Amott Index Research Articles

Relationship Between Residual Saturations and Wettability Using Pore-Network Modeling

Summary The relationship between residual saturation and wettability is critical for modeling multiphase processes like enhanced oil recovery, CO2 sequestration, and geologic storage of hydrogen. The wetting state of a core is often quantified through Amott indices, which are estimated from the ratio of the saturation fraction that flows spontaneously to the total saturation change that occurs due to spontaneous flow and forced injection. Observations from traditional coreflooding experiments show a minimum in the trends of residual oil saturation (Sor) around mixed-wet conditions. Amott indices, however, provide an average measure of wettability because of their intrinsic dependence on a variety of factors such as the initial oil saturation, aging conditions, rock heterogeneity, etc. Thus, the use of Amott indices could potentially cloud the observed trends of residual saturation with wettability. Using pore-network modeling (PNM), we show that Sor varies monotonically with the contact angle, which is a direct measure of wettability. That is, for fixed initial oil saturation, the Sor decreases monotonically as the reservoir becomes more water-wet (decreasing contact angle). Further, the calculation of Amott indices for the PNM data sets shows that a plot of the Sor vs. Amott indices also shows this monotonic trend, but only if the initial oil saturation is kept fixed. Thus, for the cases presented here, we show that there is no minimum residual saturation at mixed-wet conditions as wettability changes. In this research, we employ a numerical approach to quantify trends of Sor against the traditional definition of wettability. Through the analysis of our numerical work and literature experiments, we find that under isolated conditions (constant initial saturation), linear trends exist between Sor and wettability. This can have important implications for low salinity waterflooding, water-alternating-gas enhanced oil recovery, or CO2 sequestration where the effects of wettability are critical to understand phase trapping.

Influence of rock permeability and surface conditioning on carbonate wettability: A link between contact angle and Amott-index

The wettability of crude oil/brine/rock system is of great importance in determining oil recovery during water displacement processes. The wetting behavior of rocks has traditionally been assessed via a range of experimental techniques such as the Amott tests and contact angle measurements. While the Amott wettability is known to be influenced by a range of factors, still the impact of rock permeability, rocks surface/saturation condition and initial water saturation remains unclear. Furthermore, a link between Amott wettability and contact angle is missing which is vital to characterize macroscopic vs. core scale wettability. Therefore, in this study, we investigated the effect of permeability, rocks surface/saturation condition and initial water saturation on Amott tests and contact angle measurements using Indiana limestone. We further attempt to experimentally explore the relationship between the contact angle and Amott-Harvey wettability index (IAH) for different rocks. We demonstrated that, in addition to surface texture (roughness) and surface chemistry (heterogeneity), rock surface wetting behavior depends also on the rock permeability and surface/saturation condition (Dry,Sw=1,Sor,SwirrandSo=1). Moreover, a comparison of the observed values for the Amott and contact angles, showed that only when the rock has moderate to high permeability (up to 15.17 mD) will the Amott index corresponds to the wetting state estimated using contact angle method. The influence of several factors on wettability via IAH and contact angle is evident. While permeability demonstrated a positive correlation with wettability, Sor exhibited a negative correlation. For water-wet rocks, contact angle showed weak positive correlation with IAH, while negative correlations were observed in the case of intermediate- and oil-wet rocks. In addition, exceptions were found in the correlations; unlike the IAH, contact angle is weakly correlated with both Sor and Swi obtained from the imbibition experiments. Lastly, spontaneous imbibition time becomes slower and tends to underestimate IAH as rock permeability decreases. The findings from this study will thus broaden the understanding of the interplay of different petrophysical parameters and the relationship between different wetting indices.

Simultaneous Assessment of Wettability and Water Saturation Through Integration of 2D NMR and Electrical Resistivity Measurements

Summary Nuclear magnetic resonance (NMR) transverse relaxation (T2) measurements are sensitive to fluid saturations and wettability of the rocks. However, quantifying wettability index solely from NMR T2 models relies on accurate estimates of water saturation. It has been shown that integrating resistivity measurements and NMR T2 distributions enables simultaneous assessment of wettability and water saturation. Nevertheless, there still exist significant uncertainties in this approach in the presence of multiple types of fluids with overlapping transverse relaxation times or multimodal pore-size distribution. Thus, the objectives of this paper are (a) to introduce a new multiphysics workflow integrating 2D NMR with resistivity measurements to simultaneously quantify wettability index and water/hydrocarbon saturation and (b) to verify the reliability of the introduced workflow with core measurements in different rock types. The workflow starts by using 2D diffusivity-transverse relaxation (D-T2) or longitudinal-transverse relaxation (T1-T2) measurements to estimate fluid saturations. We use a nonlinear inversion algorithm to fit a multimodal Gaussian distribution to the 2D NMR measurements. We then calculate water and hydrocarbon saturations using the fluid volumes estimated from the multimodal Gaussian distribution. This estimate of water/hydrocarbon saturation is an input to our new physics-based resistivity model that explicitly incorporates the influence of wettability. The inputs to the resistivity model include water saturation, resistivity index, and pore-geometry-related parameters. In the core-scale verification step, we compare the results of wettability and fluid saturations obtained from the new workflow with gravimetrically assessed water saturation and Amott index measurements on core sample. We successfully verified the reliability of the new workflow with experimental measurements. Estimated water saturation using the introduced workflow resulted in an average relative error of less than 7% compared to the gravimetrically assessed water saturations. Wettability indices obtained from the workflow were in agreement with those estimated using Amott indices. The average absolute error between the estimated wettability indices and the Amott indices was 0.27. In conclusion, results demonstrated that integration of 2D NMR and electrical resistivity measurements enables reliable and simultaneous assessment of wettability and water saturation in different rock types. The method introduced in this paper is promising for reliable and real-time wettability assessment, both in the laboratory and in-situ condition. It provides a physics-based and robust method to accurately and simultaneously estimate water/hydrocarbon saturation and wettability in hydrocarbon-bearing rocks.

Qualitative assessment of improved oil recovery and wettability alteration by low salinity water injection for heterogeneous carbonates

This study aims to evaluate the qualitative potential for low salinity water injection (LSWI) to alter the wettability and increase oil production in heterogeneous oil-wet coquina cores (one of the facies of Pre-Salt reservoirs) in relevant conditions of brine salinity, temperature, and initial wettability. We also aimed to verify the impact of micro-porosity fraction on oil recovery. Finally, we verified whether the presence of micro-dispersion in the oil phase upon contact with low salinity would have a positive correlation with improved oil recovery due to low salinity water injection.To achieve these objectives, we performed zeta-potential experiments to evaluate the charges at the oil-brine and brine-rock interfaces that affect rock wetting state and contact tests to test for the presence of micro-dispersions in the oil phase and potential for LSWI. A series of spontaneous imbibition and coreflood experiments were performed to calculate the Amott index and evaluate wettability of coquinas in core-scale as a function of brine salinity. Tertiary and secondary low salinity waterfloods were carried out to investigate whether a diluted desulfated seawater would increase oil production in coquina cores. The effect of predominance of macro-, meso-, and micro-porosity on secondary low salinity waterflood was also evaluated. Our results have shown that heterogeneity had a greater impact on recovery factor compared to brine salinity. Oil recovery for low salinity brine for a core with predominance of macro-pores was smaller than for cores with higher fraction of micro-pores flooded with FW and DSW. Low-salinity oil recovery was also smaller than high-salinity was for core with microporosity but with presence of dead-end pores. Secondary injection of low-salinity using the same core with large fraction of micro-porosity showed that it accelerated oil production compared to high-salinity brine. We have also observed that LSWI resulted in increased oil recovery in coquinas both in tertiary mode (average 10%) compared to FW/DSW and secondary mode using the same core (18% compared to FW) due to wettability alteration. This result was supported by spontaneous imbibition as well as zeta-potential results. The contact test between crude oil and low salinity brine resulted in a micro-dispersion ratio of 11.7, showing that a positive oil is likely to result in improved oil recovery due to low salinity injection. Despite the increased oil recovery seen during the tests, the results showed that oil production in tertiary mode was significantly delayed (after 4 PV), likely due to adverse oil/water viscosity ratio and water dispersion due to mixing between low- and high-salinity brines. We observed that for the shorter more oil-wet core significant oil production was measured during bump flow with both high-salinity and low-salinity brines, due to capillary end effects. This could mean that residual oil saturation was not achieved during high-salinity water injection and an overestimation of recovery factor due to low-salinity was seen.

Simultaneous assessment of wettability and water saturation using 2D NMR measurements

Nuclear Magnetic Resonance (NMR) measurements can be used for estimating porosity, fluid saturation, pore-size distribution, and sometimes wettability. However, quantitative interpretation of rock wettability can be challenging in rocks with complex pore structures in the presence of different fluid types. Conventional NMR-based wettability models are applicable only for rocks with unimodal pore-size distributions. In this paper, we develop a new workflow for simultaneous assessment of fluid saturation and wettability in partially-saturated mixed-wet rock samples using 2D NMR measurements. We verify the reliability of this new workflow in three rock types, including unimodal and multi-modal pore-size distributions.The main inputs to the introduced workflow include the transverse relaxivity (T2) and Diffusivity-T2 (D-T2) or longitudinal-T2 (T1-T2) NMR measurements of the partially-saturated mixed-wet rock samples. Other input parameters include the bulk relaxivities of the saturating fluids and the NMR responses of fully water-saturated water-wet and fully oil-saturated oil-wet samples of the same rock type as the partially-saturated mixed-wet rock. In the verification step, we vary the fluid saturation by injecting brine, decane, or diesel into the rock sample using a core-flood setup. Then, we obtain NMR measurements at different fluid saturations to estimate the water/hydrocarbon saturation and wettability. Results demonstrated that the NMR-based wettability index has an average absolute difference of 0.18 when compared to the Amott Index, and the NMR-based water saturation estimates are within 18% average relative error of the gravimetric-estimates for the brine and diesel saturated rock samples.

Joint Interpretation of Electrical Resistivity andT2 NMR Measurements To Estimate Wettability and Water Saturation

SummaryThe wettability of rocks can be assessed from interpretation of borehole geophysical measurements, such as electrical resistivity and nuclear magnetic resonance (NMR). These wettability models often require additional inputs (e.g., water saturation, porosity, and pore-geometry- related parameters), which are difficult to obtain independently. Consequently, a multiphysics workflow that integrates resistivity and NMR measurements can reduce the number of input parameters, resulting in a more accurate and robust wettability assessment. The objectives of this paper are to introduce a new workflow for joint interpretation of resistivity and NMR measurements to simultaneously estimate wettability and water saturation, and to verify the reliability of wettability and water-saturation estimates by comparison with experimentally measured contact angles, Amott Indices, and gravimetrically assessed water saturation.This new workflow for assessing wettability and water saturation combines nonlinear resistivity- and NMR-based rock physics models. The inputs to the resistivity-based wettability model include the resistivity of the rock–fluid system and brine, porosity, and pore-geometry-related parameters. The NMR-based wettability model requires the transverse (T2) response of the rock–fluid system, saturating fluids, and water-wet water-saturated and hydrocarbon-wet hydrocarbon-saturated rocks. To verify the reliability of the new integrated workflow, we perform resistivity and NMR measurements on core samples from different rock types, covering a range of wettability and water-saturation levels. These measurements are inputs to the nonlinear models, which are simultaneously solved to estimate wettability and water saturation for each core sample. We verify the reliability of wettability estimates by comparison with the Amott Index (IA) and contact-angle measurements, and the water-saturation estimates by comparison with the gravimetric water-saturation estimates.We successfully verified the reliability of the new method for this joint interpretation of resistivity and NMR measurements to estimate wettability and water saturation of limestone and sandstone core samples. For water-saturation levels ranging from irreducible water saturation to residual oil saturation, we observed an average relative error of 11% between the gravimetrically assessed and the model-estimated water saturation. It is challenging to estimate water saturation in rocks with multimodal pore-size distribution uniquely from the interpretation of NMR measurements. One contribution of the introduced workflow is improving the accuracy of water-saturation estimates (in addition to wettability) in rocks with complex pore structure and wettability states. For the wettability ranging from hydrocarbon-wet to water-wet, we observed an average absolute difference of 0.15 between the experimentally measured IA and the model-estimated wettability. These model-estimated wettability values were also consistent with the contact-angle measurements. It should be noted that the new workflow relies on physically meaningful and measurable parameters, which minimizes calibration efforts. Furthermore, the multiphysics workflow eliminates the nonuniqueness associated with wettability and water-saturation estimates obtained from independent interpretation of NMR and resistivity measurements.

Amino Acid as a Novel Wettability Modifier for Enhanced Waterflooding in Carbonate Reservoirs

SummaryReservoir wettability plays an important role in waterflooding, especially in fractured carbonate reservoirs since oil recovery from the rock matrix is inefficient because of their mixed wettability. This paper presents the first investigation of amino acids as wettability modifiers that increase waterflooding oil recovery in carbonate reservoirs.All experiments used a heavy-oil sample taken from a carbonate reservoir. Two amino acids were tested, glycine and β-alanine. Contact angle experiments with oil-aged calcite were conducted at room temperature with deionized (DI) water, and then at 368 K with three saline solutions: 243 571-mg/L salinity formation brine (FB), 68 975-mg/L salinity injection brine 1 (IB1), and 6898-mg/L salinity injection brine 2 (IB2). IB2 was made by dilution of IB1.The contact angle experiment with 5-wt% glycine solution in FB (FB-Gly5) resulted in an average contact angle of 50°, in comparison to 130° with FB, at 368 K. Some of the oil droplets were completely detached from the calcite surface within a few days. In contrast, the β-alanine solutions were not effective in wettability alteration of oil-aged calcite with the brines tested at 368 K.Glycine was further studied in spontaneous and forced imbibition experiments with oil-aged Indiana limestone cores at 368 K using IB2 and three solutions of 5 wt% glycine in FB, IB1, and IB2 (FB-Gly5, IB1-Gly5, and IB2-Gly5). The oil recovery factors from the imbibition experiments gave the Amott index to water as follows: 0.65 for FB-Gly5, 0.59 for IB1-Gly5, 0.61 for IB2-Gly5, and 0.33 for IB2. This indicates a clear, positive impact of glycine on wettability alteration of the Indiana limestone cores tested.Two possible mechanisms were explained for glycine to enhance the spontaneous imbibition in oil-wet carbonate rocks. The primary mechanism is that the glycine solution weakens the interaction between polar oil components and positively charged rock surfaces when the solution pH is between glycine's isoelectric point (pI) and the surface's point of zero charge (pzc). The secondary mechanism is that the addition of glycine tends to decrease the solution pH slightly, which in turn changes the carbonate wettability in brines to a less oil-wet state.The amino acids tested in this research are nontoxic and commercially available at relatively low cost. The results suggest a new method of enhancing waterflooding, for which the novel mechanism of wettability alteration involves the interplay between amino acid pI, solution's pH, and rock's pzc.

Ketone solvent as a wettability modifier for improved oil recovery from oil-wet porous media

The main objective of this research is to investigate a novel class of oxygenated solvents that can enhance the oil recovery from oil-wet rocks by multiple mechanisms, such as wettability alteration, oil-viscosity reduction, and oil swelling, in the presence of brine (connate water and/or fracturing water). The compound studied for the first time in this research is 3-pentanone (3p), a symmetric short ketone that can partition into both oil and brine at reservoir conditions. It can act as a solvent by itself, but this paper is focused on the potential mechanisms of oil recovery when an aqueous solution of 1.1 wt% 3p in reservoir brine (3pRB) is in contact with oil and oil-wet rock.Results show that the average contact angle of oil droplets on oil-aged calcite surfaces was rapidly reduced to 26° with 3pRB, in contrast to 123° with RB, without affecting the oil/brine interfacial tension. Spontaneous imbibition results show that the oil recovery factor reached 50.0% with 3pRB and 10.0% with RB at Day 3. The final recovery factor was 51.0% with 3pRB and 12.0% with RB. The subsequent forced imbibition determined the Amott index to water of 0.76 with 3pRB and 0.23 with RB, indicating a clear, positive impact of 3pRB on oil recovery by water imbibition in the cores tested. The main mechanism of oil recovery by 3pRB in this research is the wettability change as demonstrated by the contact-angle experiment.

Effect of Chlorite Clay-Mineral Dissolution on the Improved Oil Recovery From Sandstone Rocks During Diethylenetriaminepentaacetic Acid Chelating-Agent Flooding

SummarySandstone oil reservoirs consist of different clay minerals, such as kaolinite, illite, and chlorite. While these clay minerals can highly affect oil recovery from sandstone oil reservoirs, no attention has been given to investigating the effects of clay minerals during such oil recovery, and no solution has been introduced to alleviate the effects.In this study, and for the first time, the effect of chlorite clay-mineral content on the improved oil recovery (IOR) from different sandstone rock samples was investigated. A new solution was proposed to eliminate the effect of chlorite on the oil recovery from sandstone rocks. Different sandstone cores were used, such as Berea (BSS), Bandera (BND), Kentucky (KSS), and Scioto (SCS) sandstone rocks with different clay minerals. ζ-potential measurements were used to investigate the surface charge of the different clays and different sandstone rocks with different fluids. Fluids such as seawater (SW), low-salinity water (LSW), fresh water, and chelating agents were used. Diethylenetriaminepentaacetic acid (DTPA) chelating agent was introduced to mitigate the chlorite effect on oil recovery from sandstone rocks. The wettability was evaluated using contact-angle measurements and the Amott test for different solutions and different rocks in the presence of actual crude oil. Coreflooding experiments were conducted using these fluids with different sandstone rocks to identify the effect of chlorite on the oil recovery.Coreflooding experiments showed that sandstone cores with high chlorite content yielded the lowest oil recovery when SW and LSW were used. The effect of chlorite on the oil recovery from the two sandstone rocks was minimized with 3 wt% DTPA chelating agent. More oil was recovered in the case of DTPA because of the iron chelation from chlorite. ζ-potential showed that sandstone with high chlorite content has a surface charge close to zero in the case of SW and fresh water. In addition, contact-angle measurements showed that samples with high chlorite content have less water-wetness, which will reduce oil recovery. Contact-angle measurements on chlorite sheets showed that chlorite is oil-wet compared with mica at the same conditions. The addition of high-pH DTPA chelating agent sequestered the iron from the chlorite clay minerals and changed the surface charge to very high negative value, and the contact angle confirmed that the rock changed to water-wet after adding the chelating agent. The Amott index showed that adding DTPA increased the water-wetness for SCS that contains 4 wt% chlorite.

Morphological Variation and Recovery Mechanism of Residual Crude Oil by Biosurfactant from Indigenous Bacteria: Macro- and Pore-Scale Experimental Investigations.

Microbial enhanced oil recovery (MEOR) is being used more widely, and the biological contributions involved in MEOR need to be identified and quantified for the improvement of field applications. Owing to the excellent interfacial activity and the wide distribution of producing strains in oil reservoirs, lipopeptides have proved to be an essential part of the complex mechanisms in MEOR. In this study, crude lipopeptides were produced by a strain isolated from an indigenous community in an oil reservoir. It was found that crude lipopeptides can effectively reduce the IFT (interfacial tension) to 10(-1)~10(-2) mN/m under high salinity without forming stable emulsions, and the wettability of natural sandstone can be enhanced (Amott index, from 0.36 to 0.48). The results of core flooding experiments indicate that an additional 5.2% of original oil in place can be recovered with a 9.5% reduction of injection pressure. After the shut-in period, the wettability of the core, the reduction of injection pressure, and the oil recovery can be improved to 0.63, 16.2% and 9.6%, respectively. In the microscopic flooding experiments, the crude oil in membrane, cluster, and throat states contribute nearly 90% in total of the additional oil recovery, and the recovery of membranestate oil was significantly enhanced by 93.3% after shut in. Based on the results in macro and pore scale, the IFT reduction and the wettability alteration are considered primary contributors to oil recovery, while the latter was more dominant after one shut-in period.

Wettability Alteration of a Heavy Oil/Brine/Carbonate System with Temperature

The wettability of reservoir rock is a crucial factor controlling displacement efficiency and ultimate oil recovery. In this study, the wettability of carbonate reservoir rocks as a function of temperature has been studied by measuring the Amott index to water using an X-ray computed tomography (CT) scanner. The cores for the Amott test were carefully prepared and aged at reservoir conditions to achieve restoration of reservoir wettability. The reservoir cores contain dolomite and chert based on the results of Fourier transform infrared spectroscopy (FT-IR) and energy dispersive X-ray spectroscopy (EDS). The porosity, permeability, and saturation profiles were measured with a core-flooding system and an X-ray CT scanner. The wettability test was carried out at reservoir temperature (70–80 °C) and elevated temperatures (130 °C, 170 °C). The rock components were dissolved at elevated temperature (170 °C) and resulted in a slight increase of porosity and absolute permeability. Also, OOIP and Amott water inde...

The Influence of Heterogeneity, Wetting, and Viscosity Ratio on Oil Recovery From Vertically Fractured Reservoirs

Summary We use upscaling through homogenization to predict oil recovery from fractured reservoirs consisting of matrix columns, also called vertically fractured reservoirs (VFRs), for a variety of conditions. The upscaled VFR model overcomes limitations of the dual-porosity model, including the use of a shape factor. The purpose of this paper is to investigate three main physical aspects of multiphase flow in fractured reservoirs: reservoir wettability, viscosity ratio, and heterogeneity in rock/fluid properties. The main characteristic that determines reservoir behavior is the Péclet number that expresses the ratio of the average imbibition time divided by the residence time of the fluids in the fractures. The second characteristic dimensionless number is the gravity number. Upscaled VFR simulations, aimed at studying the mentioned features, add new insights. First, we discuss the results at low Péclet numbers. For only small gravity numbers, the effect of contact angle, delay time for the nonequilibrium capillary effect, the heterogeneity of the matrix-column size, and the matrix permeability can be ignored without appreciable loss of accuracy. The ultimate oil recovery for mixed-wet VFRs is approximately equal to the Amott index, and the oil production does not depend on the absolute value of the phase viscosity but on viscosity ratio. However, large gravity numbers enhance underriding, aggravated by large contact angles, longer delay times, and higher viscosity ratios. Layering can lead to an improvement or deterioration, depending on the fracture aperture and permeability distribution. At low Péclet numbers, the fractured reservoir behaves very similarly to a conventional reservoir and depends largely on the viscosity ratio and the gravity number. At high Péclet numbers, after water breakthrough, the oil recovery appears to be proportional to the cosine of the contact angle and inversely proportional to the sum of the oil and water viscosity. In addition, the mixed-wetting effect is more pronounced; there are significant influences of delay time (nonequilibrium effects), matrix permeability, matrix-column size, and the column-size distribution on oil recovery. At low gravity numbers and an effective length/thickness ratio larger than 10, the oil recovery is independent of the vertical-fracture-aperture distribution. For the same amount of injected water, the recovery at low Péclet numbers is larger than the recovery at high Péclet numbers.

Wettability estimation of low-permeability, siliceous shale using surface forces

This work evaluates shale/oil wettability and wettability alteration by solutions whose pH ranges from 3 to 12. The reservoir rocks are siliceous shale that are fractured and low permeability oil-bearing rocks. Wettability alteration is evaluated in terms of estimated thin-film stability, contact angle, and fines migration. Previously, we presented core-scale spontaneous countercurrent imbibition and forced displacement results for the crude oil/brine/rock system. The new surface forces results for stability of wetting films and contact angle compare favorably to the previously measured Amott index to water. The pH=3 and pH=12 solutions result in greater water wettability in comparison to neutral pH brine. The possibility of fines migration, that is one of the scenarios of wettability alteration, is explored. Results show that a balance of the surface forces as a function of brine chemistry explains wettability alteration of these siliceous shale samples. The trend of small contact angles for the aqueous phase for basic and alkaline solutions is consistent with the oil recovery characteristics, and fines migration does not trigger wettability alteration for this particular crude oil/brine/rock system.

Wettability alteration and oil recovery by water imbibition at elevated temperatures

This investigation adopts a new perspective on wettability alteration as a function of temperature. Colloidal (i.e., DLVO) theory and calculations are used to interpret results from laboratory-scale displacements. Water imbibition tests were conducted with 9 reservoir cores from a diatomaceous reservoir. Permeability and porosity of cores varied from 0.2 to 0.7 md and 46% to 65%, respectively. The experiments included spontaneous counter-current water imbibition followed by forced co-current water imbibition to residual oil saturation. The fluids were 34° API crude oil and synthetic formation brine. All tests were isothermal and temperatures ranged from 45 to 230 °C at pressures sufficient to maintain liquid water. The experimental results show that an increase in temperature results in: (1) a substantial increase in imbibition rate and extent of oil recovery, (2) a slight reduction in residual oil saturation, and (3) a significant shift in the Amott wettability index from intermediate and weakly water wet to strongly water wet. DLVO calculations illustrate detachment of fines from pore surfaces at high temperature. Fines detachment is a mechanism for altering wettability. Release of fines coated with oil exposes clean water-wet pore surfaces. Further calculations indicate the water–oil contact angle decreases as temperature increases indicating a systematic increase in water wettability consistent with experimental measurements of the Amott index.

In situ wettability distribution and wetting stability in outcrop chalk aged in crude oil

This paper reports an investigation of in situ wettability distribution and wetting stability of moderately water-wet and nearly neutral-wet outcrop chalk cores, aged in crude oil at elevated temperature. In this paper, in situ wettability measurements by magnetic resonance imaging (MRI) tomography are shown to give Amott indices that agree well with the standard wettability indices based on average saturations. The in situ method provides information concerning Amott index distribution radially and along the length of the core plugs. Applying multidirectional crude oil flooding during aging, uniform wettability distributions, both radially and axially, were obtained. Tests of wetting stability confirmed that stable wettability alterations for repeated waterfloods and Amott tests were established. The results showed that the core plugs should not be dried or cleaned because this will render the core plugs strongly water-wet. Stable wettability conditions were measured for cores subjected to storage in brine at 90 °C.

Studying the effect of wettability heterogeneity on the capillary pressure curves using the centrifuge technique

Wettability heterogeneity and its effect on fluid flow properties has been the subject of several papers in the past few years. This effect is usually studied by using composite cores made up of blocks of different wettability. In this work, wettability heterogeneity is created in the core by partial filling of the pore space with oil, which creates parts of different wetting in the core. The part accessed with oil will change its wettability while the rest will stay water-wet, which creates a core plug of heterogeneous wettability. The effect of heterogeneous wettability on the capillary pressure is studied in a systematic way using the centrifuge technique in combination with numerical simulation of the experimental data. The experimental procedure consists of the following steps: (1) the core plug is fully saturated with brine and subsequently, a drainage experiment is performed targeting initial oil saturation, S oi, (2) after aging, the oil is displaced by water to residual oil saturation, S or, and finally (3) oil is injected, targeting higher initial oil saturation. This procedure was repeated several times on the same plugs, each time targeting higher initial oil saturation. An interesting feature that has been observed is a discontinuity (step) in the capillary pressure curve when oil from a wettability-altered part accesses an unaltered (water-wet) part of the core. This step is believed to be due to wettability contrast between the two parts, the higher the contrast, the larger the observed step. Moreover, the size of this step allows for systematic study of the effect of aging and initial oil saturation on wettability alteration on pore scale. The results of this study show that aging a core sample at low oil saturation introduces significant wettability alteration in the pores filled with oil, while the rest of the core is not affected. This wettability alteration on the pore scale is difficult to capture by simple Amott index measurement. The results also suggest that aging time to restore wettability may decrease as oil saturation increases.

Systematic wettability alteration by aging sandstone and carbonate rock in crude oil

A reproducible method for selectively altering the wettability of outcrop chalk has been established to obtain stable wettability conditions in the range from strongly water-wet to near-neutral-wet. Aging in different oils and the response to aging in different rocks are reported. The influence of different initial water saturations on the role of wettability alterations has been evaluated. Core plugs were aged in oil, at 90°C, for different time periods in duplicate sets. Oil recovery by spontaneous room temperature imbibition, followed by a waterflood, was studied for aged cores, to obtain Amott–Harvey wettability index to water. The procedure was also performed on cores containing aged crude oil, on cores where the aged crude oil was exchanged with fresh crude oil after aging was completed, but before imbibition testing and for cores where the crude oil was exchanged with decahydronaphthalene which was then displaced by n-decane. Imbibition in water-wet cores with n-decane was used as the baseline experiment. A consistent and reproducible change in wettability, from strongly water-wet to a near-neutral-wet state, with increased aging time was observed for five different outcrop chalks. The altered wettability was stable over several flooding cycles but when the aged crude oil was exchanged by fresh crude oil or decane after aging but before imbibition, results exhibited different but consistent Amott indices. Exchanging crude oil at temperature with decalin, which in turn was exchanged with decane, was found to be the best procedure for reproducible and stable wettability alteration.

Pore-Scale Modeling of Wettability Effects and Their Influence on Oil Recovery

Summary The wettability of a crude oil/brine/rock system influences both the form of petrophysical parameters (e.g., Pc and krw/kro) and the structure and distribution of remaining oil after secondary recovery. This latter issue is of central importance for improved oil recovery since it represents the "target" oil for any IOR process. In the present study, we have developed a three-dimensional network model to derive capillary pressure curves from nonuniformly wetted (mixed and fractionally wet) systems. The model initially considers primary drainage and the aging process leading to wettability alterations. This is then followed by simulations of spontaneous water imbibition, forced water drive, spontaneous oil imbibition and forced oil drive—i.e., we consider a complete flooding sequence characteristic of wettability experiments. The model takes into account many pore level flow phenomena such as film flow along wetting phase clusters, trapping of wetting and nonwetting phases by snapoff and bypassing. We also consider realistic variations in advancing and receding contact angles. There is a discussion of the effects of additional parameters such as the fraction of oil-wet pores, mean coordination number and pore size distribution upon fractionally and mixed wet capillary pressure curves. Moreover, we calculate Amott oil and water indices using the simulated curves. Results indicate that oil recovery via water imbibition in weakly water-wet cores can often exceed that obtained from strongly water-wet samples. Such an effect has been observed experimentally in the past. The basic physics governing this enhancement in spontaneous water imbibition can be explained using the concept of a capillarity surface. Based on these theoretical calculations, we propose a general "regime based" theory of wettability classification and analysis. We classify a range of experimentally observed and apparently inconsistent waterflood recovery trends into various regimes, depending upon the structure of the underlying oil- and water-wet pore clusters and the distribution of contact angles. Using this approach, numerous published experimental Amott indices and waterflood data from a variety of core/crude oil/brine systems are analyzed.

Wettability and Relative Permeability of Prudhoe Bay: A Case Study in Mixed-Wet Reservoirs

Summary This paper describes the variation in wettability and relative permeability at Prudhoe Bay. We show that measurements are consistent with recent theories of the relationship between water-saturation, pH, wettability and relative permeability.1 In particular, the wettability of the reservoir changes from water-wet low on structure near the water/oil contact to mixed-wet behavior higher on structure. Increasing oil-wetting character is correlated to decreasing water saturation. Changes in wettability are also accompanied by changes in water-flood recovery efficiency and are optimum at Amott indices approaching zero. Lithology also impacts recovery efficiency, with more clay-rich rocks having higher residual oil saturations.

On The Characterization Of Rock Fluid And Fluid Fluid Interactions In Carbonate Rocks Using The Ultracentrifuge

Abstract The ultracentrifuge provides an easy and fast way of estimating the physical properties of reservoir rock/reservoir fluid systems such as wettability information, capillary pressure and relative permeability curves. The ultracentrifuge has been utilized both in routine core analysis and at the research level. In this work, an extensive experimental program was conducted for the characterization of core from the Rainbow Lake Reefs. Numerous plugs were tested for wettability and capillary pressure characteristics. During the experimental procedure, it was found that the conventional use of the centrifuge data introduces uncertainties that may compromise the quality of the results. As a result, a series of improvements was designed and implemented to allow for the collection of more accurate and consistent data using Charged Couple Devices (CCD). Moreover, a series of experiments was performed aiming at producing recovery data for both water imbibition and EOR experiments. A number of interesting and often neglected issues were addressed. The capillary pressure data often showed hysteresis that did not reflect the hysteresis observed in porous plate measurements. This paper summarizes the work completed to date, provides information on the wettability and capillary pressure characterization of the Rainbow Lake Reefs, and presents the results of gravity assisted immiscible gas injection of water flooded plugs. The hysteresis phenomenon observed between primary and secondary drainage is not consistent. The fluid propagation in a three-phase system varies from sample to sample at low Bond Numbers. Amott indices do not change significantly with temperature for strongly water-wet media. There cannot be a consistent correlation among wettability indices and other physical properties for the reef cores. USBM indices on raw centrifuge data are different than the same, indices calculated on fitted curve data but not enough to alter the overall wettability classification. Introduction Literature Survey The measurement of reservoir wettability and the assessment of its importance for the recovery of crude oil have been the topic of numerous research papers in the past fifty years. Several reviews have been published that address the methods and options that a researcher has available when measuring wettability. Although simple contact angle measurements are still thought to be the most universal measure of wettability(l), other methods have emerged through the years that take advantage of the changes in capillary phenomena as they are affected by changes in wettability(2). The Amott test(3) and the USBM test(4) and their various combinations have been widely applied in the literature for the determination of the wettability characteristics of given reservoir/crude oil combinations. The initial single wettability characterizations (i.e., oilwet, water-wet, and neutral) were later complemented by new terms such as mixed(5), fractional, etc. In real systems, the distinction between different types of wettability became more and more vague. One of the tools that has gained considerable popularity in the past decades is the centrifuge and its variations. Starting from the original paper of Hassler and Brunner(6), much effort has been spent on both the experimental part and the interpretation part of centrifuge technology.