Low-permeability Zones Research Articles

Enhancing Oil Recovery in Vertical Heterogeneous Sandstone Reservoirs Using Low-Frequency Pulsating Water Injection

Enhanced oil recovery (EOR) techniques, such as water flooding, often face significant challenges in heterogeneous reservoirs, mainly due to permeability variations that hinder effective oil displacement. This study investigated the impact of pulsating water flooding on oil recovery in reservoirs with vertical heterogeneity, focusing on interlayer and inlayer permeability variations. Laboratory experiments were conducted using cylindrical sand pack models with varying permeability to compare steady-state and pulsating water injection methods. The results demonstrated that pulsating water flooding significantly improved vertical sweep efficiency (VSE) and overall oil recovery, particularly in low-permeability zones. Pulsations helped mobilize trapped oil and redistributed injected water more evenly, mitigating the adverse effects of early water breakthrough and enhancing sweep efficiency. For interlayer heterogeneity, pulsating water injection increased total recovery by 23.2%, 8.9%, and 6.6% for core groups with permeability contrasts of 307.9 × 10⁻3 μm2, 193.9 × 10⁻3 μm2, and 73.25 × 10⁻3 μm2, respectively. For inlayer heterogeneity, recovery factors improved by 13.9%, 10.6%, and 3.1%, respectively. Core groups with higher permeability contrasts (i.e., larger differences between high and low permeability) experienced lower recovery under steady-state conditions, while pulsating injection mitigated these effects, resulting in higher recovery in more heterogeneous reservoirs than steady-state flooding. These findings suggest that pulsating water flooding is an effective and cost-efficient technique for enhancing oil recovery in heterogeneous reservoirs. It improves short-term and long-term recovery by increasing displacement efficiency, particularly in low-permeability regions, and effectively mitigates the challenges of permeability variations. As such, pulsating water flooding offers a significant improvement over steady-state flooding, providing valuable insights for EOR practices in complex reservoirs.

A novel approach to assess acid diversion efficiency in horizontal wells

Using an acid to stimulate a heterogeneous carbonate reservoir during matrix acidizing may lead to over-treating the high permeability zones, leaving low permeability zones untreated. This is particularly exacerbated in long horizontal sections, necessitating the use of acid diverters for effective acid distribution across the formation. In previous studies, conventional core flooding systems were utilized where single inlet and outlet lines were used or, at best, two outlet lines for dual-core flooding. This paper proposes a new method for simulating matrix acidizing in horizontal wells by introducing five injection points and two outlet lines. The injection points are perpendicular to the core samples to simulate multiple perforations in a horizontal well while the outlet lines are parallel. Four experiments were conducted in this study using Indiana limestone cores that were 1.5 inches in diameter. For the first three tests, the length of the core was 12 inches, and the cores’ average permeabilities were 16 mD. For the fourth one, two 6-inch length cores with different average permeability (10 and 50 mD) were employed. Hydrochloric acid was used in the first experiment, while hydrochloric acid with viscoelastic surfactant (VES) was used in subsequent experiments. To the best of our knowledge, this is the first study to introduce a multi-point injection system with enhanced coverage and distribution, resulting in a more precise representation of acidizing a horizontal well.

Uncertainty analysis of geomechanical responses: China’s first offshore carbon capture and storage project

Uncertainty analysis of geomechanical responses: China’s first offshore carbon capture and storage project

Contrast of hydraulic conductivity induces transport of combined pollutants in high- and low-permeability systems

The transport process of pollutants in the environment can be influenced by heterogeneous geologic architecture and pollutant interactions. However, there has been a lack of research on co-transport behaviors of combined pollutants in heterogeneous aquifers. In this study, a series of two-dimensional tank experiments were carried out to study the transport behavior of toluene and naphthalene in both homogeneous and heterogeneous aquifers. The results revealed that the coexisting solutes facilitated the transport of toluene and naphthalene in the homogeneous aquifers, potentially due to competitive adsorption between these compounds. In the high- and low-permeability systems, the transport rates for both toluene and naphthalene decreased while exhibiting characteristics such as early arrival, long tails, and multiple peaks. The spatial analysis of pollutant distribution indicated that hydraulic conductivity contrast played a critical role in inducing back diffusion phenomenon. Furthermore, toluene exhibited more pronounced matrix diffusion compared to naphthalene in heterogeneous aquifers, characterized by higher concentrations, wider diffusion range in low-permeability zones. And the β value for toluene is smaller than naphthalene in CTRW model, indicating that the former is more sensitive to the hydraulic conductivity contrast. This study provides novel insights into understanding the co-transport behavior of combined pollutants in heterogenous aquifers.

Performance and economic analysis of various geothermal power plant systems: Case study for the Chingshui geothermal field in Taiwan

Performance and economic analysis of various geothermal power plant systems: Case study for the Chingshui geothermal field in Taiwan

Chemical enhanced oil recovery using carbonized ZIF-67 MOFs and sulfonated copolymers at high reservoir temperatures

Chemical enhanced oil recovery using carbonized ZIF-67 MOFs and sulfonated copolymers at high reservoir temperatures

Study on The Areal Sweep Efficiency and Water Breakthrough Time Prediction of Water Flooding in Carbonate Reservoirs

Abstract This study concentrates on the evaluation of areal sweep efficiency and the prediction of water breakthrough time in a representative medium-porosity, medium-high permeability thin carbonate reservoir, using the H oilfield in the Middle East as an example. Areal geological models, accounting for variations in high permeability streaks and regional heterogeneity, were established to study the impact of areal heterogeneity on the sweep coefficient and morphology of the water flooding front. The results revealed that areal heterogeneity significantly affects both the areal sweep efficiency and the morphology of the water flooding front. In models with high permeability streaks, a greater permeability ratio led to more uneven displacement in all directions, consequently, this resulted in a poorer overall development effect. Furthermore, regional heterogeneity was found to significantly impact sweep efficiency, the larger the area of relatively low permeability zones, the more severe the reduction in sweep efficiency and the overall injection production effect. A theoretical method for accurately predicting water breakthrough time was established based on the stream tube method. This method was applied to the H oilfield, which reduced the discrepancy between the predicted and actual breakthrough times, thereby confirming its feasibility. The novelty of this study lies in overcoming the limitations of the stream tube method and utilizing numerical simulation to calculate the areal sweep coefficient at the time of water breakthrough. This approach quantitatively characterized the affected streamline area, thereby enhancing the accuracy of water breakthrough time predictions. This research provides significant theoretical insights and practical references for understanding the areal sweep efficiency of thin carbonate reservoirs, predicting water breakthrough times, and optimizing injection production strategies.

The conformance control and enhanced oil recovery performance of CO2 foam reinforced by regenerated cellulose

The conformance control and enhanced oil recovery performance of CO2 foam reinforced by regenerated cellulose

Assessment of the Hydraulic Profiling Tool for Lower Permeability Characterization

AbstractThe Hydraulic Profiling Tool (HPT) has become one of the most widely accepted approaches for obtaining vertical profiles of hydraulic conductivity (K) in environmental site investigations. The current tool, however, is limited to use in moderately permeable settings with a measurable K range of 0.03 to 25 m/d. In this work, we added a low‐flow injection system to standard HPT and modified the field profiling procedure so that it could be used more effectively in lower‐K settings. The modified lower‐K HPT was tested and evaluated against direct‐push slug tests at a field site in the Kansas River floodplain. Results indicated that when the injection rate was reduced, injection pressure decreased, which reduced the potential of injection‐induced formation alteration. A particular challenge of applying HPT in lower‐K zones is the large pressure generated by probe advancement; this can significantly affect the pressure signal measured at the injection screen. Our results showed that the impacts of advancement‐generated pressure could be mitigated by reducing the speed of probe advancement. Compared to K estimates by slug tests, the vertical variability in HPT K was much lower. The reduced variability in HPT K was likely due to formation alteration during probe advancement, as well as pressure interference from injections at previous depths and probe advancement at the bottom. Additional work, such as the use of a smaller‐diameter probe, is needed to further improve the performance of HPT in lower permeability zones.

Nanoparticle-stabilized CO2 foam flooding for enhanced heavy oil recovery: A micro-optical analysis

Nanoparticle-stabilized CO2 foam flooding for enhanced heavy oil recovery: A micro-optical analysis

Enhanced migration and degradation of nitrobenzene in heterogeneous porous media using pulsed direct current electrical resistance heating with hydraulic circulation

Enhanced migration and degradation of nitrobenzene in heterogeneous porous media using pulsed direct current electrical resistance heating with hydraulic circulation

Permeability–porosity model considering oxidative precipitation of Fe(II) in granular porous media

Permeability–porosity model considering oxidative precipitation of Fe(II) in granular porous media

Spatiotemporal dynamic temperature variation dominated by ion behaviors during groundwater remediation using direct current

Direct current (DC) electric field has shown promising performance in contaminated site remediation, in which the Joule heating effect plays an important role but has been previously underappreciated. This study focuses on the spatiotemporal characteristics and mechanism of temperature change in heterogeneous porous media with applied DC. The heating process can be divided into four phases: preferential heating of the low permeability zone (LPZ), rapid heating in the middle region, temperature drop and hot zone shift, and reheating. The dynamic ion behaviors with complex interplays among reactions, electrokinetic-driven migration, and mixed convection induced an uneven redistribution of ions and dominated the heating rate and temperature distribution. The concentration of major ions near the pH jump decreased to 1% of the initial value, even though ions were continuously pumped into the heating zone. This ion depletion caused a drop in current, heating rate, and temperature. Here ions cannot be delivered rapidly into the ion-depleted zone by electromigration due to the potential flattening in the surrounding region. The presence of LPZ intensified the nonuniformity of ion redistribution, where a regional focusing of water-soluble ions was observed, and weakened the temperature rebound compared with that using homogeneous sand. These results provide a new perspective on the regulation of DC heating in site remediation.

Flow Characterization in Fractured Shale Oil Matrices Using Advanced Nuclear Magnetic Resonance Techniques

The evaluation of flow dynamics in fractured shale oil reservoirs presents significant challenges due to the complex pore configurations and high organic material concentration. Conventional methods for petrophysical and fluid dynamic evaluations are insufficient in addressing these complexities. However, nuclear magnetic resonance (NMR) technology is an effective technique for quantitatively delineating fluid micro-transport properties across the reservoir core. This study presents an experimental methodology rooted in NMR technology to quantify the flow capabilities within the shale oil matrix. This approach incorporates high-pressure saturation flow experiments across seven distinct core samples to gauge the micro-transport phenomena of fluids across various pore dimensions. The results revealed that under high-pressure saturation, shale cores devoid of fractures demonstrated an average crude oil saturation rate of merely 19.44%. Cores with evident stratification exhibited a 16.18% increase in flow capacity compared to their non-stratified counterparts. The flow dynamics within these shale reservoirs exhibited a range of behaviors, from non-linear to linear. In lower-permeability zones, non-linear patterns became increasingly apparent. An NMR T2 spectrum analysis was used to identify the minimum effective pore size conducive to shale oil flow within the matrix, which was between 8 and 10 nanometers. These insights provide a foundation for a deeper understanding of the mechanisms behind oil and gas migration in fractured shale oil matrices, offering valuable insight into their extractive potential.

Image analysis technique for quantifying fluorescein concentration profiles in clays

Image analysis technique for quantifying fluorescein concentration profiles in clays

Water shutoff treatment of low permeable reservoirs by in situ polymerization: laboratory scale development and verification through core flow experiments

Excessive water generation in oil reservoirs poses economic challenges, diminishing hydrocarbon yield and incurring additional costs for water management. This study focuses on enhancing reservoir conformance control, particularly in low-permeability zones with high water production, where traditional gel-based methods face limitations. The goal is improved penetration into narrow fractures and effective sealing of water-inflow zones through in situ polymerization and sequential cross-linking. The study systematically optimized key polymerization parameters, including initiator/monomer ratios, initiator types, and environmental conditions. Core flooding tests demonstrated a significant 17% increase in original oil recovery, alongside a substantial reduction in permeability. Analytical techniques such as CT scans, thin section scans, SEM, and EDS were employed to assess gel distribution within pores and penetration rates. This in situ polymerization and gelation approach show promise in addressing water production challenges, offering enhanced recovery, and adapting well to diverse reservoir conditions. The comprehensive optimization of polymerization parameters and the use of advanced analytical methods contribute to the study’s potential impact on mitigating economic and operational issues associated with excessive water production in oilfields.

Investigation of CO2-EOR and storage mechanism in Injection-Production coupling technology considering reservoir heterogeneity

Investigation of CO2-EOR and storage mechanism in Injection-Production coupling technology considering reservoir heterogeneity

The Role of Silica Nanofluid as a Plugging Agent for Enhanced Oil Recovery – Experimental Approach

Many enhanced oil recovery techniques have been adopted in oil production to recover as much oil as possible. However, enhanced oil recovery techniques are complex and costly. Therefore, nanofluids have been modified in the laboratory to be consistent with reservoir fluids and rocks while also being environmentally benign. This study aims to investigate the role of silica nanofluid in plugging the high permeable zones after oil is recovered from the reservoir to divert pressure to the low permeable zone for enhanced oil production from the low permeable zones. A digital gas permeameter (DGP-300-B) was used to determine the permeability of the core by injecting nitrogen gas. In addition, a DHP-100-M Digital Helium Porosimeter was used to determine bulk volume, grain volume, and grain density porosity. The experiment was conducted with different percentages of silicon dioxide nanoparticles to observe the effect of plugging in each stage. Results show that a 52% reduction in core permeability was observed when using 0.5wt.% of silica nanoparticles, a 72% reduction in core permeability when using 1wt.% of silica nanoparticles and a 94% reduction in core permeability when using 2wt.% of silica nanoparticles.

Scaling up in situ combustion process for enhanced oil recovery in water-flooded light oil reservoirs from laboratory to field implementation

Aiming at low permeability, high water content light reservoir with a recovery rate higher than 20%, an improved air injection enhanced heat flooding technology is applied by combining the combustion reaction flow and flue gas flooding mechanism. The method involves the injection of air into the reservoir, which reacts with the crude oil at temperatures ranging from 220 to 300 °C. This reaction consumes part of the oil, enabling effective evaporation and flow of the remaining oil. This process combines combustion reaction flow with flue gas flooding, using high-temperature oxidation reactions to mobilize residual oil. Experimental results from combustion tube tests demonstrate stable reaction fronts, peak temperatures reaching up to 550 °C, and a significant increase in recovery rates, reaching 73.8% in some cases. Field applications of this technology require maintaining high air flux and burning rates in low-permeability zones to ensure effective heat-driven evaporation. The geological model of the well group shows that the recovery factor of the target block can be increased by more than 20% by air injection based on the water drive recovery factor of 28%–30%. The oil exchange ratio can be less than 4000 sm3/m3 by optimizing the air injection rate and oxygen content. The research results provide technical feasibility for heat flooding to significantly improve oil flow and recovery in low-permeability light oil reservoirs.

Does backflow occur in forced imbibition into a dual-permeability pore network?

Does backflow occur in forced imbibition into a dual-permeability pore network?