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Article

On the Water-Oil Relative Permeabilities of Southern Algerian Sandstone Rock Samples

by
Sami Yahyaoui
1,
Rezki Akkal
1,*,
Mohammed Khodja
2 and
Toudert Ahmed Zaid
1
1
Laboratoire de Valoriation des Energies Fossiles, Département de Gènie Chimique, Ecole Nationale Polytechnique, 10 Avenue Hassen Badi, BP 182, El Harrach, Algiers 16200, Algeria
2
Institut Algérien du Pétrole (IAP), Sonatrach, Avenue du 1er Novembre, Boumerdees 35000, Algeria
*
Author to whom correspondence should be addressed.
Energies 2022, 15(15), 5687; https://doi.org/10.3390/en15155687
Submission received: 2 July 2022 / Revised: 19 July 2022 / Accepted: 23 July 2022 / Published: 5 August 2022
(This article belongs to the Special Issue Oil Field Chemicals and Enhanced Oil Recovery)
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Abstract

:
The water–oil relative permeability behavior of different plugs from the Hassi Messaoud reservoir in south Algeria has been investigated to understand the fundamental processes of two-phase flow taking place within the macro-structure of rock samples. The experiments were conducted on cylindrical reservoir samples (plugs) using the unsteady-state method to measure the oil–water relative permeabilities due to operational simplicity. The impact of factors such as wettability, overburden pressure and rock characteristics based on the relative permeability curves have been carefully assessed. During this test, temperature was kept in the range of 95 to 100 °C and pressure was maintained at 100 bar. Large variations in relative permeability curve trends have been experimentally observed for different rock samples under investigation, which can be explained by the heterogeneous nature of the studied reservoir. Results showed an intermediate alteration of wettability and for all studied samples, and the intersection point of the relative permeability values for oil and water is less than 50%, showing that these samples exhibit oil-wet behavior. Our results also show that displacement pressure increases from 0.13 to 2 psi, promoting a gradual displacement of oil relative permeability (Kro) toward higher saturations in water (45% to 60%). The results show that the oil recovery rate at breakthrough is approximately 16% to 28% of the initial oil in place (IOP), with an average of 23%. The final oil recovery rate, obtained by moving at constant pressure, ranges from 43% to 55% of the initial oil in place (IOP), with an average value of around 49%. The forced displacement at the end of the performed tests increased the average recovery rate by about 4%. These rates vary from 46% to 61% of the initial oil in place (IOP). The residual oil saturation (Sor) varies from 33.7% to 47.8% relative to pore volume (Vp); the average is about 42%. The residual oil saturation (Sor) is about 30% to 45% Vp after forced displacement at the end of the test, the average is about 38.5%, and the relative permeabilities Krw and Kro are equal to the water saturations of 33% to 50%; the average value is about 41%.

1. Introduction

Over time, oil reservoir pressure becomes insufficient to produce oil at an economical rate, so additional pressure may be necessary after conventional primary recovery. Otherwise, large amounts of oil—more than 75% in most cases—are left in a reservoir after conventional oil recovery processes. Generally, oil recovery can be achieved in three stages, namely primary, secondary and tertiary [1,2,3]. The initial or primary production is the first oil, “easy oil”, which is the result of natural mechanisms in the reservoir. Once a well has been drilled and completed in a hydrocarbon-bearing zone, natural pressure at this depth will cause the oil to flow through the reservoir rock to lower-pressure wells (Figure 1a). This process causes the precipitation of inorganic salt in various areas of oil well production. Thus, the reservoir rock pore channels become clogged with precipitation, which lowers their permeability [4,5]. Salt also accumulates in pipeline networks and on the surface of manufacturing equipment. High material costs and large losses in oil production are caused by salt formation [6]. This process, primary recovery, is the least expensive extraction method, and its typical recovery factor is about 5–15% of the original oil in place (OIP) [7,8].
Meanwhile, pressure inside the reservoir is reduced and will not be sufficient to force oil to the surface. Thus, the secondary recovery method is applied to adjust reservoir pressure (Figure 1b). To increase reservoir pressure and to reduce the overall density of the fluid inside the borehole, external energy may be introduced into the reservoir [9,10]. Thus, the injection of water or gas is the most common technique, which uses an injection well to introduce large quantities of water or gas under pressure into the hydrocarbon-bearing zone. As water flows through the formation towards the producing wells, it sweeps some of the encountered oil, and upon reaching the surface, the oil is separated and the water reinjected. The average recovery factor after primary and secondary oil recovery operations ranges from 30% to 50% [11,12]. Tertiary recovery or enhanced oil recovery (EOR) begins when secondary oil recovery is not enough to continue adequate extraction, but only when oil can still be extracted profitably (Figure 1c). The main objective of EOR, in addition to restoring formation pressure, is to improve the displacement of oil or fluid flow in the reservoir. This method improves the recovery of oil from 5% to 15% of the remaining oil trapped in the reservoir formation [13,14,15,16].
Our study is focused on the Hassi Messaoud oil field in south Algeria. In this area, Cambrian sandstone, which is the producing formation of the Hassi Messaoud field, is located at a depth of 11,000 feet, has a PaY zone between 100 and 300 feet thick, and covers an area of around 600 square miles. The crude bubble point fluctuates in an east–west traverse of the field from 2880 psi to 2130 psi, while the original reservoir pressure was 6825 psi. Due to a decrease from the Hassi Messaoud field’s beginning pressure, which is depicted in Figure 2a for pressure distribution for different zones in the field and Figure 2b for pressure evolution over time for Zone 4 in the same field, we turned to the water–oil recovery approach to raise the injection pressure and attain the field’s original production energy.
In the Hassi Messaoud field, the water-flooding technique is often used to enhance oil recovery significantly following a fall in pressure after years of primary oil output. These techniques are used to maintain reservoir pressure and/or sweep oil towards the production wells. The performance of the water-flooding technique is affected by the following key parameters: geometry and geology of the oil reservoir, petrophysical properties (porosity and permeability), fluid properties (viscosity and wettability) and mineralogical properties (different clays in the reservoir rock) [17]. However, at the laboratory scale, the fundamental parameter on which oil recovery is based is relative permeability, which is thus investigated. This is used as a basis to characterize porous and fractured reservoirs during the multiphase fluid flow. A reliable characterization of this parameter, including a good quantification of uncertainties relating to estimates, allows us to evaluate the performance of the reservoir, the ultimate recovery of oil expected, and the effectiveness of enhanced oil recovery techniques [18,19,20,21,22]. Several experimental methods are used to measure relative permeability, such as the unsteady-state method, the Hassler method [23,24,25], and the dynamic simple sample method [25,26,27,28], which can be categorized into two major groups, being steady-state and unsteady-state methods [29,30]. Other methods, including capillary pressure [31,32,33], are used. The evaluation of the relative permeabilities of two immiscible fluids in the laboratory is achieved using several techniques, but generally two methods are most used in the laboratory. These are unsteady-state and steady-state. The relative permeabilities can also be obtained from a petroleum reservoir based on the production history of the oil field, geology and fluid properties [23,34,35,36,37,38]. The relative permeabilities can also be obtained from a petroleum storage tank based on the history of the production of the petroleum reservoir (see Figure 2a,b), its geology, as well as the properties of the fluid. The steady-state method is based on the simultaneous injection of two fluids through the reservoir rock. In this technique, a fixed ratio of fluid is injected through the test sample to obtain a drop of uniform pressure and saturation through the basic sample [39,40,41,42]. These methods provide flexibility in controlling the saturation, where several injection ratios can be used to cover the full range of saturation. For the steady-state method, relative permeabilities are calculated using a theory based on the extended Darcy law for the multiphase flow. The main assumption of these processes is the need for the existence of a flat saturation profile, which can be obtained for a sufficiently long sample or high flow rate. The methods of unsteady state which involve the displacement of one or two phases by a third injected phase, are faster and easier to run. These methods are also considered to be more representative of the way in which the process of displacement occurs during the recovery of oil, typically in terms of change in rapid saturation to the unbalanced state. These methods have several benefits. To prevent problems with krw instability, relative permeability is estimated across a broad saturation range. This straightforward calculation (Darcy) is the suggested approach for unfavorable oil. However, these techniques have some drawbacks, such as the requirement that tests be conducted using a high-pressure-capacity apparatus and employing long core plugs to optimize data accuracy. Due to the need for reservoir conditions, this requires sophisticated lab resources and equipment, and test costs would be significant [43,44]. In general, the theory developed by Buckley and Leverett [45], and later extended by Welge [46], is widely accepted and used to determine the relative permeability of the fluid phases using data extracted from steady-state experiences. Given the geological complexity of the Hassi Messaoud oil field, the fluid-flow properties in the oil reservoir are the composite effect of pore geometry, wettability, saturation history of the fluid, reservoir temperature and pressure, and the petrophysical properties of the rock such as porosity and permeability. Some of the influencing factors are determined in the laboratory, and others are determined at the reservoir level. The present study aims to investigate the process of water–oil relative permeability and to identify the dominant mechanisms occurring during this process. In this respect, a series of fluid-flow experiments was performed on various plug samples from the Hassi Messaoud oil field using the unsteady-state method under constant pressure. We performed a series of laboratory experiments to gather data to provide a better understanding of the rock–fluid interaction. Petrophysical parameters such as porosity, permeability, wettability, relative permeability, water saturation, and capillary pressure were measured. Analysis of the results gave us some insights on the mechanisms of the fall in productivity at the Hassi Messaoud field and offer an overall view on the total production.

2. Laboratory Procedures

2.1. Samples Preparation

In the present work, samples from the Hassi Messaoud field have been selected in order to carry out enhanced oil recovery tests. These samples are known to be heterogeneous. Indeed, the mineralogical composition of the reservoir samples is variable, containing 60–79% of quartz and clay cements (illite, kaolinite and chlorite) whose CEC is of the order of 3.4 to 6.3 meq/100g clay. The lengths and diameters of the different plugs are of the order of 4 and 4.65 cm, respectively. The petrophysical properties of these reservoir rocks are variable, with porosities ranging between 16% and 21%, and the permeabilities are good to very good, ranging between 250–440 mD and 1000–2100 mD, respectively. In order to be reused for testing relative permeabilities, the selected reservoir rock samples (plugs) were washed using Soxhlet extraction in a mixture of solvent methanol/acetone/toluene (ratio 15/15/70), to extract organic matter (hydrocarbon fluids) and impurities. Soxhlet washing was stopped when the solvent becomes transparent. It was followed by a second washing with methanol alone to dissolve the salts in the pores. Control of the presence of salt in the solution was done using the silver nitrate test. After washing, the samples were dried in an oven at a temperature of 65 °C until constant weight. Then, these were subject to porosity and permeability measurements. Saturation of the sample was carried out with reconstituted reservoir water or API brine (distilled water containing 8.5% NaCl and 2.5% KCl). This operation was performed after keeping the samples under high vacuum for over 24 h. The vacuum is applied to replace the interstitial water by draining oil before measuring the initial permeability. In fact, this water remained trapped in the pores after placing the hydrocarbons during their migration to the surface, which was stopped by an impermeable cover. Water is generally pushed back against the walls of the pores and/or small pores (rock wettable with water) and constitutes so-called irreducible water.

2.2. Experimental Section

In this section, key parameters such as the irreducible water saturation S w i , the oil and water relative permeabilities K r o and K r w , and residual oil saturation S o r are investigated. The experimental procedure for S o r and S w i determination is as follows: the sample is placed in a Hassler cell under a crimping pressure. Water is injected through the sample’s upstream face, maintaining at a constant pressure. The volumes of the two test fluids are recovered and counted in graduated centrifuge tubes. A total of 15 points are recorded over time during the test course. Once oil flow becomes negligible with respect to water flow, the pressure increased (three to seven times the test pressure) to determine extreme residual oil saturation. In the second step, the irreducible water saturation (S w i ) is determined. The core samples are 100% saturated with synthesized formation water (Figure 3), loaded in a cell with a semipermeable membrane and subjected to increasing steps of gas (nitrogen) pressure, from 1 to 35 psi, with an equilibrium time between 24 and 72 h between each step. At the end of the equilibrium time, the samples are partially unsaturated. The variations of the sample weights are noted, from which water saturation is deduced, and the capillary pressure relationship is then determined as a function of water saturation [Pc = f (Sw)]. The irreducible water saturation (S w i ) corresponds to saturation pressure determined at the final pressure step (35 Psi). After the set-up of S w i , all restored samples were vacuumed and saturated with reservoir dead oil provided by Sonatrach and then aged for three weeks at a pressure of 200 bar and temperature of 100 °C. In the third step, the unsteady-state method at constant pressure was used to determine the oil relative permeability (K r o ). The water used for the displacement tests was synthesized from the chemical composition of Albian water composed mainly of sodium chloride (NaCl) 158.87%, potassium chloride (KCl) 7.44%, hydrated calcium chloride CaCl 2 · 2H2O 94.53% and hydrated magnesium chloride (MgCl 2 · 2H2O) 140.74%, and the synthesized water is composed mainly of sodium chloride (NaCl) 10.26%, potassium chloride (KCl) 0.16%, hydrated calcium chloride CaCl 2 · 2H2O 4.44% and hydrated magnesium chloride (MgCl 2 · 2H2O) 1.89%. Finally, the sample was loaded into a Hassler cell under a confining pressure. Then, water was injected into the upstream face of the sample under a constant pressure, as mentioned above (Figure 4).

3. Experimental Outcomes

3.1. Influence of Petrophysical Properties

The main objective in this section is to highlight the relationship between rock petrophysical properties, such as pore geometry and permeability, and the behavior of the reservoir under the conditions of multiphasic flow. Plugs from the Hassi Messaoud field have been used whose petrophysical characteristics and mineralogical composition are given in Table 1. It should be noted that the more permeable rocks (sample #8, sample #6 and sample #3), whose permeabilities range between 1500 mD and 2000 mD, show relative permeability of the non-wetting phase beginning at lower water saturation values compared to that of sample #14, whose permeability is around 200 mD (Figure 5a). This is clearly shown in Figure 5b, showing that the recovery in oil increases when the pore volume increases for all samples (see Table 1); however, this recovery in oil is enhanced when the permeability changes from 241 mD to much higher values reaching above 1700 mD (Figure 5a). It should also be noted that there is a smooth transition of oil relative permeability (Kro) to the highest water saturations (Sw) when reservoir rock permeability decreases. This can be explained by the fact that reservoir rocks with high permeability are often mixed with porous favorable networks, allowing efficient circulation and quickly reaching irreducible oil saturation during the water-flooding phase [13,47]. A similar effect can be seen when we plot relative permeability curves along with the permeability and porosity of each rock, as shown in Figure 6a,b. As can be seen from this figure, for rock samples with similar porosity, the non-wetting phase flow begins at the same water saturation value, around Sw = 25% and Sw = 33%. For samples #12, #11 and #14, which have relatively low permeability compared with those of samples #10 and #15, the non-wetting phase flow starts for relatively high water saturation values [10,25]. Figure 7a,b and Table 1 show that oil relative permeability (Kro) increases while residual oil saturation Sor decreases with high porosity and low permeability of reservoir rocks. This strengthens our explanation that an increase in microporosity leads to better connectivity, which in turn leads to a facilitated fluid flow in the rock pores.

3.2. Relative Permeability of Different Wells

Oil-water relative permeabilities were measured in different plugs sampled from the Hassi Messaoud oil field. Figure 8 shows the relative permeability curves for the different plugs under investigation. The results clearly indicate that these plugs are mainly oil-wet because the intersection mark between the two curves of water and oil relative permeability is below 50% of water saturation for plugs #3, #4, #5, #8 and #9. However, there are exceptions, with certain plugs, such as plugs #12 and #14, which exhibit a water-wet behavior because the intersection mark is just 50% of water saturation. This can be attributed to the heterogeneity of the Hassi Messaoud reservoir rocks, and can thus be explained by a pronounced accumulation of water in the high-permeability sections of composite cores. The characteristics of relative permeability shown by these two plugs (#12 and #14) indicate the easy movement of the non-wetting oil phase. This means that the greater alteration of the rock wettability renders them more water-wet and promotes oil phase flow efficiency. The rocks exhibiting moderate permeability show a water-wet wettability, whereas the rocks with very high permeability and porosity show an oil-wet behavior [17]. This can be explained by the fact that during fluid circulation in reservoir rock, there is a strong interaction between fluid and rock composition, leading to the dissolution and deposition of particles on the pore surfaces which, in turn, leads to porosity clogging and to the rock wettability inversion [48,49]. In addition, rocks that exhibit water-wet behavior have lower oil residual saturations (Sor) and a significant initial oil in place (IOP) compared to those exhibiting oil-wet behaviors.

3.3. Pressure Effects on the Relative Permeability

To study the effect of displacement pressure of the fluid (oil displacement with reconstituted reservoir water) on the relative permeabilities, tests were conducted using the porous plate method on reservoir rocks from the Hassi Messaoud field. As can be seen from Figure 9, when injection pressure is increased, there is a gradual shift of the oil relative permeability to higher values of water saturation, from rocks with high porosity and permeability to rocks with average porosity and permeability (see Table 1). This may be explained by the fact that the rocks of high permeability are often considered heterogeneous, with a porosity-predominant system ensuring effective sweeping of fluid during the initial phase of water-flooding. The higher-pressure injection leads to the creation of a connected porous network, which in turn facilitates the easy movement of a non-wetting phase (oil) [50,51,52].

3.3.1. Wettability Effect

In this section, the test data are interpreted with respect to the Amott wettability index (AIW), and the analysis of the produced fines is presented. A wettability test was performed on three restored samples and two samples in their native state (Table 2). Samples restored necessitated preparation (washing, drying, petrophysical measurement, vacuum saturation with reconstituted formation water, establishment of irreducible water saturation, saturation with the bearing oil, and aging) as cited in the experimental section before undergoing the test, and the samples retained were soaked without prior preparation. During injection of the reservoir fluid (water) containing minerals such as NaCl and KCl, an interaction with rock reservoir mineral components occurs, leading to the dissolution and deposition of solids on the pore surface, thus altering the rock wettability, conferring it a more oil-wet behavior [17] (Figure 10 and Figure 11 and Table 2). This can be expected because mineral surfaces are much more water-wet than in the oily phase. This is because the interfacial energy of oil–mineral is superior to the interfacial energy of water–mineral, which makes the mobility of the oily phase difficult [53,54,55,56,57,58].

3.3.2. Capillary Pressure Effect

Capillary pressure plays a significant role in the two phases regarding permeability for wetting and non-wetting phases. In order to investigate the impact of capillary pressure on oil recovery, identical rocks were considered for plotting capillary pressure versus irreducible water saturation. As shown in Figure 12, capillary pressure decreases when irreducible water saturation S w i increases for low values of water saturation, then a plateau appears for water saturation above approximately 35%. It should also be noted that when the S w i is more important, there is a trend of displacement of capillary pressure curves toward higher water saturations, which makes the reservoir rock water-wet, leading to easier movement to the non-wetting phase (oil) [59,60,61]. This will lead to a reduction in oil residual saturation and increase in oil recovery.

4. Conclusions

This work is intended to address the general problem of immiscible fluid flow (water and oil) through reservoir rocks from the Hassi Messaoud field. The circulation of these fluids through the rock will be used to provide plots of the water/oil relative permeabilities to gain a clear insight into the rock behavior regarding the flow of fluids through the rocks on the one hand, and final oil recovery on the other hand, thus providing a valuable response to a sharp decline in oil production due to a large pressure drop. During this study, the nature of the fluid used is probably the most important variable to be considered in the process of oil recovery. In addition to the variable geological nature of the complex formation traversed, the work undertaken within this project aimed to identify the most significant variables influencing oil recovery, and we tried to deduce the complex relationships and interactions between the fluids used and the nature and type of formation encountered. According to the obtained results, the Hassi Messaoud sample rocks with high petrophysical properties, such as permeability (higher than 1500 mD) and porosity, show that the relative permeability of the non-wetting phase begins at lower water saturation values compared with that of low permeability, and porosity shows that the non-wetting phase flow starts for relatively high water saturation values. It should also be noted that oil relative permeability (Kro) increases while the residual oil saturation Sor decreases, with high porosity and low permeability of the reservoir rocks. The examination of the oil–water relative permeability measured for different plugs provided from the Hassi Messaoud oil field shows that some rocks are oil-wet, and others show a water-wet behavior due to rock heterogeneity. Nevertheless, rocks exhibiting moderate permeability indicate a water-wet wettability, whereas rocks with very high permeability and porosity show an oil-wet behavior. In addition, rocks that have water-wet behavior have lower oil residual saturation (Sor) and a significant initial oil in place (IOP) compared to those exhibiting oil-wet behaviors. The fluid saturation, the distribution, and the fluid flow in the porous medium are governed by minerals present in the reservoir rock, generally known as inherently hydrophilic, i.e., they are preferentially water-wet. Thus, Hassi Messaoud plugs with low irreducible water saturations are fundamentally composed of carbonates, which makes the rock more oil-wet. On the other hand, the presence of clays in the form of kaolinite, in addition to quartz, makes the rock more water-wet, which promotes oil recovery. In a second step, the intrinsic properties of the reservoir rock were determined, such as the effective permeability of the two fluids Ko and Kw, and the water and oil saturations Swi and Sor. These vary between 16.02% and 30.61% for the Swi and between 38.13% to 47.77% for Sor. In a third step, we investigated the impact of different parameters such as pressure displacement, petro-physical properties of the rocks (porosity and permeability) and the wettability on the relative permeabilities. Results showed an intermediate alteration of wettability and, for all samples under investigation, the intersection point of the relative permeability values for oil and water is less than 50%, showing that these samples have an oil-wet behavior. It is also expected that the displacement pressure increases from 0.13 to 2 psi, promoting a gradual displacement of oil relative permeability (Kro) toward the higher saturations in water (45% to 60%). The extracted parameters, such as the initial oil in place (IOP), water saturation, and oil and water relative permeabilities, are strongly related to the above-addressed factors such as displacement and capillary pressure, wettability, and the nature of the fluid used. The oil recovery rate at breakthrough is approximately 16% to 28% of the original oil in place (IOP),with an average of 23%. The final oil recovery rate, obtained by moving at constant pressure, ranges from 43% to 55% of the original oil in place (IOP), with an average value of around 49%. The forced displacement at the end of the performed tests increased the average recovery rate by about 4%. These rates vary from 46% to 61% of the original oil in place (IOP). The residual oil saturation (Sor) varies from 33.7% to 47.8% relative to pore volume (Vp); the average is about 42%. The residual oil saturation (Sor) is about 30% to 45% Vp after forced displacement at the end of the test; the average is about 38.5% and the relative permeabilities Krw and Kro are equal to the water saturations of 33% to 50%; the average value is about 41%.
Oil and natural gas companies rely on predicting future oil/gas outputs for reservoir management, which is performed through significant investments in precise history-matching studies and extensive characterization efforts. This can be overcome using new techniques such as machine learning [62] and by predicting two- or three-phase relative permeability from two-phase data or from relationships between saturation and capillary pressure based on several correlations that have been proposed. Among them are the models created by Stone, Hirasaki, Corey et al., Naar and Wygal, Land, Parker et al. and others [63,64].

Author Contributions

Formal analysis, S.Y., R.A., M.K. and T.A.Z.; Investigation, T.A.Z.; Methodology, R.A. and M.K.; Project administration, S.Y.; Writing—original draft, R.A. and T.A.Z. All authors have read and agreed to the published version of the manuscript.

Funding

This research received no external funding.

Institutional Review Board Statement

Not applicable.

Informed Consent Statement

Not applicable.

Data Availability Statement

Not applicable.

Acknowledgments

The authors thank Sonatrach, National Oil Company of Algeria, for permission to use the products, the technical support, financial and technical contributions of the Research and Laboratory.

Conflicts of Interest

The authors declare no conflict of interest.

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Figure 1. Oil recovery steps: (a) Initial oil recovery; (b) secondary oil recovery; (c) tertiary oil recovery.
Figure 1. Oil recovery steps: (a) Initial oil recovery; (b) secondary oil recovery; (c) tertiary oil recovery.
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Figure 2. Pressure distribution at the Hassi Messaoud Field: (a) Pressure distribution for different zones and (b) Pressure evolution along the years for Zone 4. The online pressure evolution is depicted in blue, and this curve’s fitting is shown in red color.
Figure 2. Pressure distribution at the Hassi Messaoud Field: (a) Pressure distribution for different zones and (b) Pressure evolution along the years for Zone 4. The online pressure evolution is depicted in blue, and this curve’s fitting is shown in red color.
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Figure 3. Viscosity evolution versus the temperature for the fluids used in the water/oil relative permeability experiments.
Figure 3. Viscosity evolution versus the temperature for the fluids used in the water/oil relative permeability experiments.
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Figure 4. Applied apparatus to achieve the water/oil relative permeability tests measurement.
Figure 4. Applied apparatus to achieve the water/oil relative permeability tests measurement.
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Figure 5. Relative permeability versus water saturation highlighting: (a) the impact of petrophysical properties on wetting and non-wetting phases and (b) oil recovery versus pore volume.
Figure 5. Relative permeability versus water saturation highlighting: (a) the impact of petrophysical properties on wetting and non-wetting phases and (b) oil recovery versus pore volume.
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Figure 6. (a) Relative permeability versus water saturation indicating the effect of air permeability and porosity on the relative permeability and (b) Oil recovery versus pore volume highlighting the IOIP index impact for the studied rocks.
Figure 6. (a) Relative permeability versus water saturation indicating the effect of air permeability and porosity on the relative permeability and (b) Oil recovery versus pore volume highlighting the IOIP index impact for the studied rocks.
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Figure 7. Water/oil relative permeability versus water saturation indicating the Sor permeability effect on the water/oil relative permeability (a) for samples 8, 9 and (b) for samples 1, 2.
Figure 7. Water/oil relative permeability versus water saturation indicating the Sor permeability effect on the water/oil relative permeability (a) for samples 8, 9 and (b) for samples 1, 2.
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Figure 8. Relative permeability versus water saturation for oil wetting samples (a,b) and for water wetting samples (c,d).
Figure 8. Relative permeability versus water saturation for oil wetting samples (a,b) and for water wetting samples (c,d).
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Figure 9. Relative permeability versus water saturation highlighting (a) the injection pressure effect on the relative permeability and (b) irreducible water saturation and capillary pressure versus pore volume for the study rocks in this section.
Figure 9. Relative permeability versus water saturation highlighting (a) the injection pressure effect on the relative permeability and (b) irreducible water saturation and capillary pressure versus pore volume for the study rocks in this section.
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Figure 10. (a) Relative permeability versus water saturation indicating the impact of irreducible water saturation Swi wettability on the relative permeability and (b) oil recovery versus water saturation highlighting how wettability affect the relative permeability.
Figure 10. (a) Relative permeability versus water saturation indicating the impact of irreducible water saturation Swi wettability on the relative permeability and (b) oil recovery versus water saturation highlighting how wettability affect the relative permeability.
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Figure 11. Images from an electronic scanning microscope before and after the fluid circulation (a) exhibiting the open pores prior to the fluid injection and (b) the mineral salt accumulation following the fluid injection.
Figure 11. Images from an electronic scanning microscope before and after the fluid circulation (a) exhibiting the open pores prior to the fluid injection and (b) the mineral salt accumulation following the fluid injection.
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Figure 12. Capillary pressure versus the irreducible water saturation highlighting the impact of capillary pressure on the Sro, Swi and IOP for (a–d) different rocks from the oil feild.
Figure 12. Capillary pressure versus the irreducible water saturation highlighting the impact of capillary pressure on the Sro, Swi and IOP for (a–d) different rocks from the oil feild.
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Table
Table 1. Description of the experimental results including sample description, coast porosity, density, irreducible water saturation, air permeability, initial oil in place, residual oil saturation and pressure.
Table 1. Description of the experimental results including sample description, coast porosity, density, irreducible water saturation, air permeability, initial oil in place, residual oil saturation and pressure.
Sample DescriptionCoastPorosityDensity (gr/cc)Irreducible Water Saturation SwiPermeability K air Initial Oil in Place IOPResidual Oil Saturation SorPressure Saturation [×14.2233] Psi
Hassi Messaoud sample #13072.3918.42.6416.0356.552.639.80.89
Hassi Messaoud sample #23094.5720.12.6713.31217.244.947.80.23
Hassi Messaoud sample #32996.0321.52.6411.72122.149.045.10.25
Hassi Messaoud sample #42996.0821.42.6411.21971.455.139.90.13
Hassi Messaoud sample #52996.1720.92.6612.71549.849.644.10.23
Hassi Messaoud sample #63016.9020.92.6412.61297.545.747.50.54
Hassi Messaoud sample #73182.0721.42.659.31538.252.343.20.23
Hassi Messaoud sample #83198.5419.42.6712.21796.047.246.30.12
Hassi Messaoud sample #93200.6419.42.6515.51037.349.242.90.75
Hassi Messaoud sample #103235.0517.82.6526.9440.343.241.51.05
Hassi Messaoud sample #113235.1018.22.6730.6263.445.038.12.00
Hassi Messaoud sample #123235.1519.12.6030.7265.351.433.71.90
Hassi Messaoud sample #133186.8516.62.6715.5329.651.341.21.60
Hassi Messaoud sample #143257.7116.12.6626.8241.443.941.01.60
Hassi Messaoud sample #153257.8117.52.6222.7431.249.938.70.98
Table
Table 2. Description of the experimental results including the sample description, coast, wettability index and observation.
Table 2. Description of the experimental results including the sample description, coast, wettability index and observation.
Sample DescriptionCoastWettability IndexResultObservation
Hassi Messaoud sample# 163244.32−0.65Oil-wetRestored sample
Hassi Messaoud sample# 173200.59−0.68Oil-wetRestored sample
Hassi Messaoud sample# 183244.32−0.25Oil-wetRestored sample
Hassi Messaoud sample# 193198.65−0.83Oil-wetNative sample
Hassi Messaoud sample# 203072.49−0.74Oil-wetNative sample
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Yahyaoui, S.; Akkal, R.; Khodja, M.; Ahmed Zaid, T. On the Water-Oil Relative Permeabilities of Southern Algerian Sandstone Rock Samples. Energies 2022, 15, 5687. https://doi.org/10.3390/en15155687

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Yahyaoui S, Akkal R, Khodja M, Ahmed Zaid T. On the Water-Oil Relative Permeabilities of Southern Algerian Sandstone Rock Samples. Energies. 2022; 15(15):5687. https://doi.org/10.3390/en15155687

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Yahyaoui, Sami, Rezki Akkal, Mohammed Khodja, and Toudert Ahmed Zaid. 2022. "On the Water-Oil Relative Permeabilities of Southern Algerian Sandstone Rock Samples" Energies 15, no. 15: 5687. https://doi.org/10.3390/en15155687

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