Unconventional Formations Research Articles

Making my voice and owning its future

This article explores disabled experience and the future of technologies relating to augmentative and alternative communication (AAC). This field includes people’s use of AAC devices, typically in combination with other...

Three-dimensional physical experimental study on mechanisms and influencing factors of CO2 huff-n-puff and flooding process in shale reservoirs after fracturing

Carbon dioxide (CO2) capture and geological storage technology is a promising strategy for enhancing oil and gas production and mitigating climate change in unconventional formations. In shale reservoirs, production decline is rapid under volumetric fracturing development. Currently, CO2 injection and huff-n-puff techniques are cost-effective methods to boost shale oil recovery. However, traditional huff-n-puff techniques are limited in capturing reservoir heterogeneity and intricate fracture conditions. This study employed a three-dimensional physical experimental apparatus to explore CO₂ huff-n-puff dynamics across six distinct fracture patterns. By implementing a real-time monitoring system with multiple pressure points, the study elucidated the impacts of varying fracture penetration levels and spacing on dynamic pressure wave patterns, mobilization extent, and development outcomes during CO2 huff-n-puff. The results demonstrate that fractures substantially improve CO₂ huff-n-puff efficiency in shale reservoirs compared to a seamless model, with Model 6 achieving the highest recovery rate of 42.38%. As fracture penetration increases, CO₂ dynamic coverage expands. However, full penetration leads to preferential flow through fractures, reducing matrix contact and diminishing huff-n-puff efficiency. Reduced fracture spacing enlarges the well's control domain, amplifies CO2 huff-n-puff dynamic coverage area, and increases oil production and recovery rate. Conversely, decreasing fracture spacing accelerates oil and gas displacement rates, leading to higher economic expenses. The study concludes that 2/3 fracture penetration in five fractures offers the most efficient recovery method. For a 500 m horizontal well, optimal fracture spacing is recommended at 125 m, with a fracture length of 145.8 m for a well spacing of 417 m.

Modified Low-Field NMR Method for Improved Pore Space Analysis in Tight Fe-Bearing Siliciclastic and Extrusive Rocks

Abstract Understanding the filtration and storage properties of tight reservoirs is crucial for efficient resource exploitation, particularly in unconventional formations. This study presents two low-field nuclear magnetic resonance (LF-NMR) techniques: standard cut-off and modified differential approaches combined with mercury injection capillary pressure (MICP) and X-ray diffraction (XRD) studies to evaluate porosity and pore size distribution (PSD) in such formations. The differential technique involves subtracting the dry sample signal from a 100% water-saturated one, allowing the chemically bound water compound to be eliminated and facilitating PSD analysis. Through the application of the percolation theory, we established a power–law relationship between LF-NMR transverse relaxation time (T2) and MICP pore-throat diameter, enabling the derivation of PSD and pseudo capillary pressure curves. Our methodology was validated on a sample set representing tight sandstones, conglomerates, and extrusive rocks with high clay and iron mineral content, demonstrating the superior accuracy of the modified differential method in estimating effective porosity and absolute PSD in comparison with the standard approach. While the use of the percolation theory in PSD conversion was successful for rocks with unimodal distributions, it often failed for rocks with larger voids. The study also revealed that the relationship between the LF-NMR transverse relaxation times and MICP pore sizes is both nonlinear and challenging to describe with a universal equation, especially in the presence of para- and ferro-magnetic elements in the rock matrix. Despite obstacles to the complete elimination of the influence of these minerals on the T2 distribution, employing the modified differential LF-NMR method significantly mitigated this effect and offered a precise and noninvasive way of characterizing the petrophysical properties of tight reservoir rocks. Consequently, our studies offer a significant step toward a more precise assessment of pore structures in unconventional reservoirs that could be translated into more efficient strategies for locating geothermal heat and hydrocarbon resources.

High-Yield Synthesis Route, Post-Synthesis Treatment, and Insights into the Photoluminescence and Magnetic Properties of Tricopper(I) Melaminate Cu3(C3N6H3).

A novel and more efficient synthesis of Cu3(C3N6H3) is presented through a salt-metathesis reaction using copper(I) chloride and sodium hydrogen cyanamide. This synthesis yields a melaminate trianion through the cyclotrimerization of (HNCN)- ions, offering an alternative route to the deprotonation of melamine for synthesizing melaminate. The reaction is analyzed via differential thermal analysis. After the unconventional formation of this MOF-like structure by solid-state reaction, this material still requires treatment via solvent exchange and vacuum drying due to the presence of a host molecule inside the channels of the structure. The process and the impact of the treatment of Cu3(C3N6H3) on its XRD pattern are thoroughly discussed. Additionally, results from stability, NMR and infrared spectroscopy, and thermogravimetric analysis. Finally, photoluminescence and magnetic studies are conducted to evaluate their potential as a functional material.

Fracture Evolution during CO2 Fracturing in Unconventional Formations: A Simulation Study Using the Phase Field Method

With the introduction of China’s “dual carbon” goals, CO2 is increasingly valued as a resource and is being utilized in unconventional oil and gas development. Its application in fracturing operations shows promising prospects, enabling efficient extraction of oil and gas while facilitating carbon sequestration. The process of reservoir stimulation using CO2 fracturing is complex, involving coupled phenomena such as temperature variations, fluid behavior, and rock mechanics. Currently, numerous scholars have conducted fracturing experiments to explore the mechanisms of supercritical CO2 (SC-CO2)-induced fractures in relatively deep formations. However, there is relatively limited numerical simulation research on the coupling processes involved in CO2 fracturing. Some simulation studies have simplified reservoir and operational parameters, indicating a need for further exploration into the multi-field coupling mechanisms of CO2 fracturing. In this study, a coupled thermo-hydro-mechanical fracturing model considering the CO2 properties and heat transfer characteristics was developed using the phase field method. The multi-field coupling characteristics of hydraulic fracturing with water and SC-CO2 are compared, and the effects of different geological parameters (such as in situ stress) and engineering parameters (such as the injection rate) on fracturing performance in tight reservoirs were investigated. The simulation results validate the conclusion that CO2, especially in its supercritical state, effectively reduces reservoir breakdown pressures and induces relatively complex fractures compared with water fracturing. During CO2 injection, heat transfer between the fluid and rock creates a thermal transition zone near the wellbore, beyond which the reservoir temperature remains relatively unchanged. Larger temperature differentials between the injected CO2 fluid and the formation result in more complicated fracture patterns due to thermal stress effects. With a CO2 injection, the displacement field of the formation deviated asymmetrically and changed abruptly when the fracture formed. As the in situ stress difference increased, the morphology of the SC-CO2-induced fractures tended to become simpler, and conversely, the fracture presented a complicated distribution. Furthermore, with an increasing injection rate of CO2, the fractures exhibited a greater width and extended over longer distances, which are more conducive to reservoir volumetric enhancement. The findings of this study validate the authenticity of previous experimental results, and it analyzed fracture evolution through the multi-field coupling process of CO2 fracturing, thereby enhancing theoretical understanding and laying a foundational basis for the application of this technology.

A Grand Challenge: Update on Improved Recovery From Tight/Shale Reservoirs

_ This is the third of a series of six articles on SPE’s Grand Challenges in Energy, formulated as the output of a 2023 workshop held by the SPE Research and Development Technical Section in Austin, Texas. Described in a JPT article last year, each of the challenges will be discussed separately in this series: geothermal energy; net-zero operations; improving recovery from tight/shale resources; carbon capture, storage, and utilization; digital transformation; and education and advocacy. _ The exploration and extraction of hydrocarbons from tight or shale formations have revolutionized the global energy landscape, unlocking vast oil and gas reserves previously considered inaccessible. According to estimates, substantial oil production has been reported for various tight plays in the US in 2024 (Fig. 1). However, the production process in tight or shale formations is not without its own set of challenges ranging from technological hurdles to environmental concerns. Therefore, understanding the current outlook is essential for stakeholders to navigate the complex terrain. To address the significant issues outlined by SPE in July 2023 (Halsey et al. 2023), this article intends to explore the complexities of hydrocarbon extraction from tight and shale reservoirs. Description of Tight/Shale Formations First, we present a succinct description of tight or shale formations. Tight or shale oil and gas are hydrocarbons found in oil-bearing mudstone, and shale gas is produced from gas shale or associated with tight oil (Boak and Kleinberg 2020). Tight unconventional formations are characterized by the presence of fine-grained sedimentary rocks that are high in organic matter, such as shale, where hydrocarbons are firmly embedded within the rock matrix. Challenges in Tight or Shale Oil Production The Existence of Complex Geometry. Tight and shale formations are known for their complex geological structures, which can make it difficult to predict the distribution and behavior of hydrocarbons within the reservoir. Additionally, shale formations can exhibit significant variability in their thickness, composition, and the occurrence of natural fractures. Hence, it is crucial to understand and navigate the intricate geology of unconventional shale formations to achieve successful shale oil production (Jiang et al. 2016). Ultralow Reservoir Permeability. The low permeability of tight formations restricts the flow of hydrocarbons, necessitating techniques such as hydraulic fracturing to create artificial pathways for extraction. However, the effective stimulation of fractures requires the use of cutting-edge drilling and extraction methods, such as multistage hydraulic fracturing (fracking) and horizontal drilling, which in turn require precise engineering and a thorough understanding of reservoir characteristics (Pokalai et al. 2015).

Be(com)ing an academic other: a layered autoethnographic account of pursuing their doctoral studies

Placing myself as a rejected doctoral student (2010–2022), this paper examines the emergent nature of identity formation across time and space. While presenting a layered account of my lived experience in seeking pathways of pursuing doctoral study, each reading experience leads me to produce my identity(ies) and situated knowledge(s) as an outsider. To illustrate the complexity of one’s lived experience, I choose to present my work in an unconventional format of scholarship. By giving voice to an academic outsider, this paper adds to the nascent literature on the non-linear becomingness of academic identity. Further, this form of scholarship advocates for writing ­differently as a means to empower minorities to articulate their diverse epistemology. The implication of writing up this public letter helps me mitigate feelings of vulnerability and rebuild self-confidence, creating a space of being and its potential to reconstitute the self in their becomingness.

Artificial intelligence-based prediction of hydrogen adsorption in various kerogen types: Implications for underground hydrogen storage and cleaner production

Hydrogen offers significant potential as a sustainable energy source. However, its storage and transportation pose challenges due to its volatility and low density. Subsurface geological formations, such as shale, sandstone, and coal, have been investigated as potential storage sites for hydrogen. Precise estimation of hydrogen adsorption in these formations necessitates a thorough understanding of kerogens, organic-rich sedimentary rocks prevalent in unconventional formations. In this study, we introduce a novel approach employing Extreme Gradient Boosting (XGBoost), Random forest (RF), Light gradient Boosting (LGBM), and Natural gradient boosting (NGBM) algorithms to intelligently predict hydrogen adsorption in various kerogen types. Among these, the NGBM algorithm, utilizing three input features (temperature, pressure, and kerogen types), demonstrated the highest predictive accuracy, achieving an R2 value of 0.989, RMSE of 0.062, and MAE of 0.037 for all data samples. SHAP diagram analysis identified kerogen types as the most influential parameter within the NGBM model. The presented approach has implications beyond energy storage, highlighting the significance of advanced technologies in addressing complex energy challenges. Precise hydrogen adsorption estimation in subsurface formations is vital for developing sustainable energy solutions, and our approach has the potential to expedite progress in this field. Interdisciplinary collaboration among geologists, chemists, and data scientists is crucial for devising innovative solutions for sustainable energy.

Changes in environmental and engineered conditions alter the plasma membrane lipidome of fractured shale bacteria.

Microorganisms inadvertently introduced into the shale reservoir during fracturing face multiple stressors including brine-level salinities and starvation. However, some anaerobic halotolerant bacteria adapt and persist for long periods of time. They produce hydrogen sulfide, which sours the reservoir and corrodes engineering infrastructure. In addition, they form biofilms on rock matrices, which decrease shale permeability and clog fracture networks. These reduce well productivity and increase extraction costs. Under stress, microbes remodel their plasma membrane to optimize its roles in protection and mediating cellular processes such as signaling, transport, and energy metabolism. Hence, by observing changes in the membrane lipidome of model shale bacteria, Halanaerobium congolense WG10, and mixed consortia enriched from produced fluids under varying subsurface conditions and growth modes, we provide insight that advances our knowledge of the fractured shale biosystem. We also offer data-driven recommendations for improving biocontrol efficacy and the efficiency of energy recovery from unconventional formations.

Experimental study on fracture propagation in anisotropy rock under cyclic hydraulic fracturing

Hydraulic fracturing is commonly used to enhance the hydraulic conductivity of geothermal, oil, and gas reservoirs, particularly those situated in enclosed and unconventional formations. Shale oil and gas reservoirs exhibit distinct characteristics in rock mechanics parameters, morphology, natural fracture geometry, and geological features. Structural anisotropy in materials generally arises from changes in grain type and size, weak layering, and variations in layering angles. This study aims to investigate the impact of two key factors, namely cyclic injection and structural anisotropy, on the hydraulic fracturing process. To achieve this goal, the phenomenon of hydraulic fatigue in rock was examined through various cyclic injection methods, and true-triaxial hydraulic fracturing tests were conducted on cubic samples composed of different materials and layers. To evaluate and analyze the fracture morphology of these samples, CT scan X-ray imaging technology was employed. The results revealed that samples subjected to cyclic injection exhibited an average breakdown pressure approximately 30% lower than those subjected to monotonic injection. Fracture geometry in the cyclic injection samples displayed a network pattern with multiple crack branches, while monotonic injection primarily resulted in a single-surface pattern. In samples with differences in horizontal stress, the anisotropy of the sample did not affect the fracture, and the single fracture surface extended in the direction of maximum stress. The energy generated by cyclic injection using the damage-controlled method (cycle duration: 16 s) was concentrated around the borehole, creating a complex fracture network with shorter crack lengths. Conversely, cyclic injection using the ramp signals method (cycle duration: eight seconds) produced more straightforward cracks with greater expansion and penetration. Examination of CT scan images of the fractured samples revealed average tortuosity and fracture volume fraction parameters of 1.117 and 0.027 for cyclic injection, respectively, in contrast to 1.026 and 0.008 for monotonic injection. Furthermore, the S-N damage model based on the results of true-triaxial hydraulic fracturing was introduced to describe rock damage behavior and the concept of fatigue under cyclic loads.

Applications of Two-Dimensional Laboratory Higher-Frequency NMR in Unconventional Shale Characterization

The complexity of the microstructure and fluids in unconventional reservoirs presents challenges to the traditional approaches to the evaluation of geological formations and petrophysical properties due to the low porosity, ultralow permeability, complex lithology, and fluid composition. Nuclear magnetic resonance (NMR) techniques have been playing major roles in unconventional shale characterization in the last decades as NMR can provide critical information about the reservoirs for quantifying their petrophysical parameters and fluid properties and estimating productivity. Laboratory NMR techniques at higher frequency (HF), e.g., 23 MHz, especially two-dimensional (2D) T1-T2 mapping, and their applications have been essential for the noninvasive characterization of tight rock samples for identifying kerogen, bitumen, heavy or light hydrocarbons, and bound or capillary water. Traditional T2 cutoffs, established with low frequency (LF) NMR, no longer apply and need new definitions to reflect the inferences from water and hydrocarbons separately. The crushed rock analysis method, as applied to unconventional formations, has been successful in evaluating total porosity and water saturation but also suffers from inconsistency in results due to desiccation and solvent effects. In the past decade, the oil and gas industry has witnessed significant development of HF NMR techniques that couple advances in petrophysics, petroleum engineering, and geochemistry with a broad range of applications. It is necessary to review such technological advances and draw conclusions to benefit unconventional core analysis programs. This article will summarize key advances in laboratory NMR applications in unconventional shale characterization, including monitoring processes of liquids equilibrium, desiccation, and imbibition in fresh shale samples, determination of activation energy of hydrocarbons in shales, monitoring changes in a shale sample during liquid flooding experiments, and direct measurements on kerogen.

Interfacial and transport properties of supercritical hydrogen and carbon dioxide in unconventional formations

In this work, a systematic investigation is conducted on the interfacial and transport behavior in systems comprising supercritical carbon dioxide (CO2) and supercritical hydrogen (H2) at conditions relevant to their storage in unconventional formations. The interfacial tension (IFT) and wetting behavior in gas-brine-rock systems are determined at conditions that have not been reported earlier. Furthermore, gas adsorption capacities are measured and gas diffusivities are simultaneously evaluated and reported for H2 for the first time. Based on the measured adsorption capacities and gas diffusivities, H2 permeability is evaluated using the solution-diffusion approach. Additionally, H2 permeability is measured using the pressure-pulse decay method and permeability values are compared. Unlike H2, it is observed that CO2 significantly alters the interfacial properties of the investigated systems. CO2 adsorption capacity is found to be up to 6 times higher than that of H2, while H2 diffusivity is an order of magnitude higher than CO2.

Methane mass transfer in mesoporous silica saturated with liquid hydrocarbons

Mass transfer across gas/liquid interfaces plays a central role in many industrial applications. In particular, gas dissolution and diffusion in liquid hydrocarbon mixtures, confined in nanometer-sized pores, is an essential mechanism during enhanced oil recovery (EOR) from unconventional formations. In this work, we have measured methane (C1) diffusion in n-decane (C10), n-hexadecane (C16), and mixtures of C10 + C16 in a mesoporous material with an average pore size of 4 nm at 50 °C and ∼ 8 MPa of gas pressure. A key conclusion of this work is that the diffusivities, measured in the bulk phase, for the relevant binary systems, are sufficient to predict the diffusion behavior of the corresponding multicomponent systems in the porous medium by using Wilke’s equation for the evaluation of effective component diffusivities, combined with an accurate equation of state (EOS) representation of the (bulk) phase behavior. This observation can facilitate accurate prediction of recovery processes in unconventional formations and, potentially, guide other applications that entail gas-liquid interface mass transfer in mesoporous materials.

An experimental study on the imbibition characteristics in heterogeneous porous medium

Capillary imbibition plays an essential role in the flow behavior of unconventional reservoirs. The severe heterogeneity of pore structures in unconventional formations can lead to different imbibition processes and flow dynamics compared to conventional reservoirs. This study investigates the imbibition process in heterogeneous pore networks by first examining the imbibition process between different pores using an ideal capillary model with interacting microchannel micromodels. The results reveal that water preferentially imbibes into small microchannels rather than large ones, and the imbibition velocity decreases with the microchannel width due to crossflow between different microchannels. Furthermore, heterogeneous matrix–fracture micromodels are used to examine the influence of boundary conditions, pressure conditions, and pore structure distribution on the imbibition process. The results show that the imbibition pattern is primarily governed by the boundary condition and is unaffected by the driving pressure condition. The conventional dimensionless time model fails to capture the spontaneous imbibition characteristics due to the interaction of different pores and the change in the imbibition pattern. Both increasing the injection pressure and increasing boundary openness can lead to higher oil recovery enhancement, and the distribution of the pore structure also influences the final oil recovery. Finally, the imbibition characteristics in the core scale are monitored using Nuclear Magnetic Resonance, demonstrating the similar phenomenon that water can imbibe into small pores and displace oil into larger pores. These findings enhance our understanding of the imbibition mechanism in heterogeneous porous media.

Neglected Applications of Monolithic Structures: Advanced Thin Layer Chromatography-Mass Spectrometry Approaches

Thin-layer or planar chromatography (TLC) continues to evolve, albeit at a slower pace than its more powerful counterparts, liquid and gas chromatography. This is easy to understand as TLC has always been a very simple alternative to these methods without the need for complex instrumentation. This does not mean, however, that TLC cannot be combined with sophisticated detection methods such as mass spectrometry or performed in multiple dimensions. To make TLC more widely applicable, its separation potential is constantly being improved. Therefore, layers with new chemical compositions and innovative processes are being developed leading to layers that enable applications not yet described. This review describes the use of monolithic layers formed from porous organic polymers developed for use in mass spectrometry with laser desorption and ionization without the participation of a low molecular weight matrix or for the preparation of layers with unconventional formats for separations in two dimensions. Attention is also given to so far unusual approaches where TLC is realized in microfluidic environments.

Effect of Sub- and Supercritical Water on the Transformation of High-Molecular-Mass Components of High-Carbon Rocks from Unconventional Formations (A Review)

State-of-the-art in the field of recovering high-molecular-mass hydrocarbon components of bituminous and shale rocks by intrastratum transformation into readily recoverable forms using sub- and supercritical water is analyzed. The phase composition of water and its properties in the critical state and the transformations of a number of substances in subcritical (SBW) and supercritical (SCW) water are discussed. The substances under consideration include model polycyclic and heteroatomic compounds containing nitrogen, sulfur, and oxygen, metal porphyrin complexes, asphaltenes, oil sands, and heavy oils and organic matter (OM) of kerogen-containing shale rocks. The preventing effect of hydrogen donors and catalysts for hydrogenation and oxidative cracking on the coking in the course of transformation of heavy hydrocarbons in SCW is compared. The catalytic effect of the mineral matrix of rocks in the course of generation of oil fractions from them is analyzed in detail. The published data concerning the possibility of using SBW and SCW for the transformation of high-molecular-mass components of high-carbon dense rocks from unconventional formations demonstrate high potential of hydrothermal and supercritical fluid technologies

Effect of Sub- and Supercritical Water on the Transformation of High-Molecular-Mass Components of High-Carbon Rocks from Unconventional Formations (A Review)

Effect of Sub- and Supercritical Water on the Transformation of High-Molecular-Mass Components of High-Carbon Rocks from Unconventional Formations (A Review)

Improving predictions of shale wettability using advanced machine learning techniques and nature-inspired methods: Implications for carbon capture utilization and storage

The utilization of carbon capture utilization and storage (CCUS) in unconventional formations is a promising way for improving hydrocarbon production and combating climate change. Shale wettability plays a crucial factor for successful CCUS projects. In this study, multiple machine learning (ML) techniques, including multilayer perceptron (MLP) and radial basis function neural networks (RBFNN), were used to evaluate shale wettability based on five key features, including formation pressure, temperature, salinity, total organic carbon (TOC), and theta zero. The data were collected from 229 datasets of contact angle in three states of shale/oil/brine, shale/CO2/brine, and shale/CH4/brine systems. Five algorithms were used to tune MLP, while three optimization algorithms were used to optimize the RBFNN computing framework. The results indicate that the RBFNN-MVO model achieved the best predictive accuracy, with a root mean square error (RMSE) value of 0.113 and an R2 of 0.999993. The sensitivity analysis showed that theta zero, TOC, pressure, temperature, and salinity were the most sensitive features. This research demonstrates the effectiveness of RBFNN-MVO model in evaluating shale wettability for CCUS initiatives and cleaner production.

STUDY OF THE DYNAMİCS OF THE İMPACT OF DRİLLİNG FLUİD SLURRY ON THE WELL BOTTOM

Currently, the study of the effect of drilling fluid slurry on the well bottom during the drilling of oil and gas wells remains one of the urgent problems in the center of attention. The main purpose of research on the dynamics of drilling fluid (or drilling mud) during the drilling process is to gather information about the effect of drilling fluid on the drilling process. As a result of this research, more detailed information about the effect of drilling mud on the well bottom will be determined, and based on that information, strategies will be drawn up for the selection and use of drilling mud to make the drilling process more effective, safe and successful. Drilling mud is a homogeneous mixture of two or more substances. system is understood. A solution is a mixture consisting of one or more soluble components and also solvents. In general, both dissolved components and solvents can be solid, liquid or gaseous. At this time, the dissolved substances are constantly distributed in the form of small particles in the solvent environment, causing the formation of a new dispersed system called a solution. At this time, dissolved substances create a dispersed phase, and solvents create a dispersed medium. The clay solutions in the drilling solution can be called the dispersed system, the dissolved clays can be called the dispersed phase, and the water, which is the solvent, can be called the dispersed medium. When used for unconventional formations, selecting a drilling fluid based on data from conventional reservoirs may be the wrong choice. During exposure to the drilling fluid, the drilling fluid has a chemical-mechanical effect on the formation rock; this interaction may be sharp or subtle, depending on the minerals that make up the rock structure and their chemical sensitivity to the fluid composition. Improper selection of drilling fluid can lead to strong rock-fluid interactions, resulting in wellbore instability. This paper presents a comprehensive experimental study investigating the effect of different drilling fluids on the mechanical properties of conventional and unconventional rock samples. Studying the dynamics of the impact of the drilling fluid solution on the bottom of the well is an important aspect of the drilling process. This study aims to better understand how the drilling fluid affects the bottom of the well and the surrounding formation. The results of this study can provide valuable information to optimize the use of drilling fluid solution, improve drilling efficiency and reduce the risk of well damage. Keywords: drilling fluid, drilling bit, layer, rock, well, wellbore, pressure.

Experimental Investigation of Asphaltene Deposition and Its Impact on Oil Recovery in Eagle Ford Shale during Miscible and Immiscible CO2 Huff-n-Puff Gas Injection

One of the challenges in extracting oil from unconventional resources using hydraulic fracturing and horizontal drilling techniques is the low primary recovery rate, which is caused by the ultra-small permeability of these resources. Consequently, it is essential to investigate gas injection methods to produce the trapped oil in shale formations. However, the injection process can cause asphaltene depositions inside the reservoir, leading to plugging of pores and oil recovery (OR) reduction. There has been limited research on using gas injection techniques to improve oil production in tight/unconventional resources, although carbon dioxide (CO2) and gas-enhanced oil recovery methods have been used in conventional resources. In order to determine whether or not the cyclic (huff-n-puff) CO2 process improves OR and aggravates asphaltene precipitation, a rigorous experimental investigation was undertaken utilizing filter membranes and Eagle Ford shale cores. After the minimum miscibility pressure was calculated for CO2, various injection pressures were selected to perform CO2 huff-n-puff experiments. Investigations were carried out at 70 °C on injection pressure, cycle number, production time, and huff-and-puff mode injection. The results demonstrated that when the pore size structure of the membranes used was smaller and gas injection cycles increased, a higher asphaltene weight percent (wt %) was determined during the static experiments (i.e., employing filter paper membranes). Miscibility improved OR in dynamic testing (i.e., using shale cores), but a more oil-wet system was detected in wettability measurements taken following CO2 huff-and-puff tests. The plugging impact of asphaltene particles on the pore structure was studied using optical microscopy and scanning electron microscopy imaging. Following the huff-and-puff tests, a mercury porosimeter revealed how severely the pores were plugged, and after the CO2 tests, the pore size distribution reduced as a consequence of asphaltene deposition. This study examines the significance of CO2 injection in OR under miscible/immiscible conditions to identify the critical parameters that could impact the effectiveness of CO2 huff-n-puff operation in unconventional formations.