**7. Heavy oil recovery**

The performance of the baseline and the SAP system as mobility control agents in displacing and mobilizing heavy oil was carried out through conventional sand-pack displacement tests. The heavy oil that was provided by Husky Energy Inc. (Calgary, AB, Canada) had an initial viscosity of 68,728 cP at 25°C that was adjusted to 3000 cP at 25°C by dilution with natural condensate (density: 0.9 g/ml) provided by Corridor Resources Inc. (McCully field, Sussex, NB, Canada). A Temco DCHH-series core holder (Temco Inc., Tulsa, OK, USA) was employed to perform the displacement tests. The core holder's rubber sleeve was packed with sand (QUIKRETE® Premium Play Sand®, No. 1113, 100% quartz) of effective size: D10 = 180 μm and a uniformity coefficient: D60/D10 = 2.44 determined by sieve analysis (ASTM C136/C136M-14) [60] employing woven wire brass sieves (Endecotts Limited, London, UK). The packed sleeve was sealed using the floating distribution plug and inserted into the core holder body. An overburden pressure of 500 psi was applied by filling the annulus between the outer diameter of the sleeve and the inner diameter of the core holder body with distilled water. CFR-series transfer vessels (Temco Inc., Tulsa, OK, USA) were used to store heavy oil, brine, and polymer that were pumped to the sand pack by a Teledyne ISCO Syringe pump, model 100DX (Teledyne Isco Inc., Lincoln, NE, USA). Pressure gauges (Omega, Laval, QC, Canada) with an accuracy of 0.5% (FS) were installed in different sections of the sand-pack displacement setup (**Figure 12**).

the second step of brine (8.4 wt%) injection to displace heavy oil (i.e., water flooding) until the production of oil stopped, which corresponded on average to the injection of 6 PVs of brine. The third step consisted of the injection of 1 PV of baseline and/or the SAP system as EOR mobility control agents to further displace and recover oil. The fourth and final step was the post-polymer brine (8.4 wt%) injection as a chaser to displace the baseline polymer and/or the SAP system through the sand pack. On average, 6PV of post-polymer brine was injected. The average injection flow rate was 0.76 ml/min that corresponds to a linear velocity of 0.77 ft./day. During each injection step, the volume of fluid injected, the volume of fluid produced, injection time, and pressures at the inlet, at the sand-pack pressure ports, and outlet of the sand-pack holder were recorded. Material balance of each injection step was carried out to determine the sand-pack fluid saturation and oil recovery. More details on the experimental procedure employed during

**) Porosity,** *φ* **(%) Permeability,** *k* **(mD)**

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The performance of the baseline and the SAP network as mobility control agents in porous media was analyzed by plotting the effective viscosity or resistance factor (RF) [63–68] of the polymer system during flow through porous media as a function of the volume of fluid injected expressed as a fraction of pore volume (PV), which was normalized for porosity and permeability to compare the displacement tests on the same reference. The capillary bundle

these routine sand-pack displacement tests are provided in Ref. [62].

Baseline # 1 208 29 10,049 Baseline # 2 206 29 8667 SAP # 1 204 29 8109 SAP # 2 187 26 4700

**Figure 12.** Experimental setup sand-pack displacement test.

**Flooding test # Pore volume, PV (cm<sup>3</sup>**

**Table 2.** Sand-pack properties.

parameter model was applied for data normalization [66, 69–71].

Four displacement tests were carried out at 25°C. Two displacement tests evaluated the performance of the baseline system and the other two tests the performance of the SAP network. The unconsolidated porous media were characterized by determining the pore volume (PV), porosity (*ϕ*), and permeability (*k*) following standard procedures described in Ref. [61]; at this stage, the sand packs were 100% saturated with brine (8.4 wt%). **Table 2** summarizes the properties of each of the sand packs employed during the flooding tests.

The fluid injection sequence was carried out in four steps as follows. The first step was the injection of heavy oil into the brine-saturated porous media until no more brine was produced from the sand pack that corresponded to approximately two pore volumes (2PV), followed by Viscoelasticity of a Supramolecular Polymer Network and its Relevance for Enhanced Oil Recovery http://dx.doi.org/10.5772/intechopen.77277 109

**Figure 12.** Experimental setup sand-pack displacement test.


**Table 2.** Sand-pack properties.

Although this extended thermal stability evaluation demonstrates the significant effect of temperature and time on the viscoelastic **flow** behavior of both systems, these results further confirm that the functionality of the SAP system is increased at higher ionic strengths due to the formation of stronger intra- and interpolymer associations that enhances its stability at 90°C.

**Figure 11.** *G*'- and *G*"-curves as a function of angular frequency and time.

The performance of the baseline and the SAP system as mobility control agents in displacing and mobilizing heavy oil was carried out through conventional sand-pack displacement tests. The heavy oil that was provided by Husky Energy Inc. (Calgary, AB, Canada) had an initial viscosity of 68,728 cP at 25°C that was adjusted to 3000 cP at 25°C by dilution with natural condensate (density: 0.9 g/ml) provided by Corridor Resources Inc. (McCully field, Sussex, NB, Canada). A Temco DCHH-series core holder (Temco Inc., Tulsa, OK, USA) was employed to perform the displacement tests. The core holder's rubber sleeve was packed with sand (QUIKRETE® Premium Play Sand®, No. 1113, 100% quartz) of effective size: D10 = 180 μm and a uniformity coefficient: D60/D10 = 2.44 determined by sieve analysis (ASTM C136/C136M-14) [60] employing woven wire brass sieves (Endecotts Limited, London, UK). The packed sleeve was sealed using the floating distribution plug and inserted into the core holder body. An overburden pressure of 500 psi was applied by filling the annulus between the outer diameter of the sleeve and the inner diameter of the core holder body with distilled water. CFR-series transfer vessels (Temco Inc., Tulsa, OK, USA) were used to store heavy oil, brine, and polymer that were pumped to the sand pack by a Teledyne ISCO Syringe pump, model 100DX (Teledyne Isco Inc., Lincoln, NE, USA). Pressure gauges (Omega, Laval, QC, Canada) with an accuracy of 0.5% (FS)

were installed in different sections of the sand-pack displacement setup (**Figure 12**).

properties of each of the sand packs employed during the flooding tests.

Four displacement tests were carried out at 25°C. Two displacement tests evaluated the performance of the baseline system and the other two tests the performance of the SAP network. The unconsolidated porous media were characterized by determining the pore volume (PV), porosity (*ϕ*), and permeability (*k*) following standard procedures described in Ref. [61]; at this stage, the sand packs were 100% saturated with brine (8.4 wt%). **Table 2** summarizes the

The fluid injection sequence was carried out in four steps as follows. The first step was the injection of heavy oil into the brine-saturated porous media until no more brine was produced from the sand pack that corresponded to approximately two pore volumes (2PV), followed by

**7. Heavy oil recovery**

108 Polymer Rheology

the second step of brine (8.4 wt%) injection to displace heavy oil (i.e., water flooding) until the production of oil stopped, which corresponded on average to the injection of 6 PVs of brine. The third step consisted of the injection of 1 PV of baseline and/or the SAP system as EOR mobility control agents to further displace and recover oil. The fourth and final step was the post-polymer brine (8.4 wt%) injection as a chaser to displace the baseline polymer and/or the SAP system through the sand pack. On average, 6PV of post-polymer brine was injected. The average injection flow rate was 0.76 ml/min that corresponds to a linear velocity of 0.77 ft./day. During each injection step, the volume of fluid injected, the volume of fluid produced, injection time, and pressures at the inlet, at the sand-pack pressure ports, and outlet of the sand-pack holder were recorded. Material balance of each injection step was carried out to determine the sand-pack fluid saturation and oil recovery. More details on the experimental procedure employed during these routine sand-pack displacement tests are provided in Ref. [62].

The performance of the baseline and the SAP network as mobility control agents in porous media was analyzed by plotting the effective viscosity or resistance factor (RF) [63–68] of the polymer system during flow through porous media as a function of the volume of fluid injected expressed as a fraction of pore volume (PV), which was normalized for porosity and permeability to compare the displacement tests on the same reference. The capillary bundle parameter model was applied for data normalization [66, 69–71].

Polymer retention in porous media after the post-polymer brine injection was determined by the residual resistance factor, RRF [59, 62–65, 67, 68, 70–74]. RF and RRF are significant parameters because they provide reliable information on the propagation and effectiveness of polymeric systems as mobility control agents through porous media. **Figure 13** displays the average RF and RRF as a function of the volume of fluid injected normalized for porosity and permeability of the baseline and the SAP system sand-pack displacement tests.

The RF curves reveal that the SAP system offers a higher end value of effective viscosity, RF (61%), during flow in porous media relative to the baseline. The SAP RF curve also shows a tendency to level off as a function of the volume of fluid injected, which indicates an appropriate propagation of the SAP network through the unconsolidated porous media. Therefore, the SAP network displays a better performance as mobility control agent compared with the baseline system.

The superior performance of the SAP network in displacing heavy oil is attributed to an enhanced effective viscosity during flow in porous media, which generates a more stable displacement front that increases the volumetric sweep efficiency accelerating the production of oil. Besides, both systems—the baseline and the SAP network—show to be very efficient in controlling WOR during the polymer-flooding stage. However, as soon as the post-polymer water flooding is initiated, the water to oil ratio, WOR, increases very rapidly, due to the uncontrollable channeling of brine toward the production end caused by viscous fingering [63].

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A stable supramolecular system was formulated based on the self-assembling of xanthan gum, HPAM, and HMPAM driven by electrostatic interactions through divalent cation (i.e., Ca2+) bridges, which reduce the steric hindrance among anionic polymer chains promoting strong and stable intra- and interpolymer associations via hydrophobic interactions and hydrogen bonding. The viscoelastic functionality of the SAP system is enhanced in high ionic strength aqueous solutions. This performance makes the SAP system suitable for EOR applications

The SAP system shows a high structural strength, mechanical stability, and self-healing capabilities. The supramolecular polymer network exhibits instant recovery of the interpolymer noncovalent interactions and even the increase in structural strength following the lifting of

In the temperature range from 282.5 (9°C) to 353.5 K (80°C), the SAP network exhibits thermal stability. In this temperature range, the strong and stable intra- and interchain interactions maintain the integrity of the supramolecular polymer and its flow viscoelastic behavior. Likewise, the SAP system demonstrated an enhanced thermal stability after 8 weeks at 90°C in high-salinity brine (8.4 wt%) compared with the thermal performance of the baseline. This further confirms that the functionality of the SAP system is upgraded at higher ionic strengths

The SAP system rendered a 10% higher incremental oil recovery relative to the baseline system. The superior performance of the SAP network in displacing heavy oil is attributed to better mobility control properties, to the generation of a stable displacement front, the

involving brines containing high salinity and hardness concentrations.

**Figure 14.** Cumulative oil recovery, *S*or/*S*oi, and WOR versus volume of fluid injected.

due to the formation of stronger intra- and interpolymer associations.

high-shear conditions (i.e., severe shear thinning).

**8. Conclusions**

The RRF curves indicate a larger retention of the SAP system along the sand pack with an end RRF value that stabilizes at around 2.8, while the end RRF value induced by the baseline levels off at approximately 1.3. Therefore, the permeability of the unconsolidated sand packs was further reduced by the SAP system, which aids the displacement and mobilization of heavy oil by further reducing the relative permeability to water [70, 75].

**Figure 14** shows cumulative oil recovery as the percentage of the original oil in place (OOIP) recovered, the ratio of the remaining oil saturation to the initial oil saturation (*S*or/*S*oi), and the water to oil ratio (WOR) as a function of the volume of fluid injected for the water-flooding stage, polymer-flooding stage, and post-polymer water-flooding stage. Water flooding as a secondary oil recovery process on average recovers between 20 and 30% of the original oil in place [76, 77], which agree with our results.

Polymer-flooding and the post-polymer water-flooding steps rendered an overall percentage of cumulative oil recovery of 41% for the baseline system and 51% for the SAP network. Therefore, the SAP system rendered a 10% higher incremental oil recovery relative to the baseline. In field applications of polymer flooding, an incremental oil recovery of 5% is considered successful [44].

**Figure 13.** RF and RRF versus volume of fluid injected.

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**Figure 14.** Cumulative oil recovery, *S*or/*S*oi, and WOR versus volume of fluid injected.

The superior performance of the SAP network in displacing heavy oil is attributed to an enhanced effective viscosity during flow in porous media, which generates a more stable displacement front that increases the volumetric sweep efficiency accelerating the production of oil. Besides, both systems—the baseline and the SAP network—show to be very efficient in controlling WOR during the polymer-flooding stage. However, as soon as the post-polymer water flooding is initiated, the water to oil ratio, WOR, increases very rapidly, due to the uncontrollable channeling of brine toward the production end caused by viscous fingering [63].
