Energies

Research

16 pages, 3026 KiB

Open AccessArticle

Benefit–Cost and Energy Efficiency Index to Support the Screening of Hybrid Cyclic Steam Stimulation Methods

by Laura Osma, Luis García, Romel Pérez, Carolina Barbosa, Jesús Botett, Jorge Sandoval and Eduardo Manrique

Energies 2019, 12(24), 4631; https://doi.org/10.3390/en12244631 - 6 Dec 2019

Cited by 19 | Viewed by 4088

Abstract

Most of the evaluations of thermal enhanced oil recovery (EOR) methods in numerical simulations mainly focus on the identification of recovery processes with the greatest potential to increase oil recovery. In some cases, the economic aspects of the EOR methods evaluated are also [...] Read more.

Most of the evaluations of thermal enhanced oil recovery (EOR) methods in numerical simulations mainly focus on the identification of recovery processes with the greatest potential to increase oil recovery. In some cases, the economic aspects of the EOR methods evaluated are also considered. However, these studies often lack the evaluation of the energy efficiency of the proposed methods as a strategy to support the selection of profitable recovery processes. Therefore, this study aimed to identify the potential of different hybrid cyclic steam stimulation (CSS, with flue gas, foam, nanoparticles, or solvents) methods based on a numerical simulation study using a radial model representative of a large heavy oil reservoir in the Middle Magdalena Basin, Colombia. The simulation results were used to estimate the benefit–cost (B/C) ratios and energy efficiency (EE) indices that can be used to screen and rank the hybrid CSS methods studied. When comparing different hybrid methods, it was found that CSS with nanoparticles or solvents performed better during the first two steam cycles (higher oil saturations). However, CSS with foam and flue gases showed higher incremental oil production (≥3564 bbls or 567 m³) during the sixth steam cycle. Based on an energy cost index (ECI = [(B/C) / EE]), CSS with foam outperformed (ECI ≈ 453) cyclic steam injection with flue gases (ECI ≈ 21) and solvents (ECI ≈ 0.1) evaluated during the sixth steam cycle. The results show that this methodology can be used to guide decision-making to identify hybrid CSS methods that can increase oil recovery in a cost-effective manner and provide an efficient energy balance. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery 2019)

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15 pages, 7531 KiB

Open AccessArticle

Simulation Study of CO₂ Huff-n-Puff in Tight Oil Reservoirs Considering Molecular Diffusion and Adsorption

by Yuan Zhang, Jinghong Hu and Qi Zhang

Energies 2019, 12(11), 2136; https://doi.org/10.3390/en12112136 - 4 Jun 2019

Cited by 22 | Viewed by 3875

Abstract

CO₂ injection has great potentials to improve the oil production for the fractured tight oil reservoirs. However, Current works mainly focus on its operation processes; full examination of CO₂ molecular diffusion and adsorption was still limited in the petroleum industry. To [...] Read more.

CO₂ injection has great potentials to improve the oil production for the fractured tight oil reservoirs. However, Current works mainly focus on its operation processes; full examination of CO₂ molecular diffusion and adsorption was still limited in the petroleum industry. To fill this gap, we proposed an efficient method to accurately and comprehensively evaluate the efficiency of CO₂-EOR process. We first calculated the confined fluid properties with the nanopore effects. Subsequently, a reservoir simulation model was built based on the experiment test of the Eagle Ford core sample. History matching was performed for the model validation. After that, we examined the effects of adsorption and molecular diffusion on the multi-well production with CO₂ injection. Results illustrate that in the CO₂-EOR process, the molecular diffusion has a positive impact on the oil production, while adsorption negatively impacts the well production, indicating that the mechanisms should be reasonably incorporated in the simulation analysis. Additionally, simulation results show that the mechanisms of molecular diffusion and adsorption make great contributions to the capacity of CO₂ storage in tight formations. This study provides a strong basis to reasonably forecast the long-term production during CO₂ Huff-n-Puff process. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery 2019)

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16 pages, 5118 KiB

Open AccessArticle

Synthesis of Novel Ethoxylated Quaternary Ammonium Gemini Surfactants for Enhanced Oil Recovery Application

by S. M. Shakil Hussain, Muhammad Shahzad Kamal and Mobeen Murtaza

Energies 2019, 12(9), 1731; https://doi.org/10.3390/en12091731 - 8 May 2019

Cited by 56 | Viewed by 5666

Abstract

Two aspects are always considered in the design and development of new surfactants for oilfield application. One of them is that surfactant must be sufficiently stable at reservoir temperature and the other is the solubility of the surfactant in the injection water (usually [...] Read more.

Two aspects are always considered in the design and development of new surfactants for oilfield application. One of them is that surfactant must be sufficiently stable at reservoir temperature and the other is the solubility of the surfactant in the injection water (usually seawater) and the formation brine. Most industrially applied surfactants undergo hydrolysis at elevated temperature and the presence of reservoir ions causes surfactant precipitation. In relevance to this, a novel series of quaternary ammonium gemini surfactants with different length of spacer group (C8, C10, and C12) was synthesized and characterized using FT-IR, ¹³C NMR, ¹H NMR, and MALDI-TOF MS. The gemini surfactants were prepared by solvent-free amidation of glycolic acid ethoxylate lauryl ether with 3-(dimethylamino)-1-propylamine followed by reaction with dibromoalkane to obtain quaternary ammonium gemini surfactants. The gemini surfactants were examined by means of surface properties and thermal stabilities. The synthesized gemini surfactants showed excellent solubility in the formation brine, seawater, and deionized water without any precipitation for up to three months at 90 °C. Thermal gravimetric data revealed that all the gemini surfactants were decomposed above 227 °C, which is higher than the oilfield temperature (≥90 °C). The decrease in critical micelle concentration (CMC) and surface tension at CMC (γ_cmc) was detected by enhancing spacer length in the order C8 ˃ C10 ˃ C12 which suggested that the larger the spacer, the better the surface properties. Moreover, a further decrease in CMC and γ_cmc was noticed by enhancing temperature (30 °C ˃ 60 °C) and salinity (deionized water ˃ seawater). The current study provides a comprehensive investigation of quaternary ammonium gemini surfactants that can be further extended potentially to use as a suitable material for oilfield application. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery 2019)

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21 pages, 2359 KiB

Open AccessArticle

An Injectivity Evaluation Model of Polymer Flooding in Offshore Multilayer Reservoir

by Liang Sun, Baozhu Li, Hanqiao Jiang, Yong Li and Yuwei Jiao

Energies 2019, 12(8), 1444; https://doi.org/10.3390/en12081444 - 15 Apr 2019

Cited by 9 | Viewed by 3405

Abstract

Good polymer flood performance evaluation requires an understanding of polymer injectivity. Offshore reservoirs are characterized by unfavorable water–oil mobility ratios, strong heterogeneity, and multilayer production, which collectively contribute to unique challenges. Accordingly, this article presents a semi-analytical model for the evaluation of commingled [...] Read more.

Good polymer flood performance evaluation requires an understanding of polymer injectivity. Offshore reservoirs are characterized by unfavorable water–oil mobility ratios, strong heterogeneity, and multilayer production, which collectively contribute to unique challenges. Accordingly, this article presents a semi-analytical model for the evaluation of commingled and zonal injectivity in the entire development phase, which consists of primary water flooding, secondary polymer flooding, and subsequent water flooding. First, we define four flow regions with unique saturation profiles in order to accurately describe the fluid dynamic characteristics between the injector and the producer. Second, the frontal advance equation of polymer flooding is built up based on the theory of polymer–oil fractional flow. The fluid saturation distribution and the injection–production pressure difference are determined with the method of equivalent seepage resistance. Then, the zonal flow rate is obtained by considering the interlayer heterogeneity, and the semi-analytical model for calculating polymer injectivity in a multilayer reservoir is established. The laboratory experiment data verify the reliability of the proposed model. The results indicate the following. (1) The commingled injectivity decreases significantly before polymer breakthrough and increases steadily after polymer breakthrough. The change law of zonal injectivity is consistent with that of commingled injectivity. Due to the influence of interlayer heterogeneity, the quantitative indexes of the zonal flow rate and injection performance are different. The injectivity of the high-permeability layer is better than that of the low-permeability layer. (2) The higher the injection rate and the lower the polymer concentration, the better the injectivity is before polymer breakthrough. An earlier injection time, lower injection rate, larger polymer injection volume, and lower polymer concentration will improve the injectivity after polymer breakthrough. The polymer breakthrough time is a significant indicator in polymer flooding optimization. This study has provided a quick and reasonable model of injectivity evaluation for offshore multilayer reservoirs. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery 2019)

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13 pages, 7122 KiB

Open AccessArticle

An Experimental Investigation of Flow Regimes in Imbibition and Drainage Using a Microfluidic Platform

by Feng Guo and Saman A. Aryana

Energies 2019, 12(7), 1390; https://doi.org/10.3390/en12071390 - 11 Apr 2019

Cited by 41 | Viewed by 5809

Abstract

Instabilities in immiscible displacement along fluid−fluid displacement fronts in porous media are undesirable in many natural and engineered displacement processes such as geological carbon sequestration and enhanced oil recovery. In this study, a series of immiscible displacement experiments are conducted using a microfluidic [...] Read more.

Instabilities in immiscible displacement along fluid−fluid displacement fronts in porous media are undesirable in many natural and engineered displacement processes such as geological carbon sequestration and enhanced oil recovery. In this study, a series of immiscible displacement experiments are conducted using a microfluidic platform across a wide range of capillary numbers and viscosity ratios. The microfluidic device features a water-wet porous medium, which is a two-dimensional representation of a Berea sandstone. Data is captured using a high-resolution camera, enabling visualization of the entire domain, while being able to resolve features as small as 10 µm. The study reports a correlation between fractal dimensions of displacement fronts and displacement front patterns in the medium. Results are mapped on a two-dimensional parameter space of log M and log Ca, and stability diagrams proposed in literature for drainage processes are superimposed for comparison. Compared to recent reports in the literature, the results in this work suggest that transition regimes may constitute a slightly larger portion of the overall flow regime diagram. This two-phase immiscible displacement study helps elucidate macroscopic processes at the continuum scale and provides insights relevant to enhanced oil recovery processes and the design of engineered porous media such as exchange columns and membranes. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery 2019)

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30 pages, 17912 KiB

Open AccessArticle

Simulation of Surfactant Oil Recovery Processes and the Role of Phase Behaviour Parameters

by Pablo Druetta and Francesco Picchioni

Energies 2019, 12(6), 983; https://doi.org/10.3390/en12060983 - 13 Mar 2019

Cited by 1 | Viewed by 4400

Abstract

Chemical Enhanced Oil Recovery (cEOR) processes comprise a number of techniques which modify the rock/fluid properties in order to mobilize the remaining oil. Among these, surfactant flooding is one of the most used and well-known processes; it is mainly used to decrease the [...] Read more.

Chemical Enhanced Oil Recovery (cEOR) processes comprise a number of techniques which modify the rock/fluid properties in order to mobilize the remaining oil. Among these, surfactant flooding is one of the most used and well-known processes; it is mainly used to decrease the interfacial energy between the phases and thus lowering the residual oil saturation. A novel two-dimensional flooding simulator is presented for a four-component (water, petroleum, surfactant, salt), two-phase (aqueous, oleous) model in porous media. The system is then solved using a second-order finite difference method with the IMPEC (IMplicit Pressure and Explicit Concentration) scheme. The oil recovery efficiency evidenced a strong dependency on the chemical component properties and its phase behaviour. In order to accurately model the latter, the simulator uses and improves a simplified ternary diagram, introducing the dependence of the partition coefficient on the salt concentration. Results showed that the surfactant partitioning between the phases is the most important parameter during the EOR process. Moreover, the presence of salt affects this partitioning coefficient, modifying considerably the sweeping efficiency. Therefore, the control of the salinity in the injection water is deemed fundamental for the success of EOR operations with surfactants. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery 2019)

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15 pages, 6601 KiB

Open AccessArticle

Embedded Discrete Fracture Modeling as a Method to Upscale Permeability for Fractured Reservoirs

by Zhenzhen Dong, Weirong Li, Gang Lei, Huijie Wang and Cai Wang

Energies 2019, 12(5), 812; https://doi.org/10.3390/en12050812 - 1 Mar 2019

Cited by 17 | Viewed by 5112

Abstract

Fractured reservoirs are distributed widely over the world, and describing fluid flow in fractures is an important and challenging topic in research. Discrete fracture modeling (DFM) and equivalent continuum modeling are two principal methods used to model fluid flow through fractured rocks. In [...] Read more.

Fractured reservoirs are distributed widely over the world, and describing fluid flow in fractures is an important and challenging topic in research. Discrete fracture modeling (DFM) and equivalent continuum modeling are two principal methods used to model fluid flow through fractured rocks. In this paper, a novel method, embedded discrete fracture modeling (EDFM), is developed to compute equivalent permeability in fractured reservoirs. This paper begins with an introduction on EDFM. Then, the paper describes an upscaling procedure to calculate equivalent permeability. Following this, the paper carries out a series of simulations to compare the computation cost between DFM and EDFM. In addition, the method is verified by embedded discrete fracture modeling and fine grid methods, and grid-block and multiphase flow are studied to prove the feasibility of the method. Finally, the upscaling procedure is applied to a three-dimensional case in order to study performance for a gas injection problem. This study is the first to use embedded discrete fracture modeling to compute equivalent permeability for fractured reservoirs. This paper also provides a detailed comparison and discussion on embedded discrete fracture modeling and discrete fracture modeling in the context of equivalent permeability computation with a single-phase model. Most importantly, this study addresses whether this novel method can be used in multiphase flow in a reservoir with fractures. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery 2019)

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19 pages, 11511 KiB

Open AccessArticle

Experimental Study of Profile Control with Foam Stabilized by Clay Particle and Surfactant

by Songyan Li, Chenyu Qiao, Guowei Ji, Qun Wang and Lei Tao

Energies 2019, 12(5), 781; https://doi.org/10.3390/en12050781 - 26 Feb 2019

Cited by 22 | Viewed by 3641

Abstract

Foam is a kind of ideal fluid for profile control in petroleum engineering, which has attracted intense interests of scholars globally in recent years. In this study, a foam system stabilized with anionic surfactants and clay particles was proposed for profile control in [...] Read more.

Foam is a kind of ideal fluid for profile control in petroleum engineering, which has attracted intense interests of scholars globally in recent years. In this study, a foam system stabilized with anionic surfactants and clay particles was proposed for profile control in reservoirs, and the formulation was optimized experimentally. Moreover, flooding experiments in visible porous media models and in sandpacks were conducted to test the plugging effect of the foam system on reservoirs, and the effects of different factors such as gas–liquid ratio, temperature and permeability on profile control were also evaluated. According to the experimental results, the clay-HY-2 system was elected for its satisfactory foamability, stability, and salinity resistance, and the optimum concentrations of HY-2 and clay particle are 0.6 wt% and 5.0 wt%, respectively. Compared with traditional foam fluids, the clay-HY-2 system can form denser and smaller bubbles in high- and middle-permeable layers, enhancing the plugging effect there, while there are less bubbles in low-permeable layers, i.e., the restriction on the flow in narrow structures is slight. The clay-HY-2 foam can perform the efficient and uniform profile control effect on sandpacks when the foam quality is around 50%. The resistance factor of the foam decrease gradually with the increasing temperature, however, the resistance factor remains higher than 350.0 when the temperature reaches 80.0 °C. When the permeability exceeds 1502.0 mD, the clay-HY-2 foam can perform deep profile control in reservoirs, and the resistance factor are not sensitive to the change of permeability when it exceeds 3038.0 mD. Besides, the site application case shows that the clay-HY-2 foam do have good profile control effect on reservoirs, i.e., improving oil production and declining water cut. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery 2019)

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19 pages, 4393 KiB

Open AccessArticle

Experimental Study and Mechanism Analysis of the Effect of Oil Viscosity and Asphaltene on Foamy Oil

by Zhuangzhuang Wang, Zhaomin Li and Teng Lu

Energies 2019, 12(4), 761; https://doi.org/10.3390/en12040761 - 25 Feb 2019

Cited by 7 | Viewed by 4359

Abstract

Foamy oil is considered an important reason for the anomalous performance in depletion development for some heavy oil reservoirs, but its influence factors remain to be fully investigated. In order to determine the effect of oil viscosity and asphaltene on foamy oil, ten [...] Read more.

Foamy oil is considered an important reason for the anomalous performance in depletion development for some heavy oil reservoirs, but its influence factors remain to be fully investigated. In order to determine the effect of oil viscosity and asphaltene on foamy oil, ten oil samples including two types (deasphalted oil and asphaltenic oil) and five viscosities were used in the work. On this basis, depletion experiments were conducted in a sandpack and microscopic visualization model. Then, viscoelastic moduli of the oil–gas interface were measured to analyze the mechanisms of viscosity and asphaltene of foamy oil from the perspective of interfacial viscoelasticity. Results show that, with the decrease of the oil viscosity, the foamy oil performance in depletion development worsened, including a rapider decline in average pressure, earlier appearance of gas channeling, shorter period of foamy oil, and lower contribution of foamy oil to recovery. Asphaltene had an influence on foamy oil only in the viscosity range between 870 mPa∙s and 2270 mPa∙s for this study. The effect of viscosity and asphaltene on foamy oil can be explained by the viscoelasticity of bubble film. With the increase of oil viscosity, the interfacial viscous modulus increases significantly, indicating the bubble film becomes stronger and more rigid. Asphaltene, like armor on the bubble film, can improve the viscoelastic modulus, especially at lower viscosity. This can inhibit the coalescence of micro-bubbles and increase the possibility of splitting. This work identifies the effects of oil viscosity and asphaltene on foamy oil systematically and provides theoretical support for foamy oil production. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery 2019)

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14 pages, 6391 KiB

Open AccessArticle

Effect of Surface Wettability on Immiscible Displacement in a Microfluidic Porous Media

by Jorge Avendaño, Nicolle Lima, Antonio Quevedo and Marcio Carvalho

Energies 2019, 12(4), 664; https://doi.org/10.3390/en12040664 - 19 Feb 2019

Cited by 32 | Viewed by 4179

Abstract

Wettability has a dramatic impact on fluid displacement in porous media. The pore level physics of one liquid being displaced by another is a strong function of the wetting characteristics of the channel walls. However, the quantification of the effect is still not [...] Read more.

Wettability has a dramatic impact on fluid displacement in porous media. The pore level physics of one liquid being displaced by another is a strong function of the wetting characteristics of the channel walls. However, the quantification of the effect is still not clear. Conflicting data have shown that in some oil displacement experiments in rocks, the volume of trapped oil falls as the porous media becomes less water-wet, while in some microfluidic experiments the volume of residual oil is higher in oil-wet media. The reasons for this discrepancy are not fully understood. In this study, we analyzed oil displacement by water injection in two microfluidic porous media with different wettability characteristics that had capillaries with constrictions. The resulting oil ganglia size distribution at the end of water injection was quantified by image processing. The results show that in the oil-wet porous media, the displacement front was more uniform and the final volume of remaining oil was smaller, with a much smaller number of large oil ganglia and a larger number of small oil ganglia, when compared to the water-wet media. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery 2019)

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Graphical abstract

14 pages, 5720 KiB

Open AccessArticle

Experimental Study on Factors Affecting the Performance of Foamy Oil Recovery

by Weifeng Lv, Dongxing Du, Jiru Yang, Ninghong Jia, Tong Li and Rong Wang

Energies 2019, 12(4), 637; https://doi.org/10.3390/en12040637 - 16 Feb 2019

Cited by 2 | Viewed by 3066

Abstract

The flow characteristics of dissolved gas driven processes in some heavy oil reservoirs, such as low gas–oil ratio and higher oil recovery rate than expected, are quite different from conventional oil production processes. Foamy oil is considered one of the main reasons behind [...] Read more.

The flow characteristics of dissolved gas driven processes in some heavy oil reservoirs, such as low gas–oil ratio and higher oil recovery rate than expected, are quite different from conventional oil production processes. Foamy oil is considered one of the main reasons behind such a production phenomenon. In this paper, the factors affecting the performance of foamy oil recovery were experimentally investigated in a sandpack medium with the assistance of computed tomography (CT) technology to help further the understanding of the mechanism. Five different experiments were applied and the results showed that (1) the linear pressure drop production model had a similar oil recovery to that of the step-down mode; (2) increasing the depletion rate could be more favorable to the oil recovery rate; (3) under a constant gas–oil ratio, raising the temperature had little impact on oil recovery, but showed obvious impact on the production curve; and (4) with higher permeability, there were more residual oil at the end of the displacement process. Lastly, a dry gas huff and puff experiment was conducted and the decreased oil saturation was observed in the inlet section, while no obvious effect was remarked in the outlet region of the medium. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery 2019)

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25 pages, 2992 KiB

Open AccessFeature PaperArticle

Polymer Injectivity: Investigation of Mechanical Degradation of Enhanced Oil Recovery Polymers Using In-Situ Rheology

by Badar Al-Shakry, Tormod Skauge, Behruz Shaker Shiran and Arne Skauge

Energies 2019, 12(1), 49; https://doi.org/10.3390/en12010049 - 24 Dec 2018

Cited by 44 | Viewed by 7520

Abstract

Water soluble polymers have attracted increasing interest in enhanced oil recovery (EOR) processes, especially polymer flooding. Despite the fact that the flow of polymer in porous medium has been a research subject for many decades with numerous publications, there are still some research [...] Read more.

Water soluble polymers have attracted increasing interest in enhanced oil recovery (EOR) processes, especially polymer flooding. Despite the fact that the flow of polymer in porous medium has been a research subject for many decades with numerous publications, there are still some research areas that need progress. The prediction of polymer injectivity remains elusive. Polymers with similar shear viscosity might have different in-situ rheological behaviors and may be exposed to different degrees of mechanical degradation. Hence, determining polymer in-situ rheological behavior is of great significance for defining its utility. In this study, an investigation of rheological properties and mechanical degradation of different partially hydrolyzed polyacrylamide (HPAM) polymers was performed using Bentheimer sandstone outcrop cores. The results show that HPAM in-situ rheology is different from bulk rheology measured by a rheometer. Specifically, shear thickening behavior occurs at high rates, and near-Newtonian behavior is measured at low rates in porous media. This deviates strongly from the rheometer measurements. Polymer molecular weight and concentration influence its viscoelasticity and subsequently its flow characteristics in porous media. Exposure to mechanical degradation by flow at high rate through porous media leads to significant reduction in shear thickening and thereby improved injectivity. More importantly, the degraded polymer maintained in-situ viscosity at low flow rates indicating that improved injectivity can be achieved without compromising viscosity at reservoir flow rates. This is explained by a reduction in viscoelasticity. Mechanical degradation also leads to reduced residual resistance factor (RRF), especially for high polymer concentrations. For some of the polymer injections, successive degradation (increased degradation with transport length in porous media) was observed. The results presented here may be used to optimize polymer injectivity. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery 2019)

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