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Chemical Enhanced Oil Recovery (EOR) processes received more attentions nowadays. Crude Terephthalic Acid (CTA) as a chemical compound is used for flooding here as an alternative to the traditional hydrolyzed polyacryl amide (HPAM). Crude Oil samples from an Iranian oil field were used during the flooding tests. Sand packed models using two different sizes of sand mainly 50 and 100 meshes were employed in this investigation. A comparison between water flooding and CTA flooding as a secondary oil recovery process revealed that the recovery was improved by 10% when CTA was used. The effect of various injection rates and different concentration of chemical solutions on the recovery factor have been checked. Besides, experimental results improved the surfactant behavior of the CTA solution in water. Moreover, at tertiary state, Sodium Dodocyl Sulfate (SDS) as an anionic surfactant was flooded. Experiments showed that recovery factor increased by 5% OOIP while using SDS.
Keywords: Chemical flooding - EOR- CTA-SDSSand packed model
Polymers can typically be added to the injection water flooded through a reservoir to achieve IOR. The purpose of this additive is to block ‘highways' for the injection water in the reservoir in order to change and optimize flow patterns. With the other technique, surfactants (detergents) are added to injection water to ‘wash out' more oil in the reservoir. More specifically, polymers increase sweep efficiency by improving the mobility ratio. Surfactants, for their part, enhance microscopic recovery by reducing capillary forces in addition to boosting sweep efficiency. Conventional polymers help to raise the viscosity of the injection water, whilst surfactants reduce interfacial tension between oil and water. Petroleum engineers used polymer solutions so that it can sweep the more area of oil-bearing reservoir and it can delay the breakthrough time as well. during a standard water flood, breakthrough time relatively come up fast and water fingering take place into the oil front because of high mobility of water relative to oil, therefore its sweep efficiency will be low [3-4]. Polymer is added to injecting water so that it can increase the viscosity of solution because of its high molecular weight and as a result of that, the fingering effect will be reduced and the sweep efficiency can be improved . Hydrolyzed poly acryl amide (HPAM) and xantan gum as synthetic and natural polymer respectively, are usually used in polymer flooding both in field and in pilot projects. In 1964, Pye and Sandi established the fact that polymer flooding can increase oil recovery compared to water flooding, they expressed that partially hydrolyzed poly acryl amide (HPAM) can reduce the mobility of displacing water with increasing its viscosity and improve the sweep efficiency of flooding process . Fouling and Wang (2006) used high concentration of HPAM polymer solution during flooding studies for Canadian oil field and illustrated the promising effect of HPAM to increasing recovery factor to around 21% of the originally oil in place [7-8].Alkaline-surfactantpolymer (ASP) flooding is studied by Zhang and Halliburton (2006) during the EOR process of a Chinese oil field and improved effect of combination compared to polymer flooding lonely . Kotlar and Selle (2007) studied the influence of combination of polymer (mobility control agent), surfactant (reducing IFT agent) and a small bi-functional molecule (increasing solubility agent and reducing salinity effect) during flooding to enhance oil recovery factor and deduced that oil recovery can be increased by 20% OOIP . Tabary and Bezin (2007) investigated the improved oil recovery techniques and remarked that chemical process plays an important role in recovering upswept oil by improving the mobility ratio and reducing residual oil saturation during processes such as polymer flooding, surfactants polymer flooding (SP) and alkaline / surfactant /polymer (ASP).Basically surfactants reduce the interfacial tension between oil & water and mobilize the residual oil saturation . In 2007 Lakatos and Toth studied the viscoelastic surfactants as mobility - control agents to enhance oil recovery. Their experiments showed that the viscoelastic surfactant could be replaced by traditional mobility control agents because they could reduce IFT and control the mobility ratio simultaneously . Crude Terephtalic Acid (CTA) was used in this study as a macro monomer that can increase water viscosity because it belongs to polyesters family with relatively high molecular weight. In addition, SDS was selected to flood in tertiary state in order to wash out the residual oil after polymer flooding through the sand packed model.
CTA which is an abbreviation for "Crude Terphitalic Acid" is one isomer of the three phthalic acids. It is mostly used as a commodity chemical, substantially as a beginning compound for making of polyester (specifically PET) which its property given in table 1. Addition to good solubility of CTA, it is stable in high temperature around 2800C. It has the chemical formula C6H4 (COOH) 2 (Figure1) and known as 1, 4-benzenedicarboxylic acid as well. CTA can enhance the viscosity of water when is augmented. Therefore, it can be a candidate during chemical flooding process to improve oil recovery factor.
Sodium dodecyl sulfate (SDS or NaDS) or sodium lauryl sulfate (SLS) is an anionic surfactant with molecular formula C12H25SO4Na. The molecule has a tail of 12 carbon atoms, attached to a sulfate group, giving the molecule the amphiphilic properties required of a detergent (figure 2). SDS is probably the most researched anionic surfactant compound. Sodium lauryl sulfate can solve trapped oil in porous media and therefore, found an extended usage in reservoir engineering field. The critical micelle concentration (CMC) in pure water at 25°C is 0.0082 M, and the aggregation number at this concentration is usually considered to be about 50. The micelle ionization fraction (a) is around 0.3 (or 30%).
Experimental set up
To investigate the polymer-surfactant EOR process, a sand packed column was employed in this study. A glassy column with inside diameter of 2.5 cm and height of 25 cm was used as the sand pack holder. Two metallic meshed distributors were positioned on the both ends of the column. The entrance and exit parts of the model were equipped with flanges and valves to control the flooding rate. Silicate sand with mesh numbers 50 and 100 are selected as porous media. First, the sand was washed and allowed to dry in free air for 2 days. Then, it was poured into the sand pack gradually and was packed well. When the sand pack holder became full, the end flange was closed and then was connected to a CO2 storage tank and the CO2 was allowed to flow through the sand pack for about 15 minutes to completely expel the entrapped air. Then it was flooded with water and during water flooding the permeability of the sand pack was measured employing a constant water head. The water-flooded sand pack was then flooded by oil using a very precise syringe pump and 4 to 5 pore volumes of the oil was allowed to pass through it. At this time the sand pack has been representing an oil reservoir that has connate water and ready to test (figure 3). Various CTA solutions were injected in secondary state until no more oil would leave the model and during the test, the volume of oil and polymer solution which were going out the model and also the time of depletion were recorded. At the tertiary state, SDS was flooded until no more oil could leave the model and recovery factor was calculated for SDS flooding as well.
In order to find out how well the CTA will do, a comparison between it and water is made during flooding process and the result are shown on figure 4. As one can see, the CTA flooding has more recovery factor around 10 percent against pure water injection. Besides, because of the production of CTA near the Iranian oil field; it is opted for this study during flooding processes. Water flooding can be replaced by CTA flooding in secondary stage because during of tests, there are neither signs of adsorption on sand surface nor reduction of absolute permeability.
Crude Oil samples from an Iranian oil field are selected to be used during the flooding tests. CTA solutions were produced in concentrations of 100,250 and 500 ppm. Because of low solubility of CTA in ambient temperature, the solutions were heated up to 700 C while it was stirred. Fortunately, the solutions would have been uniform and stable during the tests. In efforts to investigate the effect of solution viscosity on recovery factor, three different concentrations were prepared. Table2 shows the solution properties. Experiments were performed as previously described. Solutions with different concentrations were injected in a constant rate (0.2cc/min) and four tests were done in constant concentration (250 ppm) at different rates (0.2, 0.6, 0.8, and 1 cc/min). Table 3 illustrates the characterizations of experiments. In tertiary state, SDS are injected in constant concentrating (2500 ppm) and various flow rate to obtain the effect of flow rate on effectiveness of SDS flooding in tertiary state.
IFT reduction property of CTA
In order to check the IFT reduction property of CTA solution, after preparing the model a 250 ppm solution of HPAM was injected in secondary stage until no more oil can leave the model and then a solution of CTA with 250 ppm concentration was injected in tertiary state. Experiment showed that the 250 ppm solution of CTA increased the viscosity of water up to 2.5 cp which is less than the HPAM, but it could recover more oil from the sand packed model around 3 %( figure 5). Therefore, this may be attributed to surfactant behavior of CTA. In addition theoretically CTA belongs to polyester groups which make soap foam when solve in water.
Effect of concentration of injecting solution on recovery factor
Injections of CTA solution with three concentrations were done. Injections were doing until no more oil could leave the model. It is expected that the solutions with more concentration can recover further original oil in place from the sand packed model. During these tests, SDS was injected in constant concentration (2500 ppm) as well. The results of injection with various concentrations are shown on figure 6. Since more viscous solution will displace oil across the model ideally and invade more area of the model, the breakthrough time will delay and the viscous fingering effect will be mitigated. Therefore, the recovery factor and sweep efficiency will rise. The results from the experiments, also, verify this physical concept
Effect of injection rate on recovery factor
CTA and SDS were flooded at three rates of injection in order to find out the relation of flooding rate and recovery factor. Injecting of high rate solution which expected to bypass the bulk of oil can also impose more pressure drop on porous medium. Therefore, the fingering effects may further be observed as well as coning phenomenon will be included because of unbalancing between gravitational forces and viscous forces at high rates. The results are exhibited in figure 7. Since high rate of injection cause to sweep less area of model and also, the movement of solution through the model is more longitudinal, the breakthrough time will decrease and recovery factor will reduce as well.
Salinity effect on efficacy of solution
Generally proved that the concentration of anionic compounds such as Na+, Ca2+ and Mg2+ have some effects on flooding processes which are imposed on oil reservoirs to improve recovery factor. Salinity which specially means concentration of Na+ has a drawback on Hydrolyzed Polydacryl Amide (HPAM) efficiency during polymer flooding and reduces the its helpfulness, therefore HPAM should be used for such reservoirs which have low brine concentration. However, CTA shows resistance against salinity up to 2500ppm. Figure 8 illustrates a comparison between Dow Pusher 500 polyacrylamide and CTA solutions related to effect of Nacl concentration on their viscosity . Hence, CTA could be a suitable candidate for polymer flooding processes of reservoirs with high salinity concentration processes of reservoirs with high salinity concentration.
Effect of temperature on effectiveness of CTA
Adequate temperature ranges in which polymers remain stable without degradation are very sensitive to types of polymer. It is believed that most polymers will be decomposed at high temperatures and so miss their applicability. Reservoirs with temperature higher than 3000 F should usually be avoided for using polyacrylamide because it loses their viscofying property at that temperature. Our experiments showed that CTA could sustain temperature up to 2500 c without missing its property for the reason that it is contained of benzoic loop in its structure which is very stable.
Results and discussion
This study concerns chemical flooding process to improve oil recovery using CTA and SDS as a polymer and surfactant agent respectively. A sand packed model is used to investigate the impact of various parameters on ability of CTA and SDS to recover more oil during flooding process. Experiments are designed to study effects of injection rate, concentration, temperature and salinity on flooding processes. In addition, the IFT property of CTA is checked as well. Taking every thing into the consideration, the following deductions are obtained:
- Experiments show that CTA can improve water flooding efficiency about 10% at secondary state.
- Although the viscofying property of CTA solution is less compared to HPAM solution but it is used here because of its availability and economical aspects. Moreover, it showed thermal and electrolyte stability as well as IFT reduction property.
- CTA was flooded in secondary state and it showed no adsorption tendency on sand surface or also ability to reduce absolute permeability of the model. Moreover, the better recovery was received compared to tertiary usage of that.
- CTA flooding at low rates shows more recovery factor because the fingering and bypassing effects will be mitigated.
- When CTA is flooded at high concentration, more recovery will obtained since a solution with more viscosity will be obtained and mobility ratio will close to unity.
- Since CTA is belong to polyesters groups, its solution exhibits the effect on reduction of interfacial tension between oil and water.
- CTA is able to sustain the high salinity as well as keep its stability property at high temperatures.
- SDS as a surfactant agent could improve recovery factor around 5% OOIP at tertiary state.
- SDS could recover more oil at less rate of injection while used in tertiary state.