Modeling Self-Sealing Mechanisms in Fractured Carbonates Induced by CO2 Injection in Saline Aquifers.

In the future, there will be competition among natural gas, CO2, and hydrogen for suitable geological storage sites. Therefore, it is crucial to evaluate all of the potential storage options. One promising option is the utilization of fractured carbonate rocks, which offer significant opportunities for gas sequestration in depleted reservoirs and saline aquifers. The objective of this study is to assess the feasibility of using carbonate matrix rocks in saline aquifers for carbon capture and storage (CCS) projects. Although carbonate reservoirs are currently not ranked highly for carbon storage due to the risk of CO2 leakage, their matrix rock with reactive minerals like calcite and dolomite, along with the possibility of natural fractures, presents an interesting opportunity. This research proposes a reassessment of the role of fractures, which are typically viewed as a risk factor, within a novel and integrated context. It combines geochemical modeling with numerical models that incorporate two distinct density levels of natural fractures. The interactions between the carbonate matrix, the formation brine, and the injected CO2 can lead to water vaporization and the deposition of evaporite minerals, known as the halite scale, within the porous medium. These minerals can be transported within highly conductive fractures that possess a permeability 100 times greater than the matrix. The study findings indicate that the fractures become filled, creating a natural seal that prevents CO2 leakage through what was previously considered a potential pathway in both models and different initial pH values. Furthermore, the results demonstrate the formation of secondary minerals through the reaction of CO2 and its aqueous counterparts with rock matrix minerals. These minerals, including Dawsonite, are then deposited within fracture apertures, compensating for the dissolution of calcite from the matrix and reducing the risk of enhanced fracture conductivity during CCS operations. The deposition of halite scales in initially acidic-brine saturated aquifers and/or Dawsonite scales in initially alkaline-brine saturated aquifers serves to partially counterbalance the permeability enhancement resulting from calcite dissolution. This phenomenon makes carbonate rocks a more secure option and highlights their potential suitability for CCS projects. The existence of these scales acts as a protective barrier, reducing the risk of increased permeability and enhancing the integrity of the storage reservoir.

A Comprehensive Numerical Model for Simulating Fluid Transport in Nanopores.

Since a large amount of nanopores exist in tight oil reservoirs, fluid transport in nanopores is complex due to large capillary pressure. Recent studies only focus on the effect of nanopore confinement on single-well performance with simple planar fractures in tight oil reservoirs. Its impacts on multi-well performance with complex fracture geometries have not been reported. In this study, a numerical model was developed to investigate the effect of confined phase behavior on cumulative oil and gas production of four horizontal wells with different fracture geometries. Its pore sizes were divided into five regions based on nanopore size distribution. Then, fluid properties were evaluated under different levels of capillary pressure using Peng-Robinson equation of state. Afterwards, an efficient approach of Embedded Discrete Fracture Model (EDFM) was applied to explicitly model hydraulic and natural fractures in the reservoirs. Finally, three fracture geometries, i.e. non-planar hydraulic fractures, non-planar hydraulic fractures with one set natural fractures, and non-planar hydraulic fractures with two sets natural fractures, are evaluated. The multi-well performance with confined phase behavior is analyzed with permeabilities of 0.01 md and 0.1 md. This work improves the analysis of capillarity effect on multi-well performance with complex fracture geometries in tight oil reservoirs.

A Comprehensive Model for Real Gas Transport in Shale Formations with Complex Non-planar Fracture Networks.

A complex fracture network is generally generated during the hydraulic fracturing treatment in shale gas reservoirs. Numerous efforts have been made to model the flow behavior of such fracture networks. However, it is still challenging to predict the impacts of various gas transport mechanisms on well performance with arbitrary fracture geometry in a computationally efficient manner. We develop a robust and comprehensive model for real gas transport in shales with complex non-planar fracture network. Contributions of gas transport mechanisms and fracture complexity to well productivity and rate transient behavior are systematically analyzed. The major findings are: simple planar fracture can overestimate gas production than non-planar fracture due to less fracture interference. A "hump" that occurs in the transition period and formation linear flow with a slope less than 1/2 can infer the appearance of natural fractures. The sharpness of the "hump" can indicate the complexity and irregularity of the fracture networks. Gas flow mechanisms can extend the transition flow period. The gas desorption could make the "hump" more profound. The Knudsen diffusion and slippage effect play a dominant role in the later production time. Maximizing the fracture complexity through generating large connected networks is an effective way to increase shale gas production.

Simulation Study of CO2-EOR in Tight Oil Reservoirs with Complex Fracture Geometries.

The recent development of tight oil reservoirs has led to an increase in oil production in the past several years due to the progress in horizontal drilling and hydraulic fracturing. However, the expected oil recovery factor from these reservoirs is still very low. CO2-based enhanced oil recovery is a suitable solution to improve the recovery. One challenge of the estimation of the recovery is to properly model complex hydraulic fracture geometries which are often assumed to be planar due to the limitation of local grid refinement approach. More flexible methods like the use of unstructured grids can significantly increase the computational demand. In this study, we introduce an efficient methodology of the embedded discrete fracture model to explicitly model complex fracture geometries. We build a compositional reservoir model to investigate the effects of complex fracture geometries on performance of CO2 Huff-n-Puff and CO2 continuous injection. The results confirm that the appropriate modelling of the fracture geometry plays a critical role in the estimation of the incremental oil recovery. This study also provides new insights into the understanding of the impacts of CO2 molecular diffusion, reservoir permeability, and natural fractures on the performance of CO2-EOR processes in tight oil reservoirs.