A Review of Improved-Oil-Recovery Methods in North American Unconventional Reservoirs
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In the complete paper, three stages of review have been combined to find out the applicability of the most-feasible improved-oil-recovery (IOR) methods in North American unconventional reservoirs. The study found that the integration of experimental, simulation, and pilot-test tools is the proper technique to accurately diagnose the most-feasible IOR methods in these reservoirs; these methods, as indicated by the research, include carbon dioxide (CO2), surfactant, and natural-gas injection.
Review of Potential IOR Methods
The ultratight matrix and high conductivity of natural fractures might be the two most important factors that impair success of conventional IOR methods. The authors conducted a critical review of more than 70 studies aiming to find applicability of different IOR methods in unconventional reservoirs.
Chemical Methods. Generally, this category includes three methods: surfactant, polymer, and alkaline injection. Surfactant injection has the most-promising potential to improve oil recovery in North American unconventional reservoirs. These reservoirs are well-known as intermediate-wet to oil-wet; this type of rock affinity would prevent the aqueous phase from invading the matrix to displace the oil in place. Therefore, changing wettability and enhancing water imbibition through surfactant injection would be a good strategy to improve oil recovery.
To the authors’ knowledge, there has been no study conducted to investigate the applicability of polymer- and alkaline-injection methods in these types of unconventional reservoirs. It is believed that injectivity problems are the primary reason that no investigation has been conducted on applying polymer in these reservoirs, although conformance problems are more dominant in the reported pilot tests. Also, injecting polymer into these reservoirs would plug the pore throats, which are very small in these plays. Investigation of alkaline potential in these reservoirs has also not been conducted by reported studies. This could be because there is no compatibility between this chemical agent and the mineral-composition complexity of these reservoirs.
Smart-Waterflooding Technique. Recently, intensive studies have been conducted to investigate the effect on oil recovery of flooding with low-salinity water (LSW). It has been reported in different studies that maximum oil recovery can occur at optimal concentrations of salt for brine injected in cores (laboratory work) or in the field (simulation work). Wettability alteration and interfacial tension might be the main mechanisms behind the increment in oil recovery resulting from injection of LSW. However, the underlying mechanisms for wettability alteration are still controversial. Double-layer expansion and multicomponent ion exchange might be the main mechanisms behind wettability alteration because of the addition of salt. However, most of the reviewed studies focused on conventional reservoirs with high permeability.
Miscible Gas Injection. One of the most-investigated IOR methods in unconventional liquids-rich reservoirs is gas injection. Over the last decade, different studies have reported the potential of miscible gas injection to increase oil recovery in these reservoirs. The gases investigated are CO2 and nitrogen (N2), as well as enriched natural gases. However, the majority of studies focused on CO2. CO2 can dissolve in shale oil easily and swells the oil and lowers its viscosity. CO2 has a lower miscibility pressure with shale oil than do other gases such as N2 and methane. However, the minimum miscibility pressure of CO2 in these types of oil has a range reported to be between 2,500 and 3,300 psi. The low value of the acid number reported might provide hope that CO2 injection can be applied successfully because there is not much risk of asphaltene precipitation.
Results and Discussion
Most-Appropriate IOR Technique in North American Unconventional Reservoirs. It is clear from the review that CO2, natural gas, surfactant, and LSW injection are the most-applicable IOR methods. CO2 injection is widely used in these reservoirs, according to simulation studies and experimental work. However, natural gas outperforms CO2 in pilot tests. This indicates a gap between laboratory work and pilot tests for CO2 injection. A lack of understanding of the physical mechanism for CO2 at the field scale is the main problem regarding the disappointing results from CO2 pilot tests. Generalizing the diffusion mechanism from laboratory conditions to field conditions needs to be reconsidered.
CO2-Diffusion Mechanism. The success of CO2 in shale reservoirs is dependent upon understanding its main mechanism, which is different from its mechanism in conventional reservoirs. Although most unconventional IOR studies investigated the applicability of CO2, they did not fully understand its mechanism at the field scale.
Cyclic vs. Continuous Gasflooding. Although most investigators thought that the best choice for injecting any miscible gas into these plays is by a huff-’n’-puff protocol, this belief is not always correct. Significant reported IOR that occurred in laboratory conditions and in some simulation studies was the result of the proposed or observed high diffusion rate of these miscible gases into oil molecules, thus producing the oil by a countercurrent method. However, from pilot tests, it has been shown that injectivity is not a major issue for several injectants. Furthermore, the diffusion mechanism has not been exhibited in field tests. When selecting between a cyclical protocol and continuous injection, the choice should technically depend on two main factors: the ratio of reservoir permeability to the injector/producer spacing and the diffusion mechanism.
Injectivity Problems. The main concern of all IOR methods is injection into such low-permeability rock. However, after some IOR pilot tests reported that injectivity is not always a major issue in these complex plays, some researchers wondered whether this injectivity is natural or is the result of induced fractures created by the injection process. The chance of creating injection-induced fractures in oil reservoirs increases with reduction in permeability and injection of low-viscosity fluids such as water and miscible gases. The characterization of unconventional reservoirs and injectant properties in IOR pilots indicated that there is a significant chance to induce new fractures. Several studies suggested that the injectivity improvement in pilot tests came from induced fractures. Moreover, it is not necessary to raise the injection pressure above the fracturing pressure to create fractures in these plays; it is possible to induce new fractures by pressure depletion, thermal effects, or plugging effects.
Limited Surfactant-Imbibition Rate. It has been shown that surfactant imbibition cannot proceed more than a few meters into ultralow-permeability formations. However, surfactant can penetrate deeper in the case of reservoirs with highly intensive natural fractures, which increase the contact area between the injected surfactant and the reservoir. The most-productive wells in the primary-recovery stage are the best candidates for surfactant applications because of the high chance of existing intensive natural fractures. However, the combined injection of low-salinity brine and surfactant has been reported as the best strategy to increase imbibition rate.
Thermal Methods. It is clear that oil viscosity in these reservoirs is very low. Typically, they contain light oil with reservoir temperatures of 240°F. Therefore, there is no motivation to investigate the applicability of thermal methods in shale reservoirs because the conventional main concern of these methods is with viscous and heavy oils.
Microbial Methods. The general goals of microbial methods include generating biopolymer and biosurfactant at appropriate conditions. Generating biosurfactant might have potential in altering wettability of these formations. However, nutrient availability might be a major obstacle. Moreover, to the authors’ knowledge, no study has been conducted to investigate generation of biosurfactant in shale reservoirs.
- Reviewing unconventional-reservoir properties indicated that wettability, heterogeneity, and depletion are the main targets of IOR methods.
- This review found a wide gap between conclusions of microscopic studies and those of field-scale reports on different IOR methods.
- CO2, natural gas, surfactant, and LSW injection are the most-applicable IOR methods in shale reservoirs.
- Experimental studies supported the diffusion mechanism for CO2, while pilot tests did not provide any clear indication about this mechanism at the field scale.
- Pilot tests generally supported the potential of natural-gas-injection techniques. However, CO2 may not be as beneficial in huff-’n’-puff as in the continuous-flooding process if it has been shown that the kinetics of the oil-recovery process in productive areas of these reservoirs is too fast or that the CO2-diffusion rate under field conditions is too slow.
- The miscible-gas cyclic process under laboratory conditions should not be considered for the field unless the relationship between the diffusion mechanism at field scale and that at laboratory scale is well-understood. Using results from a laboratory cyclic process for matching in numerical simulation is a misleading way to scale up the results to the field scale.
- Although IOR pilot tests indicated no problems in injectivity, all evidence suggests an improvement in injectivity resulting from injection-induced fractures.
A Review of Improved-Oil-Recovery Methods in North American Unconventional Reservoirs
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