performance. This suggests that CO2 may be injected into tight reservoirs for both eoR and co2 storage.
Similar to EOR, recovery of natural gas from tight rocks including coal and shale may be enhanced by CO2 injection. In coal beds and gas shales where a significant volume of natural gas is adsorbed to the solid surface, injection of CO2 and/or mixtures of CO2 and N2 increases ultimate recovery of natural gas while simultaneously leaving CO2 adsorbed to the solid in place of natural gas (e.g., Jessen et al., 2008). Injection of CO2 also helps to establish pressure gradients that drive natural gas toward producers. In this case, the microscopic displacement is miscible and stable. Displacement stability is achieved because CO2 viscosity, while low, is greater than methane.
Improving resource recovery from low-permeability resources is strategically important. For instance, it is estimated that about one half of the worldwide petroleum resource is found in fractured siliceous and carbonaceous formations, yet fractured resources make up only roughly 20 % of reserves (Saidi, 1983).
As a greater number of reservoirs have matured and are reaching abandonment, recovery options are needed for more difficult to produce hydrocarbon settings.
Examples of sizeable low-permeability hydrocarbon resources include the Monterey Shale (CA, USA), West Texas (USA) Carbonates, the North Sea Chalks, and the Asmari Limestone (Iran).
To illustrate the potential and difficulties of EOR in low-permeability resources, we present the results of a series of experiments using low permeability (0.02–1.3 mD), medium porosity (30–40 %) siliceous shale reservoir core samples. Cores are initially saturated with either: live oil, depleted to a pressure of 200–300 psi; or dead oil brought to miscible conditions;
followed by CO2 injection at pressures proceeding from immiscible to CO2 miscible conditions. In these experiments, two gas injection modes were used:
co2 flow across one face of the core (countercurrent flow) which intends to account for the diffusive transfer mechanism; and CO2 flow along the length of the core (cocurrent injection), where convective displacement was also expected. The experimental set-up was monitored using X-ray computed tomography that helped to visualize phase flow and distribution during the processes.
Results reported in this work include imaging techniques that provide images representative of the distribution and connectivity of gas along the central axis of the core sample. The images show CO2 distribution maps obtained by image reconstruction where the light shadowed areas indicate greater concentration or saturation of CO2 for miscible and immiscible tests, respectively.
For the immiscible tests, CO2 injection was preceded by pressure depletion that aimed to reproduce the initial conditions of a secondary recovery process.
The core was repressurized in stages to simulate an increase in reservoir
pressure. Sample resulting images for such tests are shown in Fig. 4.7. An increasing CO2 saturation becomes apparent as the CO2 injection progresses.
The last stage shows an average CO2 saturation of 0.5–0.6 PV. It can also be observed that the co2 roughly follows the pathways established by the gas produced during the pressure depletion stage.
The study also offers images associated with CO2 injection under miscible conditions, like those shown in Fig. 4.8. According to these laboratory experiences, the incremental oil recovery potential for both immiscible and miscible CO2 injection seems significant.
In particular, the incremental oil recovery caused by the immiscible co2 injection ranged from 0–10 % for countercurrent flow mode and from 18–25 % for cocurrent flow mode, totaling 18–35 % of oil recovery. For the miscible injection, countercurrent flow yielded a 54 % oil recovery and the cocurrent flow allowed an additional 39 %, adding up to a total oil recovery of 93 % OOIP.
Nevertheless, oil recovery potential by immiscible CO2 injection into siliceous shale rock is challenged by low permeability, rock heterogeneities, distribution of oil within the rock matrix, but it is aided by the presence
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4.7 Gas saturation maps for depletion/immiscible CO2 injection. Numbers below images indicate pressure in psi.
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of continuous gas pathways that allow CO2 penetration into the matrix.
Miscibility seemed to be achieved under multiple contact regime, and it was able to overcome the limitations faced by the immiscible process as demonstrated by the significant increase in oil recovery obtained under both countercurrent and cocurrent injection methods.
4.4.1 Implications on modeling of the carbon dioxide (CO2) injection process
In the modeling of a fractured low-permeability system subject to miscible CO2 injection, it is necessary to account for the effects associated with immiscible and miscible displacement that have been previously described, such as the oil
CO2 fraction maps for countercurrent miscible injection
CO2 fraction maps for cocurrent miscible injection First cycle
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4.8 Pure CO2 distribution maps for miscible CO2 injection.
swelling, viscosity, and interfacial tension reduction, among others. The use of a compositional simulator allows the definition of pseudoternary diagrams that facilitate the interpretation of the miscible processes, also accounting for the different components in each phase with more rigorous equation of state. Therefore, a good compositional analysis of the oil becomes necessary as an input. Fractures can be modeled by creating a high-permeability/high- porosity area on the grid, but there are options to model them using dual porosity/dual permeability techniques.