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The successful commercial development of high-quality middle-shallow and middle-deep shale gas in the Sichuan Basin marks a significant achievement. With the escalating energy demand, attention has shifted toward exploring and exploiting deep-buried, low-quality middle-shallow, and middle-deep shale gas reservoirs in China. This shift necessitates advancements in geological evaluation and engineering design. Here, the key issues related to sweet spot identification in shale gas reservoirs are introduced, and three correlated parameters (gas-in-place, microstructure, and permeability) are concisely overviewed. Numerous efforts and advances have been dedicated to characterizing these parameters in recent years, attempting to reveal the underlying mechanisms and identify the appropriate evaluation methods. However, challenges persist, and potential improvement opportunities are outlined here to provide insights for researchers.

This study aims to numerically assess the impact of wettability and relative permeability hysteresis on hydrogen losses during underground hydrogen storage (UHS) and explore strategies to minimize them by using an appropriate cushion gas. The research utilizes the Carlson model to calculate the saturation of trapped gas and the Killough model to account for water hysteresis. By incorporating the Land coefficient based on laboratory-measured data for a hydrogen/brine system, our findings demonstrate a significant influence of gas hysteresis on the hydrogen recovery factor when H2 is used as a cushion gas. The base model, which neglects the hysteresis effect, indicates a recovery factor of 78% by the fourth cycle, which can be improved. In contrast, the modified model, which considers hysteresis and results in a trapped gas saturation of approximately 17%, shows a hydrogen recovery factor of 45% by the fourth cycle. Additionally, gas hysteresis has a notable impact on water production, with an observed 12.5% increase in volume in the model that incorporates gas hysteresis. Furthermore, optimization of the recovery process was conducted by evaluating different cushion gases such as CO2, N2, and CH4, with the latter proving to be the optimal choice. These findings enhance the accuracy of estimating the H2 recovery factor, which is crucial for assessing the feasibility of storage projects.

CO2 sequestration is considered one of the main pillars in achieving the ongoing decarbonization efforts. A myriad of CO2 sequestration projects targeted sandstone reservoirs since carbonate reservoirs appeared to be unpropitious due to their geological complexity and unfavorable mineralogy and properties. This study investigates CO2 sequestration potential in a carbonate saline aquifer while considering various geological complexities by capitalizing on numerical simulation. A synthetic anticline reservoir model examined the optimum well location and landing zone for CO2 sequestration. Additionally, the model evaluated the role of natural fractures in the migration path of CO2 plume and geochemical reactions throughout the storage process. The study demonstrates that placing the injection well away from the top of the structure in a low-dip region while injecting in the bottom interval would yield the optimum design. After applying a plethora of analyses, geological complexity could impede the migration path of CO2 but eventually produce a similar path when injected in a similar region. The geochemical interactions between the injected CO2 and reservoir fluids and minerals reduce the free and trapped CO2 quantities by dissolving calcite and precipitating dolomite. Furthermore, natural fractures impact the CO2 quantities during early times only when the fractures cross the top layers. Similarly, the CO2 migration differs due to the higher permeability within the fractures, resulting in slightly different CO2 plumes. Consequently, the role of natural fractures should be limited in carbon storage projects, specifically if they do not cross the top of the reservoir. This study reflects a unique perspective on sequestering CO2 while capturing the roles of natural fractures and well placement in depicting the migration path of the CO2 plume. A similar systematic workflow and holistic approach can be utilized to optimize the subsurface storage process for potential formations.

Orphaned and abandoned wells in the United States pose significant environmental risks, including methane emissions, groundwater contamination, and ecosystem degradation. These wells also threaten the integrity of carbon capture and storage (CCS) projects by providing potential leakage pathways for stored CO2, particularly if they lack proper plugging and well integrity. Although the exact number of orphaned and abandoned wells is uncertain due to poor historical documentation, recent estimates suggest there could be as many as 3.9 million such wells nationwide, emitting approximately 3.2 Teragram (Tg) of methane annually. This study investigates the distribution of orphaned and abandoned wells across the United States, presenting new estimates of documented wells and exploring their methane emissions. Through state-level data analysis, the number of documented orphan wells is estimated to be significantly higher than previously reported. A machine learning model, specifically a RandomForestRegressor, was employed to predict the locations of potential orphan wells, enhancing the ability to target monitoring and remediation efforts.

The efficient use of depleted gas reservoirs for hydrogen storage is a promising solution for transitioning to carbon-neutral energy sources. This study proposes an analytical framework for estimating hydrogen storage capacity using a comprehensive material balance approach in depleted gas reservoirs. The methodology integrates basic reservoir engineering principles with thermodynamic considerations to accurately estimate hydrogen storage capacity in both volumetric drive and water drive gas reservoirs through an iterative approach based on mass conservation and the real gas law. This framework is implemented in a Python program, using the CoolProp library for phase behavior modeling with the Soave–Redlich–Kwong (SRK) equation of state. The methodology is validated with numerical simulations of a tank model representing the two reservoir drive mechanisms discussed. Also, a case study of a synthetic complex reservoir demonstrates the applicability of the proposed approach to real-world scenarios. The findings suggest that precise modeling of fluid behavior is crucial for reliable capacity estimations. The proposed analytical framework achieves an impressive accuracy, with deviations of less than 1% compared to estimates obtained through numerical simulations. Insights derived from this study can significantly contribute to the assessment of strategic decisions for utilizing depleted gas reservoirs for hydrogen storage.

The Embedded Discrete Fracture Model (EDFM) has emerged as a prominent piece of technology used for embedding the hydraulic behavior of rock joints in reservoir numerical models. This paper critically reviews its fundamentals, the latest developments, and opportunities for further research. The literature is extensive regarding novel algorithms attempting to reach more accurate and computationally effective estimates. While hydraulic fracture models seem suitable for their purposes, their assumptions might be excessively simplistic and unrealistic when assessing naturally fractured reservoirs. The paper begins by examining fractures as physical characteristics and the key mechanisms to be considered when integrating them into numerical flow simulators. The use of the EDFM technique shows promise for simulating capillary continuity and buoyancy effects in multiphase and multicomponent cases. However, there are significant limitations that hinder its widespread field-scale adoption for reservoir performance evaluation. In this regard, the lack of public-domain realistic benchmarks to validate and compare the potential of each method reinforces the difficulties of performing broader applications of the EDFM techniques in large-scale models.

Geological Carbon Storage (GCS) involves storing CO2 emissions in geological formations, where safe containment is challenged by structural and stratigraphic trapping and caprock integrity. This study investigates flow and geomechanical responses to CO2 injection based on a Brazilian offshore reservoir model, highlighting the critical interplay between rock properties, injection rates, pressure changes, and ground displacements. The findings indicate centimeter-scale ground uplift and question the conventional selection of the wellhead as a monitoring site, as it might not be optimal due to the reservoir’s complexity and the nature of the injection process. This study addresses the importance of comprehensive sensitivity analyses on geomechanical properties and injection rates for advancing GCS by improving monitoring strategies and risk management. Furthermore, this study explores the geomechanical effects of modeling flow in the caprock, highlighting the role of pressure dissipation within the caprock. These insights are vital for advancing the design of monitoring strategies, enhancing the predictive accuracy of models, and effectively managing geomechanical risks, thus ensuring the success of GCS initiatives.

Conventional Carbon Capture and Storage (CCS) operations use the direct injection of CO2 in a gaseous phase from the surface as a carbon carrier. Due to CO2 properties under reservoir conditions with lower density and viscosity than in situ brine, CO2 flux is mainly gravity-dominated. CO2 moves toward the top and accumulates below the top seal, thus reinforcing the risk of possible leakage to the surface through unexpected hydraulic paths (e.g., reactivated faults, fractures, and abandoned wells) or in sites without an effective sealing caprock. Considering the risks, the potential benefits of the interplay between CO2 and an aqueous solution of formate ions (HCOO¯) were evaluated when combined to control CO2 gravity segregation in porous media. Three combined strategies were evaluated and compared with those where either pure CO2 or a formate solution was injected. The first strategy consisted of a pre-flush of formate solution followed by continuous CO2 injection, and it was not effective in controlling the vertical propagation of the CO2 plume. However, the injection of a formate solution slug in a continuous or alternated way, simultaneously with the CO2 continuous injection, was effective in slowing down the vertical migration of the CO2 plume and keeping it permanently stationary deeper than the surface depth.

This study used numerical simulations of CO2 storage to identify the benefits of horizontal wells for geological carbon storage, such as enhancing CO2 trapped in porous media due to relative permeability and capillary hysteresis. Two injection schemes were tested: one using a vertical injector and the other employing a horizontal well. The results revealed two main findings. Firstly, the horizontal injection well effectively prevented or minimized CO2 penetration into the caprock across various sensitivity scenarios and over a thousand years of CO2 redistribution. Secondly, horizontal wells provided a safe approach to trapping CO2, increasing its entrapment as a residual phase by up to 19% within the storage site. This, in turn, reduced or prevented any unexpected events associated with CO2 leakage through the caprock. Additionally, the paper proposes a practical method for designing the optimal length of a horizontal well. This method considers a combination of two parameters: the additional CO2 that can be trapped using a horizontal well and the gravity number. In the case of the reservoir model of this study, a horizontal branch with a length of 2000 m was found to be the most effective design in enhancing CO2 entrapment and reducing CO2 buoyancy.

Three different reservoir simulators that utilize both two-phase and three-phase microemulsion phase behavior models are used to model surfactant–polymer flooding to determine and compare their results. Different models are used in each simulator to describe the physical behavior of injected chemicals into the reservoir, which raises the need to benchmark their results. The physical behavior models of polymer and surfactant were constructed and verified on a 1D scale reservoir model and further verified in a 3D model. Finally, simulations were conducted in a field-scale reservoir containing 680,400 grids, where results were compared and analyzed. The 1D and 3D model results suggest an excellent match between the different simulators in modeling surfactant–polymer floods. In the case of the field-scale model, the simulators matched in terms of oil recovery and total volumes produced and injected, while having similar reservoir pressure profiles but with significant discrepancies in terms of injected and produced chemicals. These results indicate that despite the differences in the calculated injected and produced chemicals due to the different models in the simulators, the effect of surfactant–polymer floods on oil recovery, total injected and produced fluids, and average pressure profiles can be comparably modeled in all of the three simulators.

On account of low matrix permeability and porosity, the fluid phase behavior in tight oil reservoirs significantly differs from the conventional plays, which increases the challenges of evaluating the well performance and providing reliable production prediction. One of the most important efforts is to investigate the behavior of unconventional well gas-to-oil ratio (GOR). The growth trend of GOR is always considered as a principal reference to modify the production strategies and enhance the well productivity. In this paper, long-term GOR (20 years) behavior of an unconventional well model was evaluated by a set of comprehensive sensitivity studies. This model’s dimensions and reservoir properties are based on information of the Altamont-Bluebell field in the Uinta Basin. The simulation results established a general framework for interpreting the GOR behavior. Key drivers such as completion designs, reservoir, and fracture properties are investigated. This study provides some key insights into the GOR behaviors, such as the high sensitivity of the hydraulic fracture properties, including fracture conductivity and effective fracture half-length. The GOR behavior could be considerably different on various conductivity values or fracture lengths, resulting from the conductivity impact of phase movement and the pressure transition along the fracture. The fracture design factors like drawdown scenario and cluster spacing also play indispensable roles in impacting the GOR response, where a less aggressive drawdown rate can help to delay the GOR increase at an early stage; a widening spacing also can mitigate the rise of GOR and keep it at low value during the whole production period. The impact from natural fractures is also examined and discussed for the first time, including the effect of natural fracture numbers and conductivity, where the latter variable is considered as a more effective contributor to the GOR prediction. The findings presented in this work promote a better understanding of the GOR behaviors in tight oil reservoirs. Results and discussion in this paper allow a more accurate forecasting production to improve the reservoir management efficiency and provide multiple valuable insights to guide the field development in future projects.

Hydrogen (H2) is an attractive energy carrier to move, store, and deliver energy in a form that can be easily used. Field proven technology for underground hydrogen storage (UHS) is essential for a successful hydrogen economy. Options for this are manmade caverns, salt domes/caverns, saline aquifers, and depleted oil/gas fields, where large quantities of gaseous hydrogen have been stored in caverns for many years. The key requirements intrinsic of a porous rock formation for seasonal storage of hydrogen are: adequate capacity, ability to contain H2, capability to inject/extract high volumes of H2, and a reliable caprock to prevent leakage. We have carefully evaluated a commercial non-isothermal compositional gas reservoir simulator and its suitability for hydrogen storage and withdrawal from saline aquifers and depleted oil/gas reservoirs. We have successfully calibrated the gas equation of state model against published laboratory H2 density and viscosity data as a function of pressure and temperature. Comparisons between the H2, natural gas and CO2 storage in real field models were also performed. Our numerical models demonstrated more lateral spread of the H2 when compared to CO2 and natural gas with a need for special containment in H2 projects. It was also observed that the experience with CO2 and natural gas storage cannot be simply replicated with H2.

A vug porosity system, in addition to a matrix, is also the target rocks for the acidizing. In this work, the acidizing process in two typical core-scale separate-vug porosity systems is studied in detail. Numerous cases are conducted to discuss a parametric study on the acidizing process and hydraulic behavior. Results indicate that the presence of vug reduces the pore volume of acid solution consumed to achieve a breakthrough, which is consistent with experimental observations. Increasing the vug diameter and porosity decreases pore volume to breakthrough both for a vugular carbonate rock and isolated vug carbonate rock. In comparison, the acid mass does not change a lot. Typical dissolution patterns can also be observed in the acidizing process when a vug exists. Compared to matrix dissolution patterns, the presence of vug induces wormhole to pass through the vug region.

An appropriate well spacing plan is critical for the economic development of shale gas reservoirs. The biggest challenge for well spacing optimization is interpreting the subsurface uncertainties associated with hydraulic and natural fractures. Another challenge is the existence of complex natural fractures. This work applied an integrated well spacing optimization workflow in shale gas reservoirs of the Sichuan Basin in China with both hydraulic and natural fractures. The workflow consists of five components: data preparation, reservoir simulation, estimated ultimate recovery (EUR) analysis, economic calculation, and well spacing optimization. Firstly, the multiple realizations of thirteen uncertain parameters of matrix and fractures, including matrix permeability and porosity, three relative permeability parameters, hydraulic fracture height, half-length, width, conductivity, water saturation, and natural fracture number, length, and conductivity, were captured by the assisted history matching (AHM). The fractures were modeled by the embedded discrete fracture model (EDFM) accurately and efficiently. Then, 84 AHM solutions combining with five well spacing scenarios from 517 ft to 1550 ft would generate 420 simulation cases. After reservoir simulation of these 420 cases, we forecasted the long-term gas production for each well spacing scenario. Gas EUR degradation and well interference would imply the critical well spacing. The net present value (NPV) for all scenarios would be calculated and trained by K-nearest neighbors (KNN) proxy to better understand the relationship between well spacing and NPV. In this study, the optimum well spacing was determined as 793 ft, corresponding with a maximum NPV of 18 million USD, with the contribution of hydraulic fractures and natural fractures.

To better understand the roles natural fractures play in porous media, an embedded discrete fracture model and streamline modeling method were combined to model natural fractures and compute the flow trajectory and time of fluid in matrix and fractures systems. The effects of fracture conductivity, number of fractures and fracture locations on fluid flow trajectory and time were examined through analyzing the differences in water breakthrough time and sweeping volume of reservoirs with different fracture networks. When other conditions are the same, compared with homogeneous reservoir without fractures, the fractured reservoir has water breakthrough time 30% sooner and swept volume 10% smaller. Although increase of single fracture can lead to faster water breakthrough and smaller swept volume, adding more fractures wouldn't necessarily reach the same effect. The effect of water flooding is also related to the strike and position of fractures. Fractures in different strikes and positions can result in 20% discrepancy in water breakthrough time and 9% gap in swept volume. The shorter the fracture, the less its effect on fluid flow trajectory and time will be. The position of fracture has a strong influence on sweeping efficiency, and the change of one fracture position could bring about 1% variation in swept volume. Key words: multiphase flow, water flooding, embedded discrete fracture model, streamline simulation, natural fracture

Waterflooding remains the most commonly used method to improve oil recovery. Although the injected brine type is mainly dependent on its availability, few of its characteristics can be controlled during project design. Published laboratory work indicates that the adjustment of injected brine composition can cause an increase in oil production by wettability alteration. This research objective is to propose a novel four-step framework for modeling improved oil recovery by Engineered Water Injection from laboratory to numerical simulation for carbonate formations. We use a geochemical-based model that estimates contact angles to predict wettability alteration. The steps are (1) screening criteria, (2) geochemical evaluation, (3) wettability alteration modeling, and (4) coreflood history-match. We validate our framework by conducting history-match simulations of Brazilian Pre-Salt corefloods. Incremental oil recovery factors are between 5 to 11%, consistent with those reported during experiments. The reduction in residual oil saturation varied from 3 to 5%. This work is a new systematic procedure to model oil recovery using a comprehensive approach that is fundamental to understanding the underlying wettability alteration mechanisms by Engineered Water Injection.

In order to account for big uncertainties such as well interferences, hydraulic and natural fractures’ properties and matrix properties in shale gas reservoirs, it is paramount to develop a robust and efficient approach for well spacing optimization. In this study, a novel well spacing optimization workflow is proposed and applied to a real shale gas reservoir with two-phase flow, incorporating the systematic analysis of uncertainty reservoir and fracture parameters. One hundred combinations of these uncertainties, considering their interactions, were gathered from assisted history matching solutions, which were calibrated by the actual field production history from the well in the Sichuan Basin. These combinations were used as direct input to the well spacing optimization workflow, and five “wells per section” spacing scenarios were considered, with spacing ranging from 157 m (517 ft) to 472 m (1550 ft). An embedded discrete fracture model was used to efficiently model both hydraulic fractures and complex natural fractures non-intrusively, along with a commercial compositional reservoir simulator. Economic analysis after production simulation was then carried out, by collecting cumulative gas and water production after 20 years. The net present value (NPV) distributions of the different well spacing scenarios were calculated and presented as box-plots with a NPV ranging from 15 to 35 million dollars. It was found that the well spacing that maximizes the project NPV for this study is 236 m (775 ft), with the project NPV ranging from 15 to 35 million dollars and a 50th percentile (P50) value of 25.9 million dollars. In addition, spacings of 189 m (620 ft) and 315 m (1033 ft) can also produce substantial project profits, but are relatively less satisfactory than the 236 m (775 ft) case when comparing the P25, P50 and P75 values. The results obtained from this study provide key insights into the field pilot design of well spacing in shale gas reservoirs with complex natural fractures.

In this study, the non-intrusive embedded discrete fracture model (EDFM) in combination with the Oda method are employed to characterize natural fracture networks fast and accurately, by identifying the dominant water flow paths through spatial connectivity analysis. The purpose of this study is to present a successful field case application in which a novel workflow integrates field data, discrete fracture network (DFN), and production analysis with spatial fracture connectivity analysis to characterize dominant flow paths for water intrusion in a field-scale numerical simulation. Initially, the water intrusion of single-well sector models was history matched. Then, resulting parameters of the single-well models were incorporated into the full field model, and the pressure and water breakthrough of all the producing wells were matched. Finally, forecast results were evaluated. Consequently, one of the findings is that wellbore connectivity to the fracture network has a considerable effect on characterizing the water intrusion in fractured gas reservoirs. Additionally, dominant water flow paths within the fracture network, easily modeled by EDFM as effective fracture zones, aid in understanding and predicting the water intrusion phenomena. Therefore, fracture clustering as shortest paths from the water contacts to the wellbore endorses the results of the numerical simulation. Finally, matching the breakthrough time depends on merging responses from multiple dominant water flow paths within the distributions of the fracture network. The conclusions of this investigation are crucial to field modeling and the decision-making process of well operation by anticipating water intrusion behavior through probable flow paths within the fracture networks.

Here we present an efficient and robust calculation scheme for two-phase, one-dimensional (1D) steady state steam condensation in the presence of CO2, based on conservation rules and thermodynamic phase relations. The mixing of fluids and phases is assumed to be homogeneous. Heat transfer is considered between the fluids and the ambient formations. For convenience, state equations are presented in terms of the entropy changes of individual phases, and the simple additive rule for the mixture. To monitor phase changes, the phase rule is checked. This investigation has practical significance for steam injection operation and long-distance pipe flow applications in the geothermal and mid- and up-stream oil and gas industries.