A COMPARISION OF WETTABILITY AND SPONTANEOUS IMBIBITION EXPERIMENTS OF SURFACTANT SOLUTION IN SANDSTONE AND CARBONATE ROCKS

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1 A COMPARISION OF WETTABILITY AND SPONTANEOUS IMBIBITION EXPERIMENTS OF SURFACTANT SOLUTION IN SANDSTONE AND CARBONATE ROCKS Rebelo, David; Pereira, Maria João addresses: Centre for Petroleum Reservoir Modelling, Instituto Superior Tecnico, Avenida Rovisco Pais 1, Lisboa, Portugal Abstract This work focuses on the study of the spontaneous imbibition on two types of rocks, sandstones and cabonates in different environments and the study of the wettability of the rocks. Spontaneous imbibition is influenced by the wettability of the rock that is the preference of the rock by one fluid. Spontaneous imbibition is the main mechanism which increases oil recovery in fractured and low permeability reservoirs. The surfactant is a solution which changes the wettability of the rock and/or decrease interfacial tension between phases. In this study, a non-ionic surfactant, a method of Enhance Oil Recovery (EOR). The surfactant is used along with brine at different salinities to achieve the best solution to recover more oil. The Two-Phase Separation method is used to qualify the wettability of the rock and the Amott-Harvey Method to measure the oil recovery by spontaneous imbibition of water-phase in different environments (salinities and surfactant concentrations), in the laboratory. The objective of this study is to understand the mechanisms behind the oil recovery by imbibibe spontaneously brine and surfactant. Measure the wettability of the rocks presente in this study, because the wettability is one of the main parameters that influence the spontaneous imbibition Keywords: Conventional Reservoirs, Non-ionic Surfactant, Spontaneous Imbibition and Wettability, Interfacial Tension, Amott Harvey Test, Two-Phase Separation Method Introduction Increasing oil recovery is the main objective of the oil and gas industries. Some reservoirs are more diffficult to recover oil from due to their complex petrophysical properties. So, to recover oil, the primary recovery results from the mechanisms of the reservoir allows a recovery of 5-30% of the OOIP. The second recovery is applied by the injection of a fluid to sustain the pressure of the reservoir and allow a recovery of 30-40% of OOIP. The terciary recovery, known as Enhanced Oil Recovery (EOR), allows a recovery of between 40% and 60% or more of the OOIP. Carbonate reservoirs have a complex structure and heterogeneity that is not fully understood. Most carbonates in the world are intermediate to oil-wet. Sandstones have more homogenous properties and their wettability is intermediate to water-wet. In fractured and low permeability 1

2 reservoirs the main mechanism to recover the oil is by change the wettability. (Anderson a, 1986) When the rock is water-wet, it imbibes water spontaneously and allows recovery the oil by capillary forces that are the driving mechanisms to adsorb water and displace the oil. Due to the high attraction force between the rock and water. When the rock is oil-wet, it is more difficult to recover the oil. Because the rock has more attraction forces by oil than water, so the entry pressure is important because it is the pressure to enter the first drop of water into the rock when the rock is saturated with oil. (Anderson b and d, 1986) Figure 1 Comparison of the water saturation versus capillary pressure and relative permeability (Abdallah et al., 2007) Capillary pressure is generated by the interface of two immiscible fluids in a capillary tube, where the wetting fluid due to the stronger adhesive forces builds a curved interface with another fluid. During the imbibition, the capillary pressure decreases because the wetting fluid is imbibed by the rock due to the high adhesion with the rock, possible to visualize in figure 1. In order to reduce the capillary pressure or change the wettability of the rock, it used one method of EOR, the surfactants. Surfactant is composed of a hydrophilic, water-soluble group and a hydrophobic, water-insoluble group. The non-ionic surfactant used in this study does not ionize in aqueous solutions due to the electronegativity contrasts between their constituents. They interact due to the polarity of the molecule and work better in high salinity solutions compared to other surfactants. It is used with a co-surfactant or solvent to lower the interfacial tension to ultralow values. (ElMofty, 2012) (Mosayed and Abedini, 2012) Surfactants react with the oil and carbonate or sandstone surface to alter the environment properties. There are two main mechanisms to change the wettability using surfactant. When the surfactant interacts with the rock surface they can strip the crude oil by the head of the oil and the head of the surfactant, the other is by form a monolayer of surfactant on the surface of the rock by interacting with the tail of the crude oil. (Austad et al., 1998) The other mechanism is by forming a microemulsion that is a phase between the oil phase and water phase. This new phase lowers the interfacial tension between water and oil allowing a decrease in the capillary pressure in oil and water interface and increases the oil recovery. In this paper, the aim is to study the wettability of the rocks and the oil recovery in different environments by using surfactants and different brines at different salinities in carbonates and sandstones. 2

3 This study is based on two laboratory methods: the Two-Phase Separation Method and the Amott Harvey Test. The Two-Phase Separation Method qualifies the wettability of the rock by the interaction between the rock grains and water or oil. It measures by observation what is the preference of the rock grains. The Amott Harvey Test measures over time the oil recovery by spontaneous imbibition in carbonates and sandstones. (Amott, 1959) Methodology The methodology used, figure 2, it is to achieve the objectives proposed for this study. Using surfactant or brine to increase the oil recovery by spontenous imbibition in different environments. Firstly, it is essential to measure the wettability of the reservoirs by using the Two-Phase Separation Method and analyse the spontaneous imbibition of brine and then measure the oil recovery using the Amott Harvey Test. Materials The materials used in this study are synthetic brine, surfactant, synthetic oil and core samples. Synthetic Brines: the synthetic brines used are composed of a mixture of different salts and de-ionized water. The concentration of salt used in this study is ppm (ph=7) and ppm (ph=8.5). Synthetic Oil: the synthetic oil is composed of a mixture of decane and tracer with 500 ppm. It is mixed for 1 hour. The characteristics of decane are used because the tracer is used in small amounts. Surfactant: is a non-ionic surfactant. It is a mixture of Calamide C, Isopropanol and brine. The non-ionic surfactant is used with a solvent to improve the performance. The hydrophilic group is a polymerized alkene oxide. The weight% of compound depends on the experiments. Figure 2 Experimental Design Cores: the cores used in this study are samples of Bentheimer, a Sandstone from Germany and a Carbonate from France. The oil saturation in the cores is betweem 66 to 85% of Pv. The permeability of the carbonates is low compared to the sandstones. 3

4 Two-Phase Separation Method Determine the wettability of the rock by a qualitative measurement based on the interaction between the rock grains and the fluid, brine or oil. The grains of rock will stay where there is a high interaction between the fluid and the rock. 1. Crush the rock into powder: the rock is milt by a Hummer or special apparatus, between 53 to 300 µm. 2. Wash with solvent: the grains are cleaned to restore the wettability. This process has the objective of eliminating all the fluids present in the grains. The grains are introduced into a vial filled with a solvent, in this case, isopropanol. 3. Dry the sample into an oven: the sample is placed in an oven to evaporate all the solvent used to clean a core sample. After some minutes, the sample is taken from the oven dry and clean. 4. Imbibe the sample with synthetic oil: the objective is to restore the wettability. It was not possible to age the grains in the same environment of the reservoir, so the only procedure is by imbibing the grains with a synthetic oil by droping some dropplets onto them. 5. Two Phase Separation test: 0.2g of rock grains and 10ml of oil and 10ml of brine are placed in a vial. The vial is gently shaken and then placed in a structure to settle the compounds. The method measures the wettability by observing where the rock grains are. It happens due to the chemical attraction between the rock and the fluids. If the rock grains are in oil phase, then the rock is oil-wet, if the rock grains are in the interface of the two phases, the rock is intermediate but if the rock grains sink to water phase, the rock is water-wet. Amott Harvey Test This method measures the wettability of the rock and the oil recovery by spontaneous imbibition of aqueous phase over time. It will experiment with different salinities of brine, different composition of the surfactant and different types of rocks. 1. Saturate the sample with brine: the sample is completely dry and clean, the porosity and permeability was measured. Before start it is essetial preparate all the fluids and measure the pore volume of which core. The sample is placed into an empty vial and they are placed inside a closed capsule. The pump is turned on and the pressure inside the capsule starts 4

5 to decrease to vacuum pressure. Then, the pipe vial is opened and the vial with the sample starts to fill with brine. The sample is completely saturated with brine because the pressure is vacum pressure. 2. Saturate the sample with oil: the sample fully filled with brine is placed into a hassler core holder of the coreflooding. The oil flows with a constant flow rate. When the pressure diferences reach an equilibrium, the fluids are in equilibrium and the pump is turned off. It is possible know the volume of oil in the core. The volume of oil is equal to the brine recovery less 0.05 ml of brine, the quantity of brine in the pipes. 3. Amott Harvey Test: a sample saturated with oil is placed inside the Amott Harvey cell, then the cell is filled with brine or surfactant. After this, the cell is closed and then it is record the time and the recovery of oil over time. Results The results of the experiments are presented in this chapter. The experiments are based on the study of wettability and spontaeous imbibition of different cores. Wettability Measurment The analysis of wettability was executed by analysing the spontaneous imbibition of water phase and by the method of two-phase separation. The result is equal for all the cores and they are taken from outcrops. They imbibe brine spontaneously between 15 to 30% of OOIP. This happens when the rocks are waterwet because they have a positive capillary pressure to drive the water into the core. The results of the two phase separation method indicate that the cores are water-wet because the rock grains sink to water-phase due to the high molecular interaction between water and the rocks. So all the cores in this study are water-wet. Spontaneous imbibition The experiments of spontaenous imbibition were executed with all faces of the cores open, at room temperature for carbonates and sandstones, at different salt environments and using in some cases brine others a non-ionic surfactant with different concentrations. Oil Recovery at high salinity in sandstone The brine used has ppm of salt and the surfactant 2wt% of calamide + 1wt% of isopropanol + 97% of brine. In figure 3 the surfactant recover almost 80% of OOIP in the first hour, while in brine it is 20% of OOIP. After 200 hours in surfactant the oil recover is 96% of OOIP, while in brine it is 32% of OOIP. This surfactant has a good performance in high salinity. Due to high salinity at this point, the microemulsion was not formed. So, the main mechanism of the surfactant in this environment is changing the wettability and low the interfacial tension. 5

Figure 3 Oil Recovery with brine and surfactant at high salinity in sandstone Figure 4 Oil Recovery with brine and surfactant at Low Salinity in Sandstone Oil Recovery at low salinity in sandstone

In figure 4, in the first hour the surfactant recover twice the amount of oil recovered by brine, with the oil recovery of 20% of OOIP.

6 Figure 3 Oil Recovery with brine and surfactant at high salinity in sandstone Figure 4 Oil Recovery with brine and surfactant at Low Salinity in Sandstone Oil Recovery at low salinity in sandstone The brine used has 3400 ppm of salt and the surfactant used with a mixture of 2wt% of calamide + 1wt% of isopropanol + 97wt% of brine. In figure 4, in the first hour the surfactant recover twice the amount of oil recovered by brine, with the oil recovery of 20% of OOIP. The final recovery using surfactant is higher than the total OOIP because the oil is recovery by microemulsion and oil phase. The microemulsion is constitute by surfactant, brine and oil. The final recovery in brine is less than 20% of OOIP. The surfactant near the optimum salinity forms a microemulsion due to the solubility of the surfactant in brine and oil. The microemulsion formed is water in oil because the colour of the emulsion is more green. The main mechanism for oil recovery in this environment is to lower the interfacial tension in the interface of the oil and water phase. Oil Recovery at low salinity in carbonate The brine used has 3400 ppm of salt and the surfactant used a mixture of 2wt% of calamide + 1wt% of isopropanol + 97wt% of brine. In figure 5, the first hour the oil recover by surfactant is twice to compared to the oil recover by brine. The surfactant recover 22% of OOIP while the brine recovered 10% of OOIP. The last recovery is about 25% of OOIP for the core imbibed in brine and a high recovery for the core imbibed in surfactant, combine of oil phase and microemulsion. The microemulsion has brine and surfactant in their compounds. The surfactant has a good performance in low salinity like the experiment before. A microemulsion is formed, water in oil emulsion, which increases over time. The main mechanism is by lowering the interfacial tension by forming a new phase. This phase decreases the interfacial tension in the interface between oil and water phase and the capillary pressure too, because the 6

The main mechanism using this two surfactants is by low the interfacial tension.

7 capillary pressure is dependent on the interfacial tension. oil is recovered in the microemulsion. The recovery by the surfactant with 1 wt% of calamide have a very high recovey of oil by microemulsion, what means that have brine and surfactant in their compounds. The main mechanism using this two surfactants is by low the interfacial tension. Figure 5 Oil Recovery with brine and surfactant at Low Salinity in Carbonates Oil Recovery at low salinity in sandstone with difference on surfactant concentration The brine used has ppm of salt and the surfactant used with a mixture of 4wt% of calamide + 1 wt% of isopropanol + 95wt% of brine in the core N4 and 1wt% of calamide + 1wt% of isopropanol + 98wt% of brine in the core U1. In general, figure 6, the surfactant with 1wt% calamide has the best performance. After 10 minutes after the experiment starting, the oil recovered by the surfactant with 1% calamide is more than the oil recovery with surfactant with 4wt% calamide. The surfactant with 1wt% calamide continues with a high rate of oil recovery, because it is a mixture of oil phase and microemulsion phase. The surfactant with 4wt% calamide recover in the same time 36% of OOIP. Using the surfactant with 4 wt% of calamide the microemulsion is very small compared with the 1 wt% of calamide and forms after only 24 hours while wit 1 wt% calamide it forms after 1 hour and most of the Figure 6 Oil Recovery at Low Salinity in Sandstones with differents concentration of surfactants Conclusions The carbonate and sandstone were both waterwet in this study. The cores were taken from an outcrop and in these experiments they were not submitted to aging with crude oil. Both rocks imbibed an amount of brine spontaneously that allowed to determine that they were water-wet rocks. The two-phase separation method also confirmed that the rocks were water-wet because the crushed rock sank into the water-phase. The results showed that there was a larger interaction between rock and water than between oil and rock. Analysing the oil recovery results using brine, it was possible to conclude that the brine at high salinity recovered more oil in sandstones than the brine at low salinity. This might be explained by the specific chemical composition of the brines or due to a low ph that created an 7

8 acid surface with the sandstones which adsorbs only the basic compounds of crude oil. For the carbonates was the opposite because in order to create an acid surface that adsorbs only the basic compounds of the crude oil it was necessary to increase the ph. The viscosity of the surfactants did not influenced the spontaneous imbibition, because it was not linearly dependent on the concentration of the surfactant. However, the oil recovery by microemulsion had an inverse linear dependence on the surfactant concentration. Decreasing the concentration of the surfactant, increased the oil recovery by forming a microemulsion. The microemulsion had intermediate density between oil and water phase that allowed both interfacial tension and capillary forces to decrease. These resulted on an easier water imbibition by the rock and consequently a larger oil recovery. The used non-ionic surfactant increased the oil recovery by the alteration of the wettability and by lowering the interfacial tension. At high salinity, the surfactant did not form a microemulsion, leading to the conclusion that the main mechanism was the Wettability alteration and lower the interfacial tension. While using the surfactant with 1wt% and 2wt% of calamide at low salinity the main mechanism of surfactant was by form the microemulsion that low the interfacial tension. Therefore, using the surfactant with 4wt% of calamide at low salinity it was difficult to understand the mechanism because the microemulsion formed was insignificant compared with other surfactant concentrations, but the main mechanism was the decrease of interfacial tension too. Analysing the results, it was possible to determine that the surfactant had a good performance either in high salinity and low salinity. In low salinity the surfactant forms microemulsion by achieving the Windsor type III, with three different phases. It was a good indicator of the decrease of interfacial tension between oil-water phases. References Abdallah, W., Buckley, J.S., Carnegie, A., Herold, B, Edwards, J., Fordham, E., Graue, A., Habashy, T., Seleznev, N., Signer, C., Hussain, H., Montaron, B., Ziauddin, M. (2007). Fundamentals of Wettability. Bahrain: Schlumberger Wettability Workshop Anderson, W.G. (1986). Wettability Literature Survey- Part:1 to Part:6. SPE, Conoco [Part1- (Anderson a, 1986); Part2-(Anderson b, 1986); Part3-(Anderson c, 1986); Part4-(Anderson d, 1986); Part5-(Anderson f, 1986); Part6- (Anderson g, 1986)]. Amott, E. (1959). Observations Relating to the Wettability of Porous Rock. SPE, Paper presented at Fall Meeting of Los Angeles Basin Section in Los Angeles, California Austad, T., Matre, B., Milter, J., Saevareid, A. and Oyno, L. (1998). Chemical flooding of oil reservoirs ElMofty. O (2012). Surfactant enhance oil recovery by wettability alteration in sandstones 8

9 reservoirs. Missouri University of Science and Technology Mosayed, A. and Abedini, R. (2012). The effect of non-ionic surfactants on the interfacial tension between crude oil and water. Departmnt of Petroleum Engineering,ahallat Branch, Islamic Azad University, Mahallat, Iran 9

WETTABILITY CHANGE TO GAS-WETNESS IN POROUS MEDIA

WETTABILITY CHANGE TO GAS-WETNESS IN POROUS MEDIA Kewen Li and Abbas Firoozabadi Reservoir Engineering Research Institute (RERI) Abstract In the petroleum literature, gas is assumed to be the non-wetting