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16 pages, 57241 KiB

Open AccessArticle

Analysis of Hydraulic Fracturing Efficiency Considering the Principal Stress in Brushy Canyon Formation of the Permian Basin

by Hyemin Park, Wonmo Sung and Jihoon Wang

Appl. Sci. 2021, 11(3), 1069; https://doi.org/10.3390/app11031069 - 25 Jan 2021

Viewed by 1958

Abstract

The purpose of this study is to investigate the effect of principal stress direction on the efficiency of hydraulic fracturing treatment. There are two different drilling scenarios: 1. Four horizontal wells drilled in four orthogonal directions regardless of in-situ stress condition (“Actual”). 2. [...] Read more.

The purpose of this study is to investigate the effect of principal stress direction on the efficiency of hydraulic fracturing treatment. There are two different drilling scenarios: 1. Four horizontal wells drilled in four orthogonal directions regardless of in-situ stress condition (“Actual”). 2. Three horizontal wells drilled equivalent to “Actual” case by considering the direction of principal stress (“Proposed”). The hydraulic fracturing modeling was carried out based on well logging data and completion reports of Brushy Canyon formation, Permian Basin. In the results of “Actual” case, transverse fractures were generated in two horizontal wells drilled parallel to σ_hmin-dir (direction of σ_hmin), similar to “Proposed” case. Meanwhile, for two other wells drilled perpendicular to σ_hmin-dir, longitudinal fractures were generated. These obliquely deviated fractures significantly decreased the fracture spacing between the stages up to 26%. This induced great stress shadow, however, the fractures propagated straight due to the large stress anisotropy of 2000 psi (σ_Hmax/σ_hmin = 1.4). Therefore, it was found that due to the different direction of fracture propagation in “Actual” case, “Proposed” case was 14.6% of stimulated reservoir volume (SRV) higher. In conclusion, for successful hydraulic fracturing treatment, the direction of horizontal well must be determined in consideration of the principal stress direction as well as stress anisotropy. Full article

(This article belongs to the Special Issue Advanced Oil Recovery Technologies)

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10 pages, 6352 KiB

Open AccessArticle

Effect of Capillary Number on the Residual Saturation of Colloidal Dispersions Stabilized by a Zwitterionic Surfactant

by Han Am Son and Taewoong Ahn

Appl. Sci. 2021, 11(2), 524; https://doi.org/10.3390/app11020524 - 7 Jan 2021

Cited by 4 | Viewed by 2158

Abstract

We investigated oil recovery from porous rock using nanoscale colloidal dispersions, formed by adsorption of an anionic polymer [poly-(4styrenesulfonic acid-co-maleic acid); PSS-co-MA] and a zwitterionic surfactant [N-tetradecyl-N, N-dimethyl-3-ammonio-1-propanesulfonate, TPS] onto silica nanoparticles. In an emulsion, colloidal [...] Read more.

We investigated oil recovery from porous rock using nanoscale colloidal dispersions, formed by adsorption of an anionic polymer [poly-(4styrenesulfonic acid-co-maleic acid); PSS-co-MA] and a zwitterionic surfactant [N-tetradecyl-N, N-dimethyl-3-ammonio-1-propanesulfonate, TPS] onto silica nanoparticles. In an emulsion, colloidal dispersion enhanced the stability of the oil-water interface in the absence of particle aggregation; the hydrophobic alkyl chains of TPS shifted into the oil drop, not only physiochemically, stabilizing the oil-water interface, but also promoting repulsive particle-to-particle interaction. Core flooding experiments on residual oil saturation as a function of capillary number, at various injection rates and oil viscosities, showed that the residual oil level was reduced by almost half when the zwitterionic surfactant was present in the colloidal dispersion. Consequently, the result revealed that this colloidal dispersion at the interface provides a mechanically robust layer at the oil-water interface without particle aggregation. Thus, the dispersion readily entered the pore throat and adhered to the oil-water interface, lowering the interfacial tension and improving oil recovery. Full article

(This article belongs to the Special Issue Advanced Oil Recovery Technologies)

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14 pages, 7628 KiB

Open AccessArticle

Compositional Modeling of Dimethyl Ether–CO₂ Mixed Solvent for Enhanced Oil Recovery

by Young Woo Lee, Hye Seung Lee, Moon Sik Jeong, Jinhyung Cho and Kun Sang Lee

Appl. Sci. 2021, 11(1), 406; https://doi.org/10.3390/app11010406 - 4 Jan 2021

Cited by 9 | Viewed by 2854

Abstract

Dimethyl ether (DME) is a compound first introduced by Shell as a chemical solvent for enhanced oil recovery (EOR). This study aims to investigate the efficiency of EOR using the minimum miscible pressure (MMP) and viscous gravity number when a mixed solvent of [...] Read more.

Dimethyl ether (DME) is a compound first introduced by Shell as a chemical solvent for enhanced oil recovery (EOR). This study aims to investigate the efficiency of EOR using the minimum miscible pressure (MMP) and viscous gravity number when a mixed solvent of CO₂ and DME is injected. Adding DME to the CO₂ water-alternating-gas process reduces the MMP and viscous gravity number. Reduction in MMP results in miscible conditions at lower pressures, which has a favorable effect on oil swelling and viscosity reduction, leading to improved mobility of the oil. In addition, the viscous gravity number decreases, increasing the sweep efficiency by 26.6%. Numerical studies were conducted through a series of multi-phase, multi-component simulations. At a DME content of 25%, the MMP decreased by 30.1% and the viscous gravity number decreased by 66.4% compared with the injection of CO₂ only. As a result, the maximum oil recovery rate increased by 31% with simultaneous injection of DME and CO₂ compared with only using CO₂. Full article

(This article belongs to the Special Issue Advanced Oil Recovery Technologies)

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11 pages, 2810 KiB

Open AccessArticle

The Effect of Carbonyl and Hydroxyl Compounds Addition on CO₂ Injection through Hydrocarbon Extraction Processes

by Asep Kurnia Permadi, Egi Adrian Pratama, Andri Luthfi Lukman Hakim, Alfanda Kurnia Widi and Doddy Abdassah

Appl. Sci. 2021, 11(1), 159; https://doi.org/10.3390/app11010159 - 26 Dec 2020

Cited by 4 | Viewed by 4029

Abstract

CO₂ miscible flooding occurs when injection pressure is higher than the minimum miscibility pressure (MMP) which can exceed the fracture pressure. Co-solvents are expected to reduce the MMP by interacting with various hydrocarbons that depend on the polarity and intermolecular forces of [...] Read more.

CO₂ miscible flooding occurs when injection pressure is higher than the minimum miscibility pressure (MMP) which can exceed the fracture pressure. Co-solvents are expected to reduce the MMP by interacting with various hydrocarbons that depend on the polarity and intermolecular forces of solvent and oil. However, there are limited studies that have investigated co-solvent performance in CO₂ injection through an extraction process based on oil compositional analysis. This paper is aimed at studying the effects of carbonyl and hydroxyl compounds on oil extraction and also the mutual interactions of CO₂-oil-carbonyl and -hydroxyl. The experiment is conducted by using VIPS (viscosity, interfacial tension, pressure-volume, and swelling) and gas chromatography (GC) apparatuses. The compositional results from GC are utilized to analyze the performance of co-solvents, which are further classified based on the carbon number and molecular structure of oil. Acetone is a non-associated polar compound which reacts easily with and assists CO₂ to extract polar-aromatic heavy and slightly polar components such as alkenes and straight-chain alkanes, due to high polarizability and low cohesive forces. Ethanol is a self-associated polar compound which has the capability of extracting high-boiling fractions and slightly polar-aromatic components. Moreover, both co-solvents also assist CO₂ to extract non-polar components because they have non-polar end in the alkyl group. Full article

(This article belongs to the Special Issue Advanced Oil Recovery Technologies)

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24 pages, 9528 KiB

Open AccessArticle

Effect of Thermal Exposure on Oil Shale Saturation and Reservoir Properties

by Aliya Mukhametdinova, Polina Mikhailova, Elena Kozlova, Tagir Karamov, Anatoly Baluev and Alexey Cheremisin

Appl. Sci. 2020, 10(24), 9065; https://doi.org/10.3390/app10249065 - 18 Dec 2020

Cited by 9 | Viewed by 2514

Abstract

The experimental and numerical modeling of thermal enhanced oil recovery (EOR) requires a detailed laboratory analysis of core properties influenced by thermal exposure. To acquire the robust knowledge on the change in rock saturation and reservoir properties, the fastest way is to examine [...] Read more.

The experimental and numerical modeling of thermal enhanced oil recovery (EOR) requires a detailed laboratory analysis of core properties influenced by thermal exposure. To acquire the robust knowledge on the change in rock saturation and reservoir properties, the fastest way is to examine the rock samples before and after combustion. In the current paper, we studied the shale rock properties, such as core saturation, porosity, and permeability, organic matter content of the rock caused by the combustion front propagation within the experimental modeling of the high-pressure air injection. The study was conducted on Bazhenov shale formation rock samples. We reported the results on porosity and permeability evolution, which was obtained by the gas pressure-decay technique. The measurements revealed a significant increase of porosity (on average, for 9 abs. % of porosity) and permeability (on average, for 1 mD) of core samples after the combustion tube experiment. The scanning electron microscopy showed the changes induced by thermal exposure: the transformation of organic matter with and the formation of new voids and micro and nanofractures in the mineral matrix. Low-field Nuclear Magnetic Resonance (NMR) was chosen as a primary non-disruptive tool for measuring the saturation of core samples in ambient conditions. NMR T₁–T₂ maps were interpreted to determine the rock fluid categories (bitumen and adsorbed oil, structural and adsorbed water, and mobile oil) before and after the combustion experiment. Changes in the distribution of organic matter within the core sample were examined using 2D Rock-Eval pyrolysis technique. Results demonstrated the relatively uniform distribution of OM inside the core plugs after the combustion. Full article

(This article belongs to the Special Issue Advanced Oil Recovery Technologies)

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16 pages, 6706 KiB

Open AccessFeature PaperArticle

Compositional Modeling to Analyze the Effect of CH₄ on Coupled Carbon Storage and Enhanced Oil Recovery Process

by Jinhyung Cho, Gayoung Park, Seoyoon Kwon, Kun Sang Lee, Hye Seung Lee and Baehyun Min

Appl. Sci. 2020, 10(12), 4272; https://doi.org/10.3390/app10124272 - 22 Jun 2020

Cited by 11 | Viewed by 2854

Abstract

The present study is aimed at the development of compositional simulation models of the co-injection of CO₂ and CH₄ during the water-alternating-gas (WAG) process in order to assess the efficiency of carbon capture and storage in combination with enhanced oil recovery [...] Read more.

The present study is aimed at the development of compositional simulation models of the co-injection of CO₂ and CH₄ during the water-alternating-gas (WAG) process in order to assess the efficiency of carbon capture and storage in combination with enhanced oil recovery (CCS-EOR). The co-injection of CO₂ and CH₄ occupies more reservoir pore volume and causes higher reservoir pressure than CO₂ WAG, thus leading to an enhanced early EOR performance. However, the overall EOR performance of the co-injection method becomes lower than that of CO₂ WAG due to the reduced miscibility and sweep efficiency upon further CH₄ addition. The decrease in gas displacement and sweep efficiency weaken the hysteresis effects upon the residual trapping mechanism. However, the solubility trapping mechanism takes effect because the co-injection generates higher average reservoir pressure than does the CO₂ WAG. The index of global warming potential (GWP) in a mole unit is employed to quantify the carbon storage effects of CO₂ and co-injection WAG cases. According to the index, 1 mole of CH₄ sequestration has the same effects as that of 10 moles of CO₂ for global warming mitigation. In conclusion, the carbon storage effects are enhanced as CH₄ concentration in the WAG increases. Full article

(This article belongs to the Special Issue Advanced Oil Recovery Technologies)

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25 pages, 10173 KiB

Open AccessArticle

An Elongational and Shear Evaluation of Polymer Viscoelasticity during Flow in Porous Media

by Muhammad Tahir, Rafael E. Hincapie and Leonhard Ganzer

Appl. Sci. 2020, 10(12), 4152; https://doi.org/10.3390/app10124152 - 17 Jun 2020

Cited by 4 | Viewed by 2371

Abstract

This paper uses a combination of approaches to evaluate the viscoelastic phenomenon in high-molecular-weight polymers (24–28 M Daltons) used for enhanced oil recovery (EOR) applications. Rheological data were cross-analyzed with single- and two-phase polymer flooding experiments in outcrop cores and micromodels, respectively. First, [...] Read more.

This paper uses a combination of approaches to evaluate the viscoelastic phenomenon in high-molecular-weight polymers (24–28 M Daltons) used for enhanced oil recovery (EOR) applications. Rheological data were cross-analyzed with single- and two-phase polymer flooding experiments in outcrop cores and micromodels, respectively. First, the impact of semi-harsh conditions (salinity, hardness, and temperature) was evaluated. Second, the impact of polymer degradation (sand face flow), focusing on the viscoelastic properties, was investigated. Finally, polymer viscoelastic properties were characterized, proposing a threefold rheological approach of rotational, oscillatory, and elongational behavior. Data from the rheological approaches were cross-analyzed with core flooding experiments and performed at a room temperature of 22 °C and at a higher temperature of 55 °C. The change in polymer viscoelastic properties were analyzed by investigating the effluents from core flooding experiments. Oil recovery experiments in micromodel helped our understanding of whether salinity or hardness has a dominating impact on in situ viscoelastic polymer response. These approaches were used to study the impact of mechanical degradation on polymer viscoelasticity. The brines showed notable loss in polymer viscoelastic properties, specifically with the hard brine and at higher temperature. However, the same polymer solution diluted in deionized water exhibited stronger viscoelastic properties. Multiple flow-behaviors, such as Newtonian, shear thinning, and thickening dominated flow, were confirmed through pressure drop analysis against interstitial velocity as already reported by other peer researchers. Turbulence-dominated excessive pressure drop in porous media was calculated by comparing core flood pressure drop data against pressure data in extensional viscometer–rheometer on a chip (eVROC^®). In addition, a significant reduction in elastic-dominated flow was confirmed through the mechanical degradation that happened during core flood experiments, using various approaches. Finally, reservoir harsh conditions (high temperature, hardness, and salinity) resulted in a significant reduction in polymer viscoelastic behavior for all approaches. Full article

(This article belongs to the Special Issue Advanced Oil Recovery Technologies)

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14 pages, 2430 KiB

Open AccessArticle

Nonionic Surfactant to Enhance the Performances of Alkaline–Surfactant–Polymer Flooding with a Low Salinity Constraint

by Shabrina Sri Riswati, Wisup Bae, Changhyup Park, Asep K. Permadi and Adi Novriansyah

Appl. Sci. 2020, 10(11), 3752; https://doi.org/10.3390/app10113752 - 28 May 2020

Cited by 5 | Viewed by 3255

Abstract

This paper presents a nonionic surfactant in the anionic surfactant pair (ternary mixture) that influences the hydrophobicity of the alkaline–surfactant–polymer (ASP) slug within low-salinity formation water, an environment that constrains optimal designs of the salinity gradient and phase types. The hydrophobicity effectively reduced [...] Read more.

This paper presents a nonionic surfactant in the anionic surfactant pair (ternary mixture) that influences the hydrophobicity of the alkaline–surfactant–polymer (ASP) slug within low-salinity formation water, an environment that constrains optimal designs of the salinity gradient and phase types. The hydrophobicity effectively reduced the optimum salinity, but achieving as much by mixing various surfactants has been challenging. We conducted a phase behavior test and a coreflooding test, and the results prove the effectiveness of the nonionic surfactant in enlarging the chemical applicability by making ASP flooding more hydrophobic. The proposed ASP mixture consisted of 0.2 wt% sodium carbonate, 0.25 wt% anionic surfactant pair, and 0.2 wt% nonionic surfactant, and 0.15 wt% hydrolyzed polyacrylamide. The nonionic surfactant decreased the optimum salinity to 1.1 wt% NaCl compared to the 1.7 wt% NaCl of the reference case with heavy alcohol present instead of the nonionic surfactant. The coreflooding test confirmed the field applicability of the nonionic surfactant by recovering more oil, with the proposed scheme producing up to 74% of residual oil after extensive waterflooding compared to 51% of cumulative oil recovery with the reference case. The nonionic surfactant led to a Winsor type III microemulsion with a 0.85 pore volume while the reference case had a 0.50 pore volume. The nonionic surfactant made ASP flooding more hydrophobic, maintained a separate phase of the surfactant between the oil and aqueous phases to achieve ultra-low interfacial tension, and recovered the oil effectively. Full article

(This article belongs to the Special Issue Advanced Oil Recovery Technologies)

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25 pages, 10550 KiB

Open AccessArticle

Flow Dynamics of Sulfate-Modified Water/Polymer Flooding in Micromodels with Modified Wettability

by Muhammad Tahir, Rafael E. Hincapie, Calvin L. Gaol, Stefanie Säfken and Leonhard Ganzer

Appl. Sci. 2020, 10(9), 3239; https://doi.org/10.3390/app10093239 - 7 May 2020

Cited by 7 | Viewed by 2657

Abstract

This work describes the flow behavior of the oil recovery obtained by the injection of sulfate-modified/low-salinity water in micromodels with different wettabilities. It provides a detailed microscopic visualization of the displacement taking place during modified water flooding at a pore-scale level, while evaluating [...] Read more.

This work describes the flow behavior of the oil recovery obtained by the injection of sulfate-modified/low-salinity water in micromodels with different wettabilities. It provides a detailed microscopic visualization of the displacement taking place during modified water flooding at a pore-scale level, while evaluating the effect of wettability on oil recovery. A comprehensive workflow for the evaluation is proposed that includes fluid–fluid and rock–fluid interactions. The methods studied comprise flooding experiments with micromodels. Artificial and real structure water-wet micromodels are used to understand flow behavior and oil recovery. Subsequently, water-wet, complex-wet, and oil-wet micromodels help understand wettability and rock–fluid interaction. The effect of the sulfate content present in the brine is a key variable in this work. The results of micromodel experiments conducted in this work indicate that sulfate-modified water flooding performs better in mixed-wet/oil-wet (artificial structure) than in water-wet systems. This slightly differs from observations of core flood experiments, where oil-wet conditions provided better process efficiency. As an overall result, sulfate-modified water flooding recovered more oil than SSW injection in oil-wet and complex-wet systems compared to water-wet systems. Full article

(This article belongs to the Special Issue Advanced Oil Recovery Technologies)

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