with Swi=0.1 was flooded at 50 °C in one direction using Oil A with AN=0.34 mgKOH/g. Effluent oil samples were collected and the AN analysed. The results from the first crude oil flooding, test P1:R1, are presented in Fig. 1.


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Fig.1. Adsorption of acidic crude oil components onto the water-wet chalk surface in core P1 during the first restoration, R1. The core with Swi =0.1 was flooded at 50 °C with Oil A (AN = 0.34 mgKOH/g) in one direction at a rate of 4 PV/D, totally 15 PV. The AN in the effluent samples were analysed and plotted against PV injected. Total acid adsorption was calculated to ANads = 1.14.

The AN in the first fractions of eluted crude oil from the core was very low, confirming instant adsorption of acidic material onto the water-wet chalk surface. The AN in the effluent increased gradually as the injected volume of crude oil increased, and a dynamic equilibrium was achieved after 10 PVs injected, reaching an effluent AN equal to the initial AN in crude oil A, ANi=0.34mgKOH/g. The area (ANads) between the adsorption curve and the equilibrium value is a quantitative measure of the amount of acidic functional groups adsorbed onto the chalk surface. The area is calculated by numerical integration:

2

PVn is the number of PVs injected to reach ANi in the eluted crude oil. PVx and PVx+1 are injected pore volumes in integration step x and x+1; ANx and ANx+1 are the values of AN in the eluted oil after injecting the pore volumes PVx and PVx+1. For the core P1:R1, ANads = 1.14. After the crude oil flooding the core P1:R1 was transferred from the core holder and placed in an Amott cell. Spontaneous imbibition was performed with FW at ambient temperature and the crude oil recovery is presented in Fig. 2.


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Fig. 2. Spontaneous imbibition of core P1:R1 at ambient temperature using FW as imbibing brine. Core P1:R1 had a Swi = 0.10 and was flooded 15 PV with Oil A.

The imbibing brine used was FW, the same as initially used as formation water inside the core. This was done to ensure that any chemical differences between the formation water and the imbibing fluid caused any wettability alteration inside the core during the SI experiment. The resulting low imbibition with ultimate recovery 2 %OOIP after 3 days confirmed a mixed-wet chalk core. For comparison, spontaneous imbibition in a completely water-wet SK chalk core, reference core P8, is shown in Fig.3. The water wet core P8 reached the recovery plateau after only 30 minutes with a ultimate recovery of 75 %OOIP. By comparing the SI results for cores P1 and P8, it is clear that core P1 behaved mixed-wet after having been exposed to crude oil.

Fig. 3. Spontaneous imbibition experiment on a completely water-wet SK chalk core P8. The core with Swi= 0.1 was saturated with heptane. The core was spontaneously imbibed with DI water at ambient temperature. The oil recovery in %OOIP is presented vs. imbibition time


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Core P1:R1 was then again mounted in the Hassler core holder and flooded at room temperature to Sor with SW0T brine. A chromatographic wettability test was performed using SW½T brine to investigate the fraction of water-wet area inside the core at this stage. The results are shown in Fig. 4.

Fig. 4. Chromatographic wettability tests on core P1:R1, initially with Swi = 0.1 and flooded 15 PV with Oil A. The core was flooded to Sor prior to the test. The chromatographic separation between the tracer and sulphate curves was calculated to Aw = 0.176.

From Fig. 4 the area between the tracer and sulphate curves was determined to be 0.176. For comparison, a chromatographic wettability test was performed on the completely water-wet reference chalk core, P8, Fig. 5.

Fig. 5. Chromatographic wettability test performed at ambient temperature on a completely water-wet SK chalk core P8. The core was successively flooded with SW0T- SW½T at a rate of 0.2 ml/min. Effluent brine samples were collected and the concentration of SCNand SO42- analysed. Separation area between tracer and sulphate curve was calculated to Aww=0.256


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For the completely water wet reference core P8, the area between the tracer and sulphate curves was determined to be Aww=0.256. The water-wet fraction for core P1:R1 was thus calculated to be WI = (0.176/0.256) = 0.70. According to the method explained in more details in the work by Strand et al.9 a water-wet fraction of WI = 0.70 corresponds to a mixed –wet system. To summarize, both dynamic adsorption monitoring, spontaneous imbibition tests and the chromatographic wettability test, Figs. 1, 2 and 4, showed that adsorption of acidic crude oil components had taken place, with the result that the initially water-wet core had now become more mixed-wet.

Adsorption of acidic crude oil components on a mixed-wet chalk core The mixed-wet core P1 was then mildly cleaned with Kerosene, heptane and DI water according to the procedure described in the experimental section. The purpose of the mild cleaning was to remove the oil phase but to leave the adsorbed oil components on the chalk surface.5 After the cleaning process, another dynamic adsorption test was performed by flooding crude oil through the chalk core at 50 °C, P1:R2. Initial water saturation of Swi=0.10 had first been established in the same way as before by the desiccator method. The results from the second oil flooding test, P1:R2 test are presented in Fig. 6

Fig.6. Comparing adsorption of acidic crude oil components in core P1:R2 and core P1:R1. The cores with Swi = 0.1 were flooded at 50 °C with Oil A (AN = 0.34 mgKOH/g) in one direction at a rate of 4 PV/D, totally 15 PV. The AN in effluent samples were analysed and plotted against PV injected. Total acid adsorption in P1:R2 was calculated to ANads =0.65.


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The first oil fractions eluted from the core P1:R2 showed higher AN values compared to those in the P1:R1 test. The eluted AN reached the initial crude oil value ANi = 0.34 mgKOH/g at an earlier time, suggesting that the dynamic equilibrium, was reached much faster, after 5 PV injected. From the data in Fig. 6 the area above the curve in test P1:R2 was determined to ANads =0.65. Thus, the adsorption of acidic polar components had been drastically reduced in P1:R2, from ANads = 1.14 to ANads =0.65, which confirms that the mild core cleaning removed only a small part of the initially adsorbed acidic organic components. The wetting inside the core P1:R2 after the second adsorption test had taken place was tested by performing a spontaneous imbibition test with FW at ambient temperature, Fig. 7.

Fig. 7. Spontaneous imbition of FW at ambient conditions of core P1:R2. The core with Swi = 0.10 was flooded with 15 PV of Oil A. The results are compared to those of P1:R1.

Spontaneous imbibition of core P1:R2 with FW as imbibing fluid did not result in any crude oil recovery, which is different from core P1:R1. The fact that the recovery was lower in P1:R2 compared to P1:R1 indicates that P1:R2 has less water-wet conditions than P1:R1. This is not unexpected, as core P1:R2 has been exposed to a total of 30 PV of Oil A during both restorations, while P1:R1 has only been exposed to half that amount of oil. After the spontaneous imbibition test the core was flooded to Sor by SW0T and a chromatographic wettability test was performed to determine the water-wet are inside the core and ultimately get an indication of wetting. The results from core P1:R2 showed a smaller area between the tracer and sulphate curves, Fig. 8. The water-wet surface area was calculated to Aw = 0.130, corresponding to WI = (0.130/0.256) = 0.51. The water-wet surface area decreased by 18 % compared to that of P1:R1.


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Fig. 8. Chromatographic wettability tests on core P1:R2. After mild core cleaning, the core with Swi = 0.1 was exposed to an extra 15 PV of Oil A. The chromatographic test at Sor gave a water-wet surface area of Aw = 0.130. The results from P1:R1, Aw = 0.176, are included for comparison. It is clear from the results in Fig. 6 that the core has a certain acid adsorption capacity, which was reached much faster when the core already contained adsorbed acidic material onto the surface, having a mixed wetting initially. Some of the adsorbed acidic crude oil components from P1:R1 were removed during the mild cleaning process, but new acidic material was quickly adsorbed in the second adsorption test. From the results in the spontaneous imbibition test in Fig. 7 and in the chromatographic wettability test in Fig. 8, the core became somewhat less water-wet after the second adsorption test, P1:R2. This indicated that the core wettability was dependent on the volume of crude oil the core has exposed to, and not only to an apparent dynamic adsorption equilibrium ANads being reached, which was the case in both core restorations.

Effect of core aging on wettability The wetting properties of core P1 were established by flooding crude oil at a rate of 4 PV/D at Swi in one direction at 50 °C until a dynamic equilibrium in the AN of the eluted crude was reached. As expected, the core became less water-wet in the second restoration after mild cleaning.5 No long-term core aging was performed in the core restoration. The question is then if a chemical equilibrium between the adsorbed acidic polar components on the rock surface and those present in the crude oil, has really been established during the dynamic oil flooding tests? This question was addressed in the next series of tests performed on core P2. Core P2 was subjected to the same preparation procedures and tests core P1, but in addition, core P2 was aged in crude oil for 2 weeks at 50 °C after the dynamic adsorption tests by crude oil flooding. By comparing the results obtained from an aged core versus a non-aged core any possible aging effects on the wetting conditions should be detectable. Between the core restorations, core P2 was mildly cleaned. 12 ACS Paragon Plus Environment

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The AN of the eluted crude oil from the first adsorption test P2:R1 showed similar values as those of test P1:R1, confirming good reproducibility of the analysis, Fig. 9 and Fig. 1.

Fig. 9 Adsorption of acidic polar components onto chalk core P2. First restoration P2:R1 with ANads = 1.12, and 2nd restoration P2:R2 with ANads = 0.45 are included. The core with Swi = 0.10 was flooded 15 PV with Oil A and aged for 2 weeks at 50 °C in eached restoration. In between the 1st and 2nd core restoration the core was mildly cleaned.

The calculated area related to adsorption of acidic components in test P2:R1 was ANads = 1.12 compared to ANads = 1.14 for the P1:R1 test, which shows very good reproducibility in these adsorption tests. After each core restorations with Oil A, core P2 was aged in the same crude oil at 50 °C for 2 weeks. After aging, spontaneous imbibition tests at 50 °C were performed using FW as imbibing brine. The oil recovery results for test P2:R1 and P2:R2 are shown in Fig. 10.

Fig. 10. Spontaneous imbibition tests performed at 50 °C on core P2. The core with Swi = 0.10 were flooded 15 PV with Oil A and aged for 2 weeks at 50 °C. In between the first and second restoration the core was mildly cleaned. FW was used as imbibing brine.


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Very low imbibition with a recovery plateau of 6 and 4 %OOIP after 7 and 5 days, were obtained from cores P2:R1 and P2:R2, respectively, indicating mixed-wet conditions in both cores. It is not easy to compare the results from the aged core with those of the non-aged cores, due to the spontaneous imbibition temperature being different in the two cases. The small oil recovery observed is partly due to thermal expansion of fluids from the rise in temperature. It is also known from previous experience that spontaneous imbibition is improved by a rise in temperature.8 However, the results in Fig. 10 indicate that core P2:R2 that has seen much more oil, behaves somewhat less water-wet. After the SI tests, core P2 was flooded to Sor using SW0T brine, and chromatographic wettability tests were performed in a Hassler core holder, to determine the water-wet area and the wettability inside the core. The results are presented in Fig. 11. The water-wet surface area was calculated from the data in Fig. 11, to Aw= 0.12 after the first restoration and to Aw = 0.08 after the second restoration. The corresponding wettability indices were WI = (0.12/0.256) = 0.47 after the first restoration and WI = (0.08/0.256) = 0.31 after the second restoration. These data confirm the results from the spontaneous imbibition test, that the second restoration, where the core has seen a double amount of oil, render the core less water-wet. In addition, by comparing wetting indices for the non-aged and aged cores, the cores have become slightly less water-wet by aging, although it must be emphasized that aging is not required to make a chalk core mixed-wet.

Fig. 11. Chromatographic wettability tests performed on core P2. The core with Swi = 0.10 was flooded with 15 PV with Oil A and aged for 2 weeks at 50 °C. In between the first and second restoration the core was mildly cleaned.

Discussion Adsorption of acidic, polar crude oil components onto outcrop chalk has been investigated after one or two crude oil core flooding restoration, with and without aging. All experimental results are summarized in Table 4. 14 ACS Paragon Plus Environment

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Table 4. Experimental results from adsorption tests, spontaneous imbibition tests and chromatographic wettability test performed on cores P1 and P2, after the first and second restoration, R1 and R2, and relevant data from a water-wet reference core P8

Non-aged core Total crude oil injected, PV ANads

Aged core

Water-wet core

P1:R1

P1:R2

P2:R1

P2:R2

P8

15

30

15

30

0

1.14

0.65

1.12

0.45

-

40

-

∆ANads, % readsorbed

57 3

0

6*

4*

75

Aw

0.176

0.130

0.120

0.080

0.256

WI

0.69

0.51

0.47

0.31

1

SI, %OOIP

*

SI performed at 50 °C. Due to thermal expansion, an immediate recovery of 3 % OOIP was expected.

The water-wet surface area of P2:R1 corresponded to a water-wet fraction of WI=0.47. Thus, by aging the core for 2 weeks at 50 °C, the water-wet fraction decreased from to WI = 0.70 for the non-aged core P1:R1, down to WI = 0.47 for the aged core P2:R1. The experimental results confirm that a chemical equilibrium between the acidic organic material in the oil and adsorbed material onto the chalk surface had not been achieved in the dynamic oil flooding process. The second chromatographic test for the aged core P2:R2 gave a water wet fraction WI = 0.31, which was significantly lower than that of the non-aged core P1:R2, WI = 0.51. These results confirm that extra volumes of oil flooded increased the adsorption of polar components. During the core aging, a redistribution of polar components at the rock surface and in the pores reduced the water-wet fraction of the chalk surface. After the first core restoration and dynamic adsorption test giving ANads = 1.12 and the performed core tests on P2:R1, the same core P2 was mildly cleaned and restored with Swi=0.10. A second dynamic adsorption of acidic polar components onto the rock surface was performed by flooding the core by 15 PV of crude oil A, the test termed P2:R2. The adsorption of acidic polar components was determined to be ANads = 0.45, which showed that when the core was aged as in this case, 60 % of the adsorbed material remained on the rock surface after mild core cleaning. This was significantly higher than the corresponding number 43 % for the core that had not been aged, P1. After core aging for 2 weeks at 50 °C the spontaneous imbibtion test P2:R2, showed an oil recovery of only 4 %OOIP at 50 °C, somewhat lower than that observed for P2:R1 with 6 15 ACS Paragon Plus Environment

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%OOIP, indicating a less water-wet condition after the second restoration. The same observation was made for core P1 with recoveries of 3 and 0 %OOIP. However, with such low recoveries it is impossible to conclude the degree of mixed-wet conditions of the individual cores only based on SI tests. Compared to the high SI recovery of 75 %OOIP for the completely water wet core P8, all tested cores behaved mixed-wet. FW was used as imbibing fluid to avoid any chemical induced wettability alteration during the SI tests. After the SI tests, the cores were flooded to Sor and chromatographic wettability tests were performed. The chromatographic test is much more sensitive at mixed-wet conditions. In the non-aged core P1, the fraction of water-wet surface area was reduced from WI = 0.69 to WI = 0.51, confirming that continuous oil flooding will reduce the water wetness of the core. The same was observed for the aged core P2, with WI = 0.47 and WI = 0.31. The effect of core aging is easily seen when comparing the results between P1:R1 and P2:R1. The fraction of water wet surface area was reduced from WI = 0.69 to WI = 0.47, confirming that during core aging, a redistribution of acidic components at the rock surface and in the pores are taking place, resulting in a less water-wet rock surface.

Conclusions The adsorption of acidic polar components onto outcrop chalk was monitored during dynamic flooding of 15 PV crude oil at 50 °C into chalk cores with Swi = 0.10. The wetting conditions inside the cores were tested by spontaneous imbibition and chromatographically, in aged and non-aged cores. The results obtained from this study are summarised as follows: 1. Acidic polar components in the crude oil adsorbed onto the rock surface immediately upon contact, and resulted in a mixed-wet rock surface, even without core aging. 2. The adsorption of polar components onto the rock surface increased with increasing volumes of oil injected, resulting in continued reduction in water wetness. 3. When starting out with a completely water-wet chalk core at Swi = 0.10, it appeared difficult to obtain a thermodynamic equilibrium in the wetting conditions even after 2 weeks of core aging. Even after aging, it was possible to reduce water wetness further by introducing another volume of oil. 4. Mild core cleaning preserved a large amount of the initially adsorbed acidic polar components, both in aged and non-aged cores. However, less acidic material was removed after core aging. 5. For better restoration of reservoir cores, they should be mildly cleaned to preserve initially adsorbed acidic polar components on the pore surface, and then only a limited number of PV with crude oil should be injected to compensate for the polar components removed in the mild core cleaning process.


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Acknowledgements BP is acknowledged for financial support and for the permission to publish this work.

Nomenclature AN BN ASTM D L Φ Swr PV Swi Sorw kro krw OOIP Aw Aww FW TDS SW0T SW½T C/Co WI ANads:

Acid Number Base Number American Society for Testing and Materials Core Diameter Core length Core Porosity Residual water saturation Pore volume Initial water saturation Residual oil saturation after waterflood Relative permeability to oil Relative permeability to water Original oil in place Area between the thiocyanate and sulphate curve of a sample Area between the thiocyanate and sulphate curve of a water-wet sample Valhall formation water, containing no sulphate Total Dissolved Salt Sea water without thiocyanate tracer and sulphate Seawater that contains thiocyanate tracer and sulphate Relative concentration of ion in effluent fractions Water-wet fraction of chalk core Area between the adsorbed curve and the equilibrium value

References (1) Austad, T.; Strand, S.; Puntervold, T.; Ravari, R. R. In New method to clean carbonate reservoir cores by seawater, Paper SCA2008-15 presented at the International Symposium of the Society of Core Analysts, Abu Dhabi, U.A.E., 29 Oct - 2 Nov, 2008. (2) Shariatpanahi, S. F.; Strand, S.; Austad, T.; Aksulu, H., Petroleum Science and Technology 2012, 30 (1-9). (3) Masalmeh, S. K.; Jing, X. D. In Improved characterisation and modelling of carbonate reservoirs for predicting waterflood performance, Paper IPTC 11722 presented at the International Petroleum Technology Conference, Dubai U.A.E., 4-6 December, 2007. (4) Standnes, D. C.; Austad, T., J. Pet. Sci. Eng. 2000, 28 (3), 111-121. (5) Hopkins, P.; Puntervold, T.; Strand, S. In Preserving initial core wettability during core restoration of carbonate cores, The International Symposium of the Society of Core Analysts, St. John's Newfoundland and Labrador, Canada, 16-21 Aug, 2015.


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(6) Zahid, A.; Stenby, E. H.; Shapiro, A. A. In Improved oil recovery in chalk: Wettability alteration or something else?, SPE EUROPEC/EAGE Annual Conference and Exhibition, Barcelona, Spain, 14-17 June, 2010. (7) Frykman, P., Marine and Petroleum Geology 2001, 18 (10), 1041-1062. (8) Puntervold, T.; Strand, S.; Austad, T., Energy Fuels 2007, 21 (6), 3425-3430. (9) Strand, S.; Standnes, D. C.; Austad, T., J. Pet. Sci. Eng. 2006, 52, 187-197. (10) Fan, T.; Buckley, J., SPE Journal 2007, December. http://dx.doi.org/10.2118/99884pa. (11) Springer, N.; Korsbech, U.; Aage, H. K. In Resistivity index measurement without the porous plate: A desaturation technique based on evaporation produces uniform water saturation profiles and more reliable results for tight North Sea chalk, Paper presented at the International Symposium of the Society of Core Analysts Pau, France, 21-24 Sept, 2003. http://dx.doi.org/10.2118/78059-pa.


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Adsorption of Acidic Crude Oil Components onto Outcrop Chalk at

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