The Impact of Core Firing on EOR of Low Salinity-Surfactant Flooding

The combination of injection of lower saline brine and surfactant will increase recovery in sandstone rocks than either when any of the techniques is singly applied. In this work, core IFT test, pH test, flooding experiments and measurement of dispersion were performed on four core samples which were grouped into two: group A which were not fired and group B which were fired at a temperature of 500˚C for 24 hours. Two low saline brines were prepared: LS1 which was derived by the dilution of seawater four times and LS2 which was derived by ten times diluting the seawater. The surfactant used was ethoxylated alcohol surfactant. Coreflood experiments were then performed on the rock samples starting with the injection of low saline followed by low saline brine combined with surfactant (LSS). Results from the experiments show that with the injection of LS1 brine and LSS1 higher increment in recoveries were obtained for group B than for group A cores. The same trend was also noticed with the injection of LS2 and LSS2. From the results, LS1 gave higher increment in oil recovery than LS2. Also LSS1 gave higher recoveries when compared with LSS2. In all the cases tested, core samples which were fired gave higher recoveries even though they had low permeabilities of 993 md for sample 3 and 1017 md for sample 4 than those which were not fired with higher permeabilities of 1050 md and 1055 md for samples 1 and 2 re-spectively. This was attributed to the alte ration of wettability as well as that of permeability caused by sample firing. The dispersion profiles of the rock samples show that all samples are homogeneous.

present in the petroleum reservoir interact. Petroleum reservoir contains different fluids mixed together as well as different minerals that compromise every geological system which are formed several thousands of years ago. These fluids comprise formation brine and crude oil and, these interact with the surfaces of reservoir rocks. Oil/water (formation brine)/rock system interaction is complex and this interaction affects the outcomes/results of EOR. Oil/water (formation brine)/rock interactions demand thorough investigation to ensure that EOR implementation strategies are successful and this interaction together with interfacial tension control capillary forces. Capillary forces themselves are physical forces which ensure that oil is entrapped as residual oil at the end of every secondary recovery operation. The main approach for EOR is therefore to manipulate the injected fluids in a manner that will minimize the interfacial tension existing between the fluids or cause a change in porous media wettability. Wettability alteration can greatly affect the location of fluids, mostly the flow of fluid, the distribution of residual oil in the rock and the recovery of oil [1] [2], thereby affecting relative permeability [3] as well as capillary pressure [4]. A movement in the residual oil needs an amount of energy that is in the form of viscous force usually initiated by the pressure difference existing between the reservoir and the wellbore. The viscous force is in turn affected by physical phenomena like contact angle, capillary pressure, capillary number and interfacial tension [2] [5]. Oil recovery from all reservoirs subject to increase in water/oil contact or waterflooding is governed by the phenomena of spontaneous imbibitions [6] [7]. Waterflooding remains most common and generally employed oil recovery approach practiced by the petroleum industry since 1930s. By convention, waterflooding was regarded as a physical process for the recovery of oil that serves two major functions namely: 1) to maintain the pressure of the reservoir and 2) to enforce the displacement of oil from the pore space of the reservoir to the producing wells by viscous forces. Nevertheless, the saturation of residual oil left behind after waterflooding is always on the high side [8] [9]. The research work carried out by Surface Chemistry and Petrophysics of the Wyoming University Research Group has revealed that the salinity of injection-water plays a significant role in the performance of oil recovery performance through waterflooding process [10] [11] [12] [13]. Reiter in his work, demonstrated that alteration in the composition of the brine or a reduction in the brine salinity lower than that of initial formation water can significantly lead to extra recovery of oil for the Berea core used for the experiment [14] [15], since the saturation of residual oil could be greatly reduced by low salinity [16]. The increment in oil recovery that occurs from sandstone when low salinity water is used is explained by several mechanisms such as: ion exchange in multicomponent system [17], mineral dissolution [18], double-layer expansion [19], fines migration [10], reduction in interfacial tension [20] and desorption of organic matter from surface of clay [21]. The clay presence in the reservoir [ This is because many simultaneous processes greatly contribute to the entire process [16]. The chemical heterogeneity of the Reservoir may also play a part.
Field scale and experimental projects show that incremental oil production by the flooding of brine with low salinity greatly varies case-by-case in carbonates as well as sandstones [24]. Minerals contained in natural porous rocks are unevenly distributed in random spatial patterns, while some are uniform in their distribution and others are clustered [25]. Physical heterogeneity on one hand, changes flow fields together with the spatial ions distribution [26] while Chemical heterogeneity on another hand greatly changes the rate of dissolution [27] and desorption/ adsorption [28]. A Combination of chemical and physical heterogeneity can largely affect wettability alteration plus water-rock interaction [4].
Since the mechanism for oil recovery in low saline brine injection is not completely understood, wettability alteration has been observed in various experiments. Hence, it is assumed that wettability alteration remains the basic mechanism for low salinity flooding while the factor controlling wettability alteration is double-layer expansion [29].
Surfactants are known to be surface-active agents. Addition of surfactants to the water that is injected causes a reduction in the oil/water IFT and/or the wettability of the formation altered [29] [30]. Injection of surfactant has been identified as a well-known technique for improving oil recovery. Surfactant injection increases the recovery of oil by reduction of the IFT of oil-water system, and thereby preventing oil from being capillary trapped as well as remobilises any trapped oil [31]. High recoveries from surfactant flooding are anticipated to flow at low IFT that is, at capillary number whose value is high, then with low surfactant retention [32]. Surfactants that will yield low IFT at salinities that are low are within reach and they are not expensive compared to those that are efficient at high salinities. In addition, when the salinity increases, the surfactant retention also increases [33]. The positive results obtained from low salinity waterflooding coupled with the possibility of obtaining more recoveries from the process by the addition of surfactant, Alagic and Skauge [34] carried out a hybrid EOR process that combines low salinity brine effect with surfactant injection.
The purpose was to create a more efficient process for oil recovery that combines the destabilization of oil layers during low saline brine injection with low IFT environment that hinders re-trapping of mobilised oil. Alameri et al. [35] in their work, they applied low-salinity water together with surfactants in carbonate reservoirs with oil-wet system to circumvent the challenges brought about by high salinity and thereby improve recovery in the reservoirs. From the literature review conducted, several researchers who studied EOR through low saline brine, surfactant and a combination of the two did not investigate the effect of core firing. In this work, investigation on the impact of core firing on low salinity-surfactant flooding with Niger Delta sandstone rocks was carried out. To have indebt knowledge of fluid flow in the reservoir core sample, dispersion measurements were also carried out at Sor as well as at water saturation of 100%. Open Journal of Yangtze Gas and Oil Profiles of dispersion for all the rock samples were carried out after cleaning with toluene and methanol.

Crude Oil
Crude oil BUK 1 of 56˚ API at 25˚C from Niger Delta BUK reservoir with viscosity of 6.1413 measured with the aid of cannon viscosimeter was utilized for the experiments. The crude oil was filtered with 1 mm filter paper and then vacuumed before it was used.

Sea Water
The synthetic sea water composition which is a representative of the brine for BUK Reservoir depicted in Table 1, with low-salinity brine also depicted in Table 2 used for coreflooding, contact angle measurement of the oil-brine-rock system and brine-oil interfacial tension determination. The sea water density and viscosity were measured as 1.0317 g/ml and 0.934 cp respectively. The sea water has a total dissolved solid of 36,340 parts per million as also depicted in Table 1.

IFT Test
IFT existing between two immiscible fluids, that is, oil and bulk fluid was measured with the Fisher Scientific Tensiometer Model 20. The procedure as stipulated

pH Test
The pH measurement was carried out with aid of an electronic device called pH meter and all measurements were made after calibration. The measuring probe of the pH meter was placed in the aqueous solution and after allowing the needle to stabilize, the reading was taken. The probe was washed and the procedure repeated.  Figure 1 at a confining pressure of 1000 psi with formation water (FW) injected at 2 cc/sec flow rate. This was done to ensure that the rock sample is still at 100% saturation and also to ensure that bubbles of air were not trapped in the pores. At this point the relperm of the core to brine was determined as depicted in Table 3 and also shown in Table 3 are the rock samples' physical properties. Thereafter crude oil sample BUK 1 with properties shown in Table 4 was continuously injected at the rate of 2 cc/sec until initial water satu- The injection fluids Properties are shown in Table 1, Table 2, Table 5 and Table   6 with Figure 1 showing the schematic for the coreflood experimental setup.

Measurements of Dispersion
To have indebt knowledge of fluid flow in the reservoir core sample, dispersions were measured at Sor and at Swi of 100%. Profiles of dispersion for the utilized rock samples at Sor and at Swi of 100% were carried out after cleaning the rock

Measurement of IFT
Investigation of the brine salinity effect on the brine-oil interfacial tension was Open Journal of Yangtze Gas and Oil carried with the Fisher Scientific Tensiometer Model 20 at ambient conditions.
As shown in Table 1, Table 2,  [36], posited that a reduction in IFT as seen in Surfactant cannot be the mechanism through which additional increment in oil recovery can be gotten by flooding with low saline brine. Again, as shown in the Table 1, Table 2, Table 6 and Figure 2, there was a tremendous reduction in the IFT values of LSS. This shows that the effect of reduction in brine salinity can positively impact on the brine-oil interfacial tension.    pointed out that apart from wettability alteration effect on the recovery of oil, achieving ultra-low IFT will result in increased recovery of oil through the elimination of unfavorable effect of the oil been retained in the capillaries.

Dispersion
The dispersion profiles for the rock samples 1 -4 are as depicted in Figure 5 and  Figure   6, after the core samples have been cleaned at water saturation of 100%, the profile shifted towards the right, indicating a dispersion profile that is more symmetrical and ideal in behaviour. The shift to the right was because residual oil was blocking few pores, and this gave rise to few isolated as well as few dead-end pores. When the core samples were then cleaned, the few pores that were previously isolated and few dead-ends became very accessible and thus contributed to fluid flow thereby displaying a dispersion profile that is more ideal.

Conclusions
From the research carried out, the following conclusions are drawn based on the results: • Core samples which were fired gave higher recoveries than those which were not fired in all the cases tested. This has proved that firing/no-firing of rock samples before flooding sequences gave rise to various sensitivities exhibited by the core to low salinity brine injection/surfactant flooding. • The first low salinity brine gotten when the seawater was 4 times diluted (LS1) gave higher recoveries than the low salinity brine obtained by diluting the seawater ten times (LS2).
• The increment in oil recovery gotten by the injection of a combination of LS2 and surfactant designated as LSS2 was higher than that obtained by the injection of a combination of LS1 and surfactant designated as LSS1.
• The dispersion profiles of the rock samples show that all samples are homogeneous. Thus dispersion measurements help to indicate that a core could be homogeneous or heterogeneous.

Contribution of Study
The study has proved that core sample firing also causes alteration of wettability as well as that of permeability of the rock thereby leading to increment in oil recovery.

Acknowledgments
The author acknowledges the support of Kerolycyn Engineering Services Limited for the assistance in providing the samples and certain materials for the experiment and Obmond Energy Nig. Limited for the partial funding of this research as part of community intervention and indigenous capacity building of the Ochia-Assa projects.

Conflicts of Interest
The author declares no conflicts of interest regarding the publication of this paper.