**1. Introduction**

During the productive life cycle of an oil reservoir, primary, secondary, and enhanced oil recovery methods can be applied to improve the overall hydrocarbon recovery.

Initially, during primary recovery, the oil production is accomplished by the use of the natural reservoir energy as well as artificial lift and well stimulation methods that do not directly

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affect the driving force of the porous medium. Nevertheless, the reservoir primary energy is progressively dissipated due to the decompression of fluids and to forces (viscous and capillary forces) imposed on the matrix flow.

In order to minimize the negative impacts of primary energy dissipation and increase oil recovery, two strategies may be used:


The injection of fluids into the formation (water or immiscible gas) to displace hydrocarbons from the pores of the reservoir matrix with no chemical or thermodynamic interactions between the injected fluid and oil/reservoir rock is known as secondary recovery.

Together, primary and secondary oil recovery methods produce around 33% of a reservoir's initial-oil-in-place (OOIP) [1]. This low oil recovery inherent in these methods occurs due to: (i) high interfacial tension between oil and injected fluids and/or (ii) high viscous oil in the reservoir<sup>1</sup> .

In these cases, the use of enhanced oil recovery (EOR) methods, also known as improved oil recovery (IOR) methods, is recommended, as they act on the sweep efficiency and/or on the displacement efficiency of injected fluids.

• divert the injected fluid flow from high permeability, low-oil-saturation reservoir flow paths to low-permeability, high-oil-saturation flow paths (in-depth profile control), im-

• block high-permeability zones or anomalies located near wellbore modifying the injection profile and/or preventing the channeling and early breakthrough of the injected fluid (water or gas) in production wells (water or gas shut off), thus reducing overall oil-production

This chapter aims at presenting a review of gelling polymer systems commercially available or under academic development, with potential to control the anisotropic permeability profile

Hydrogels used to control the anisotropic permeability profile of oil reservoirs are crosslinked polymers, swellable in water that retain the solvent within their three-dimensional

Polyacrylamide homopolymer (PAM) and acrylamide copolymers such as: partially hydrolyzed polyacrylamide (PHPA), copoly(acrylamide-t-butyl acrylate) (PAtBA), copoly(acrylamide-2-acrylamido-2-methyl-propanesulfonic acid) (PAM-AMPS), and copoly(acrylamide-N-vinyl-

The incorporation of AMPS and/or NVP groups in acrylamide-copolymer chains prevents the acrylamide groups from autohydrolyzing at high temperatures, reducing the polymer susceptibility to precipitate out of the solution in the presence of hardness divalent ions (i.e. Ca2+ or Mg2+). For this reason, AMPS-NVP-acrylamide copolymers are mainly applied for the conformance control of reservoirs with harsh conditions (i.e. temperature > 90°C and salinity >100,000 ppm TDS) [10, 11].

are the most widely used polymers for conformance-improvement

Hydrogels Applied for Conformance-Improvement Treatment of Oil Reservoirs

http://dx.doi.org/10.5772/intechopen.73204

71

**2. Gelling polymer systems for conformance control of oil reservoirs**

proving flood sweep efficiency, and producing incremental oil, or

**Figure 1.** Schematic of an oil reservoir conformance-improvement treatment with hydrogel.

operational costs.

of heterogeneous oil reservoirs.

2-pyrrolidone) (PAM-NVP)<sup>4</sup>

4

structures without dissolving them [7–9].

However, in fractured and/or stratified reservoirs with anisotropic permeability profiles (conformance problems), the sweep and displacement efficiencies tend to be low even after applying secondary and enhanced oil recovery methods.

In these heterogeneous porous media, the injected fluid tends to flow preferably through high-permeability zones and/or anomalies<sup>2</sup> (preferential paths), failing to recover part of the displaceable oil in low-permeability-unswept zones of the reservoir.

The channeling of the injected fluid through these high-permeability zones and/or anomalies, besides reducing the total oil recovery, can also be responsible for the early breakthrough of the injected fluid in production wells, thus increasing the operational costs associated with the separation, treatment, and disposal of the produced fluid (e.g. water).

Therefore, to remedy these problems, several authors [2–6] have proposed the injection of gelling polymer systems<sup>3</sup> to selectively flow through the high-permeability zones or anomalies, temporarily plugging them with a barrier (hydrogel) (**Figure 1**) in order to:

<sup>1</sup> When there is high interfacial tension between the injected fluid and the displaced fluid, the injected fluid capacity to displace oil from the reservoir is significantly reduced, inducing bypass of residual oil by the injected fluid. When the viscosity of the injected fluid is much lower than that of the fluid being displaced, the former displaces much more easily in the porous medium, finding preferential paths and moving quickly toward the producing wells. As the injected fluid does not spread properly inside the reservoir, the oil is trapped in large bulks of reservoir rock in which displacement does not occur.

<sup>2</sup> Fracture networks (both natural and hydraulically induced), faults, interconnected vugular porosity, caverns, and localized matrix reservoir rock with permeabilities greater than 2 Da.

<sup>3</sup> The term gelling system or gelant refers to a polymer + cross-linker solution or a microgel dispersion before any appreciable cross-linker has occurred. The term gel is used when the gelling system has attained either partial or full crosslinking maturation.

Hydrogels Applied for Conformance-Improvement Treatment of Oil Reservoirs http://dx.doi.org/10.5772/intechopen.73204 71

**Figure 1.** Schematic of an oil reservoir conformance-improvement treatment with hydrogel.

affect the driving force of the porous medium. Nevertheless, the reservoir primary energy is progressively dissipated due to the decompression of fluids and to forces (viscous and capil-

In order to minimize the negative impacts of primary energy dissipation and increase oil

• addition of an artificial secondary energy to the reservoir by means of the injection of flu-

The injection of fluids into the formation (water or immiscible gas) to displace hydrocarbons from the pores of the reservoir matrix with no chemical or thermodynamic interactions

Together, primary and secondary oil recovery methods produce around 33% of a reservoir's initial-oil-in-place (OOIP) [1]. This low oil recovery inherent in these methods occurs due to: (i) high interfacial tension between oil and injected fluids and/or (ii) high viscous oil in the reservoir<sup>1</sup>

In these cases, the use of enhanced oil recovery (EOR) methods, also known as improved oil recovery (IOR) methods, is recommended, as they act on the sweep efficiency and/or on the

However, in fractured and/or stratified reservoirs with anisotropic permeability profiles (conformance problems), the sweep and displacement efficiencies tend to be low even after apply-

In these heterogeneous porous media, the injected fluid tends to flow preferably through

The channeling of the injected fluid through these high-permeability zones and/or anomalies, besides reducing the total oil recovery, can also be responsible for the early breakthrough of the injected fluid in production wells, thus increasing the operational costs associated with

Therefore, to remedy these problems, several authors [2–6] have proposed the injection of

When there is high interfacial tension between the injected fluid and the displaced fluid, the injected fluid capacity to displace oil from the reservoir is significantly reduced, inducing bypass of residual oil by the injected fluid. When the viscosity of the injected fluid is much lower than that of the fluid being displaced, the former displaces much more easily in the porous medium, finding preferential paths and moving quickly toward the producing wells. As the injected fluid does not spread properly inside the reservoir, the oil is trapped in large bulks of reservoir rock in which displacement

Fracture networks (both natural and hydraulically induced), faults, interconnected vugular porosity, caverns, and local-

The term gelling system or gelant refers to a polymer + cross-linker solution or a microgel dispersion before any appreciable cross-linker has occurred. The term gel is used when the gelling system has attained either partial or full crosslink-

to selectively flow through the high-permeability zones or anoma-

(preferential paths), failing to recover part of the

.

• reduction of the viscous and/or capillary forces acting on the reservoir.

between the injected fluid and oil/reservoir rock is known as secondary recovery.

lary forces) imposed on the matrix flow.

recovery, two strategies may be used:

displacement efficiency of injected fluids.

high-permeability zones and/or anomalies<sup>2</sup>

gelling polymer systems<sup>3</sup>

1

2

3

does not occur.

ing maturation.

ing secondary and enhanced oil recovery methods.

ized matrix reservoir rock with permeabilities greater than 2 Da.

displaceable oil in low-permeability-unswept zones of the reservoir.

the separation, treatment, and disposal of the produced fluid (e.g. water).

lies, temporarily plugging them with a barrier (hydrogel) (**Figure 1**) in order to:

ids, and/or

70 Hydrogels


This chapter aims at presenting a review of gelling polymer systems commercially available or under academic development, with potential to control the anisotropic permeability profile of heterogeneous oil reservoirs.
