Enhanced Oil Recovery Technologies

Journal Name	Impact Factor	CiteScore	Launched Year	First Decision (median)	APC
Applied Sciences applsci	2.5	5.3	2011	18.4 Days	CHF 2400
Energies energies	3.0	6.2	2008	16.8 Days	CHF 2600

20 pages, 6608 KiB

Open AccessArticle

Synthesis and Mechanical Properties of Polyacrylamide Gel Doped with Graphene Oxide

by Hai-Peng Zhang, Jing-Jing Cao, Wen-Bing Jiang, Yu-Qi Yang, Bo-Yuan Zhu, Xiao-Yu Liu, Yang Wu, Xin Sun, Ariane Felicite Bibiche Essouma Essouma, Jian Liu and Ting-Yan Xing

Energies 2022, 15(15), 5714; https://doi.org/10.3390/en15155714 - 5 Aug 2022

Cited by 12 | Viewed by 3335

Abstract

Polyacrylamide (PAM)/polyethyleneimine (PEI) gels doped with graphene oxide (GO) were prepared. Their structure and properties were systematically studied by X-ray diffraction (XRD), Fourier transition infrared spectrum (FT-IR), Raman spectroscopy, scanning electron microscopy (SEM), differential scanning calorimetry (DSC), and rheological experiments. The results showed [...] Read more.

Polyacrylamide (PAM)/polyethyleneimine (PEI) gels doped with graphene oxide (GO) were prepared. Their structure and properties were systematically studied by X-ray diffraction (XRD), Fourier transition infrared spectrum (FT-IR), Raman spectroscopy, scanning electron microscopy (SEM), differential scanning calorimetry (DSC), and rheological experiments. The results showed that the graphene oxide (GO) nanosheets were significantly involved in the cross-linking reaction between the main agent (PAM) and the cross-linker (PEI), serving as multi-functional cross-linker and effective reinforcing nanofillers. Increasing the main agent and cross-linker content, the strength of gels was enhanced effectively. The GO could effectively adjust the strength and the gelation time to exhibit characteristics of weak gel, thanks to the improved three-dimensional honeycombed structure with controllable pore size. The DSC confirmed that the PAM/PEI/GO gel exhibited excellent thermal stability and did not dehydrate above 170 °C. This work provides theoretical support for further optimization of polyacrylamide gel used in ultra-deep and high-temperature reservoirs for water control. Full article

(This article belongs to the Topic Enhanced Oil Recovery Technologies)

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29 pages, 8995 KiB

Open AccessArticle

Investigation of the Effect of Capillary Barrier on Water–Oil Movement in Water Flooding

by Bingtao Hu, Zhaolin Gu, Chenxing Zhou, Le Wang, Chuanqing Huang and Junwei Su

Appl. Sci. 2022, 12(12), 6285; https://doi.org/10.3390/app12126285 - 20 Jun 2022

Cited by 10 | Viewed by 2734

Abstract

Water flooding technology is widely used to improve oil recovery efficiency in oilfields. The capillary barrier effect induced by the complex pore structures in the reservoir rocks is a crucial reason for the trapping of a great deal of residual oil in oil [...] Read more.

Water flooding technology is widely used to improve oil recovery efficiency in oilfields. The capillary barrier effect induced by the complex pore structures in the reservoir rocks is a crucial reason for the trapping of a great deal of residual oil in oil reservoirs after water flooding. However, the formation condition along with the effect on the recovery rate of the capillary barrier under different wettability conditions should be investigated further. To bridge the gap between the microscopic mechanism of the capillary barrier effect and the macroscopic mechanism of oil displacement efficiency, a simple conceptual capillary model is constructed to obtain the formation conditions of the capillary barrier using the analysis method, and its influence on macroscopic oil displacement efficiency in the porous media model with an opening angle of 45° is systematically investigated in this study using direct numerical simulations (DNS) coupled with the volume of fluid method. The results showed that the capillary barrier effect plays a significant role in the formation of the residual oil in the reservoir rock and the contact angle and the opening angle are the primary factors for the formation of the capillary barrier. The capillary force is the driving force when the oil–water interface advances in the throat channel under water-wet conditions, while the capillary force hinders the movement of oil–water movement when the liquid flows out of the throat channel and when θ + β > 90^o. Furthermore, the highest oil displacement efficiency is achieved at the intermediate capillary number and in the case that the minimum conditions of occurrence of the capillary barrier phenomenon are satisfied. This is of great significance for controlling the optimized contact angle to further enhance the oil recovery rate of current oil reservoirs using waterflooding technology. Full article

(This article belongs to the Topic Enhanced Oil Recovery Technologies)

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14 pages, 538 KiB

Open AccessReview

A Critical Review of Alkaline Flooding: Mechanism, Hybrid Flooding Methods, Laboratory Work, Pilot Projects, and Field Applications

by Abdelaziz L. Khlaifat, Duaa Dakhlallah and Faraz Sufyan

Energies 2022, 15(10), 3820; https://doi.org/10.3390/en15103820 - 22 May 2022

Cited by 23 | Viewed by 5931

Abstract

Over time, the dependence on oil has increased to meet industrial and domestic needs. Enhanced oil recovery (EOR) techniques in this regard have captured immense growth as EOR is not only used to increase the oil recovery but also to augment the sweep [...] Read more.

Over time, the dependence on oil has increased to meet industrial and domestic needs. Enhanced oil recovery (EOR) techniques in this regard have captured immense growth as EOR is not only used to increase the oil recovery but also to augment the sweep efficiency. Several techniques over the past decades have been used to improve oil recovery with cost-effectiveness. Cost-effective alkaline flooding has been effective for those oil reservoirs with a high total acid number. In this review, the significance of alkaline flooding has been discussed in detail, as well as the features of alkaline flooding in comparison to other modes of flooding. This review entails (1) alkaline flooding, (2) hybrid modes of injection, (3) experimental work, (4) pilot projects, (5) screening criteria, and (6) field applications. The findings of this study can help increase the understanding of alkaline flooding and provide a holistic view of the hybrid modes of flooding. Full article

(This article belongs to the Topic Enhanced Oil Recovery Technologies)

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15 pages, 8150 KiB

Open AccessArticle

An Improved Method of Clay-Induced Rock Typing Derived from Log Data in Modelling Low Salinity Water Injection: A Case Study on an Oil Field in Indonesia

by Hafizh Zakyan, Asep Kurnia Permadi, Egi Adrian Pratama and Muhammad Arif Naufaliansyah

Energies 2022, 15(10), 3749; https://doi.org/10.3390/en15103749 - 19 May 2022

Viewed by 2426

Abstract

Low salinity water injection (LSWI) is an emerging way to improve waterflood performance through chemical processes. The presence of clay minerals is one of the required parameters to successfully implement LSWI in sandstone formations. The ability of clays to exchange the cations, represented [...] Read more.

Low salinity water injection (LSWI) is an emerging way to improve waterflood performance through chemical processes. The presence of clay minerals is one of the required parameters to successfully implement LSWI in sandstone formations. The ability of clays to exchange the cations, represented by cation exchange capacity (CEC), leads to oil detachment from the rock surface and changes the formation wettability toward water-wet. There are still limited studies that discuss the implementation of specific CEC models in the field-scale LSWI reservoir simulation. This paper attempts to propose an improved method of clay-induced rock typing that can be representatively implemented for field-scale reservoir simulation. The scope of this study is limited to a sandstone reservoir from an oil field in Indonesia. The oil is considered light, and the reservoir contains main clay minerals, including kaolinite and illite, and a trace of chlorite was also found from the XRD evaluation. CEC can be derived from log data, while rock type can also be estimated from log data by using the artificial neural network method. The main finding is that the combination of those variables, i.e., log data, rock properties, and CEC, results in an improved method to characterize and classify the clay into three types associated with conventional rock types. The classification obtained by the clay typing method can be utilized as an input for advanced LSWI modeling, which is expected to provide more robust results. Furthermore, dispersed clay has a strong influence on the magnitude of cation exchange capacity rather than laminar and structural clays. Full article

(This article belongs to the Topic Enhanced Oil Recovery Technologies)

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20 pages, 35472 KiB

Open AccessArticle

Numerical Simulation of Oil Shale Pyrolysis under Microwave Irradiation Based on a Three-Dimensional Porous Medium Multiphysics Field Model

by Hao Wang, Xiaogang Li, Jingyi Zhu, Zhaozhong Yang, Jie Zhou and Liangping Yi

Energies 2022, 15(9), 3256; https://doi.org/10.3390/en15093256 - 29 Apr 2022

Cited by 5 | Viewed by 2442

Abstract

The pyrolysis characteristics of oil shale during heat treatment dominate the oil production of kerogen. In this study, the pyrolysis characteristics of oil shale in a laboratory microwave apparatus were investigated based on a novel fully coupled three-dimensional electromagnetic-thermal-chemical-hydraulic model according to the [...] Read more.

The pyrolysis characteristics of oil shale during heat treatment dominate the oil production of kerogen. In this study, the pyrolysis characteristics of oil shale in a laboratory microwave apparatus were investigated based on a novel fully coupled three-dimensional electromagnetic-thermal-chemical-hydraulic model according to the experimental microwave apparatus. By simulating the electric field, temperature distribution, and kerogen decomposition within oil shale subjected to microwave irradiation, several parameters, including waveguide, position, and power, were successfully optimized. The results indicated that the non-uniform temperature distribution was consistent with the distribution of the electric field. Double microwave ports were more effective than single ports in terms of heating rate and temperature uniformity. There was an optimal location where the highest heating efficiency was obtained, which was on the left of the cavity center. When irradiation was conducted over a range of microwave powers, a higher power was suitable for achieving a rapid temperature increase, whereas a lower power was suitable to gain a high efficiency of the pyrolysis rate. Therefore, a variable power heating mode was introduced to decrease the heating time and improve the heat uniformity simultaneously during oil shale pyrolysis. Specifically, the secondary reactions of oil products should be maximally avoided by controlling the microwave power. Full article

(This article belongs to the Topic Enhanced Oil Recovery Technologies)

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14 pages, 21064 KiB

Open AccessArticle

Surface Complexation Modelling of Wettability Alteration during Carbonated Water Flooding

by Fagan Mehdiyev, Samuel Erzuah, Aruoture Omekeh and Ingebret Fjelde

Energies 2022, 15(9), 3020; https://doi.org/10.3390/en15093020 - 20 Apr 2022

Cited by 8 | Viewed by 2175

Abstract

CO₂ capture and utilization is an effective tool in reducing greenhouse gas emissions and hence, combating global warming. In the present study, surface complexation modeling (SCM) with the geochemistry solver, PHREEQ-C, was utilized to predict the wettability alteration of minerals, sandstone reservoir [...] Read more.

CO₂ capture and utilization is an effective tool in reducing greenhouse gas emissions and hence, combating global warming. In the present study, surface complexation modeling (SCM) with the geochemistry solver, PHREEQ-C, was utilized to predict the wettability alteration of minerals, sandstone reservoir rocks (SRR), and pseudo-sandstone rocks (PSR) and mineral mixtures during carbonated water (CW) injection. The bond products, which is defined as the product of the mole fraction of oppositely charged mineral and oil surfaces, were calculated to estimate the wettability preferences. For the studied fluid systems, the results from SCM predicted that albite and quartz minerals were strongly water-wet while calcite was strongly oil-wet with formation water (FW). When it came to clay minerals, illite and montmorillonite were more oil-wet than quartz and less oil-wet than calcite. During CW injection (CWI), the wettability preferences of dominant minerals (considering weight and surface area) in SRR (i.e., quartz and calcite) were changed toward more water-wet, while for the clay minerals, the result was the opposite. The results from SCM showed that the wettability preferences of SRR were water-wet in both CW and FW. Moreover, increasing the amount of the water-wet minerals in mineral mixtures increased the rock’s tendency to become more water-wet. Full article

(This article belongs to the Topic Enhanced Oil Recovery Technologies)

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17 pages, 4980 KiB

Open AccessArticle

A New CO₂-EOR Methods Screening Model Based on Interdependency Parameters

by Diyah Rosiani, Asep Kurnia Permadi, Hasian Parlindungan Septoratno Siregar, Agus Yodi Gunawan and Tutuka Ariadji

Appl. Sci. 2022, 12(8), 3937; https://doi.org/10.3390/app12083937 - 13 Apr 2022

Cited by 7 | Viewed by 3371

Abstract

The successful implementation of carbon dioxide-enhanced oil recovery (CO₂-EOR) is crucial in increasing oil production and reducing carbon emissions. For this reason, screening criteria are needed for the initial characterization of a suitable CO₂-EOR reservoir. The existing screening model [...] Read more.

The successful implementation of carbon dioxide-enhanced oil recovery (CO₂-EOR) is crucial in increasing oil production and reducing carbon emissions. For this reason, screening criteria are needed for the initial characterization of a suitable CO₂-EOR reservoir. The existing screening model treats the screening parameters independently. Therefore, each parameter has its criteria limit and does not relate to the others. However, in reality, several screening parameters are interdependent, so we need a method that treats the interdependent parameters simultaneously. This research develops a new simultaneous screening model using the interdependency of the parameters. Quantitative and actual data were collected from CO₂-EOR field documentation worldwide with a comprehensive analysis. A statistical approach with a correlation analysis method was used to determine the interconnected screening parameters. The results were synchronized with the expert domain to match actual physical conditions. The limit of simultaneous screening criteria was acquired by multivariate quality control (MQC) based on the principal component analysis (PCA) method. The proposed screening model was compared with 13 actual projects, and demonstrated improvements to previous models. The results match actual operations and follow the expert domain rules. If the miscible CO₂-EOR is met, then the immiscible should also be appropriate but not vice versa. Nevertheless, four different immiscible projects are predicted to be slightly optimistic as miscible or immiscible. Full article

(This article belongs to the Topic Enhanced Oil Recovery Technologies)

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2 pages, 655 KiB

Open AccessCorrection

Correction: Althalb et al. A Novel Approach to Enhance Crude Oil Recovery Ratio Using Selected Bacterial Species. Appl. Sci. 2021, 11, 10492

by Hakima A. Althalb, Izzeddin M. Elmusrati and Ibrahim M. Banat

Appl. Sci. 2022, 12(6), 3099; https://doi.org/10.3390/app12063099 - 18 Mar 2022

Viewed by 1292

Abstract

In the original publication [...] Full article

(This article belongs to the Topic Enhanced Oil Recovery Technologies)

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14 pages, 3490 KiB

Open AccessArticle

Study on the Mechanism of Fiber Fracturing Fluid Controlling Pulverized Coal Transportation

by Wei Wang and Haifeng Zhao

Energies 2022, 15(6), 2165; https://doi.org/10.3390/en15062165 - 16 Mar 2022

Cited by 6 | Viewed by 2101

Abstract

In view of the problems associated with coal powder production in the development of Coalbed Methane (CBM), a fiber fracturing fluid technology is proposed to control pulverized coal production. Based on a force analysis of coal powder in the fracture and the microstructure [...] Read more.

In view of the problems associated with coal powder production in the development of Coalbed Methane (CBM), a fiber fracturing fluid technology is proposed to control pulverized coal production. Based on a force analysis of coal powder in the fracture and the microstructure of fiber-proppant, a critical intercepted particle size model of coal powder is established. This model is primarily related to fiber properties, proppant particle size and flow rate. To verify this, an FCES-100 device (Nantong Yichuang Experimental Instrument Co., Ltd., Nantong, China) was used to study the influence of fibers on the transportation of pulverized coal in the proppant pack. Five groups of comparative experiments were set up using no fiber, 0.25 g undegraded fiber, 0.25 g degradable fiber, 0.5 g undegraded fiber and 0.5 g degraded fiber, with the flow rate and closure pressures controlled, and, finally, particle size analysis of the discharged pulverized coal was performed using a laser particle size analyzer. The experimental results have shown that the space network structure formed by fiber-proppant can effectively intercept coal powder, reduce the coal powder migration and agglomeration, and eventually improve the fracture conductivity. The results further indicate that, with the increase of the flow rate, the coal particle size shows an increasing trend. The comparison between the particle size of the pulverized coal and the model calculation results demonstrate that the average error is 14.3% and the maximum error is 21.4%. Fiber fracturing fluid technology provides new directions for pulverized coal treatment. Full article

(This article belongs to the Topic Enhanced Oil Recovery Technologies)

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16 pages, 8483 KiB

Open AccessArticle

Experimental Study on Oil Drop Discharge Behavior during Dynamic Imbibition in Tight Oil Sandstone with Aid of Surfactant

by Yan Xin, Yongpeng Sun, Fei Ding, Ang Chen, Wenxun Zhao, Yanchao Fang, Li’nan Wei and Caili Dai

Energies 2022, 15(4), 1533; https://doi.org/10.3390/en15041533 - 18 Feb 2022

Viewed by 1971

Abstract

The pore and throat structure of tight oil reservoir cores is complex, and the resistance of oil drop to discharge from the core is very high during dynamic imbibition. Surfactant has good ability in interfacial tension reduction and wettability reversal. It can reduce [...] Read more.

The pore and throat structure of tight oil reservoir cores is complex, and the resistance of oil drop to discharge from the core is very high during dynamic imbibition. Surfactant has good ability in interfacial tension reduction and wettability reversal. It can reduce oil drop discharge resistance and enhance oil recovery effectively during dynamic imbibition in tight reservoirs. Here, we first analyzed the pore throat structure and mineral composition of tight core, and then the oil drop visualization instrument was used to study the discharge behavior of oil drop during dynamic imbibition. The oil drop discharge form was analyzed, and the influence of various factors on the oil drop discharge behavior was explored, and then the dynamic imbibition performance of surfactant in tight cores was obtained. The core throat diameter was mainly distributed in 0.07–1.1 μm, and the hydrophilic mineral content in core reached 50.8%. In the case of fluid flow in fracture, the oil drop discharge from near fracture matrix was faster, and its growth rate in height and width was faster than that without external fluid flow. Within a certain range, with the increase of IFT, the rate of core imbibition increased gradually. When the IFT increased from 0.32 mN/m to 0.59 mN/m, the oil drop rapture time decreased by 66.3%. The growth rate of oil drop discharged from the top and side of the core was faster than that from the bottom surface. Furthermore, it was easier to discharge. With the core thickness reduced by half, the rapture time of oil drop was reduced by 74.7%. For tight reservoirs, hydraulic fracturing can create more fracture surfaces and reduce the size of matrix blocks, which contributes to reduce the oil drop discharge resistance during imbibition and improve the oil recovery. This study provides a basis for surfactant to improve dynamic imbibition and oil production performance of tight sandstone oil reservoir. Full article

(This article belongs to the Topic Enhanced Oil Recovery Technologies)

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14 pages, 21490 KiB

Open AccessArticle

Experimental Study on Tight Sandstone Reservoir Gas Permeability Improvement Using Electric Heating

by Ze Chen, Gao Li, Xu Yang and Yi Zhang

Energies 2022, 15(4), 1438; https://doi.org/10.3390/en15041438 - 16 Feb 2022

Cited by 1 | Viewed by 2071

Abstract

Although tight sandstone gas formations are abundant in China, their single-well productivities and exploitation efficiencies are restricted by water blocking from drilling and completion. At present, shut-in, chemical additive application, and hydraulic fracturing are the common approaches applied to handle this problem. However, [...] Read more.

Although tight sandstone gas formations are abundant in China, their single-well productivities and exploitation efficiencies are restricted by water blocking from drilling and completion. At present, shut-in, chemical additive application, and hydraulic fracturing are the common approaches applied to handle this problem. However, these approaches are also characterized by low efficiencies or even cause secondary damage. In this study, the impact of high temperatures (of up to 800 °C) on the microstructure of a tight sandstone, including water blocking and gas permeability, are investigated through the electric heating of a simulated wellbore. The results show that the threshold temperature for fracturing of the tight sandstone is approximately 450 to 600 °C. Many secondary microcracks emerged near the wellbore beyond this temperature, improving the gas permeability, with some microcracks visible even after cooling. The gas permeability of the formation after heating to 800 °C increased by 456% and 3992% compared with the initial gas permeability and the water-blocking impacted gas permeability, respectively. This study demonstrates that electric heating is a potential method for improving the permeability of tight gas formations. Full article

(This article belongs to the Topic Enhanced Oil Recovery Technologies)

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13 pages, 10648 KiB

Open AccessArticle

Multimodal Carbonates: Distribution of Oil Saturation in the Microporous Regions of Arab Formations

by Tadeusz W. Patzek, Ahmed M. Saad and Ahmed Hassan

Energies 2022, 15(3), 1243; https://doi.org/10.3390/en15031243 - 8 Feb 2022

Cited by 13 | Viewed by 2795

Abstract

Perhaps as much as 50% of the oil-in-place in carbonate formations around the world is locked away in the easy to bypass microporosity. If some of this oil is unlocked by the improved recovery processes focused on tight carbonate formations, the world may [...] Read more.

Perhaps as much as 50% of the oil-in-place in carbonate formations around the world is locked away in the easy to bypass microporosity. If some of this oil is unlocked by the improved recovery processes focused on tight carbonate formations, the world may gain a major source of lower-rate power over several decades. Here, we overview the Arab D formation in the largest oil field on earth, the Ghawar. We investigate the occurrence of microporosity of different origins and sizes using scanning electron microscopy (SEM) and pore casting techniques. Then, we present a robust calculation of the probability of invasion and oil saturation distribution in the nested micropores using mercury injection capillary pressure data available in the literature. We show that large portions of the micropores in Arab D formation would have been bypassed during primary drainage unless the invading crude oil ganglia were sufficiently long. We also show that, under prevailing conditions of primary drainage of the strongly water-wet Arab formations in the Ghawar, the microporosity there was invaded and the porosity-weighted initial oil saturations of 60–85% are expected. Considering the asphaltenic nature of crude oil in the Ghawar, we expect the invaded portions of the pores to turn mixed-wet, thus becoming inaccessible to waterflooding until further measures are taken to modify the system’s surface chemistry and/or create substantial local pore pressure gradients. Full article

(This article belongs to the Topic Enhanced Oil Recovery Technologies)

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11 pages, 2143 KiB

Open AccessArticle

A Study of the Thin Film-Coated Swelling Retarding Particles in Fractured Carbonate Reservoirs for Water Plugging and Profile Control

by Guojun Li, Meilong Fu, Xuejiao Li and Jiani Hu

Energies 2022, 15(3), 1085; https://doi.org/10.3390/en15031085 - 1 Feb 2022

Cited by 10 | Viewed by 2254

Abstract

T oilfield is the fractured-vuggy carbonate reservoir at a temperature of around 130 °C, with salinity of up to 22 × 10⁴ mg/L. In order to solve the problem of the high water cut in the late development stage of T oilfield, [...] Read more.

T oilfield is the fractured-vuggy carbonate reservoir at a temperature of around 130 °C, with salinity of up to 22 × 10⁴ mg/L. In order to solve the problem of the high water cut in the late development stage of T oilfield, we selected XN-T from 27 kinds of swelling retarding particles by testing their swelling capacity, and coated a thin film to improve its retarding swelling capacity. The mechanisms of strong water absorption and water-holding abilities of particles were analyzed by infrared spectrometry and SEM. In the core flow experiment, the plugging rate was found to be 98.42%. Finally, the injection parameters of the coated particles were optimized to maximize the water plugging and profile control ability, resulting in an optimal particle size of 0.4–0.6 mm and a mass fraction of 10%. Full article

(This article belongs to the Topic Enhanced Oil Recovery Technologies)

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20 pages, 5353 KiB

Open AccessArticle

Environmentally Safe Technology to Increase Efficiency of High-Viscosity Oil Production for the Objects with Advanced Water Cut

by Aleksandra Palyanitsina, Elena Safiullina, Roman Byazrov, Dmitriy Podoprigora and Alexey Alekseenko

Energies 2022, 15(3), 753; https://doi.org/10.3390/en15030753 - 20 Jan 2022

Cited by 22 | Viewed by 3494

Abstract

The depletion of conventional oil reserves creates a significant demand for the development and improvement of methods and technologies for the production of hard-to-recover oil. A huge potential for hard-to-recover oil in Western Siberia lies in the Pokur suite (PK). These deposits are [...] Read more.

The depletion of conventional oil reserves creates a significant demand for the development and improvement of methods and technologies for the production of hard-to-recover oil. A huge potential for hard-to-recover oil in Western Siberia lies in the Pokur suite (PK). These deposits are characterized by high oil viscosity and, accordingly, early water breakthrough. This study identifies and substantiates an effective technology for oil production from such and similar deposits using polymer flooding. The obtained data are based on research of the geological structure, the main reservoir properties and those of its fluids, chemical and laboratory methods of analysis, and the results of mathematical and hydrodynamic modeling. According to the results of hydrodynamic modeling, the greatest technological effect of polymeric water flooding is observed in the model of collector permeability at 70 mD and above 1000 mD, but this technology is not recommended for reservoirs with an average permeability of less than 10 mD. Implementation of the best practices through the prism of the resource nexus allows sustainable water management by applying environment-friendly polymers for enhanced oil recovery and contributes to the UN Goal 6 of clean water and sanitation. Full article

(This article belongs to the Topic Enhanced Oil Recovery Technologies)

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16 pages, 2891 KiB

Open AccessArticle

Artificial Neural Network Model Prediction of Bitumen/Light Oil Mixture Viscosity under Reservoir Temperature and Pressure Conditions as a Superior Alternative to Empirical Models

by Ronald Ssebadduka, Nam Nguyen Hai Le, Ronald Nguele, Olalekan Alade and Yuichi Sugai

Energies 2021, 14(24), 8520; https://doi.org/10.3390/en14248520 - 17 Dec 2021

Cited by 8 | Viewed by 3096

Abstract

Herein, we show the prediction of the viscosity of a binary mixture of bitumen and light oil using a feedforward neural network with backpropagation model, as compared to empirical models such as the reworked van der Wijk model (RVDM), modified van der Wijk [...] Read more.

Herein, we show the prediction of the viscosity of a binary mixture of bitumen and light oil using a feedforward neural network with backpropagation model, as compared to empirical models such as the reworked van der Wijk model (RVDM), modified van der Wijk model (MVDM), and Al-Besharah. The accuracy of the ANN was based on all of the samples, while that of the empirical models was analyzed based on experimental results obtained from rheological studies of three binary mixtures of light oil (API 32°) and bitumen (API 7.39°). The classical Mehrotra–Svrcek model to predict the viscosity of bitumen under temperature and pressure, which estimated bitumen results with an %AAD of 3.86, was used along with either the RVDM or the MVDM to estimate the viscosity of the bitumen and light oil under reservoir temperature and pressure conditions. When both the experimental and literature data were used for comparison to an artificial neural network (ANN) model, the MVDM, RVDM and Al-Besharah had higher R² values. Full article

(This article belongs to the Topic Enhanced Oil Recovery Technologies)

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16 pages, 3136 KiB

Open AccessArticle

Optimization and Field Test of a Chelating Acid System for Scaled Gas Wells in the Hechuan Gas Field

by Qiang Li, Zhenzhong Fan, Qingwang Liu, Guohong Liu, Wenhai Ma, Junliang Li, Nan Li and Pingang Ma

Energies 2021, 14(23), 7959; https://doi.org/10.3390/en14237959 - 29 Nov 2021

Cited by 1 | Viewed by 2326

Abstract

The Hechuan gas field is one of the tight gas reservoirs with the highest formation water salinity in China. The content of metal ions, such as calcium, magnesium, iron, and barium, is as high as 20 g/L. Severe scales in near-wellbore reservoir blocks [...] Read more.

The Hechuan gas field is one of the tight gas reservoirs with the highest formation water salinity in China. The content of metal ions, such as calcium, magnesium, iron, and barium, is as high as 20 g/L. Severe scales in near-wellbore reservoir blocks the gas and liquid flow paths, affecting the normal production of gas wells. The analysis of scale samples shows that the scale compositions in the Hechuan gas field are complex, which are composed of calcium carbonate, calcium sulfate, barium sulfate, iron salt, silicate, and other inorganic scales. To dissolve these scales, 14 kinds of laboratory self-made chelating acids named AST-01 to AST-14, sequentially, were evaluated by the descaling rate, in which the chelating acid AST-01 was selected with a dissolution rate of 77.7%. Meanwhile, the optimal concentration and reaction time of AST-01 were investigated, and the concentrations of the corrosion inhibitor, the iron ion stabilizer, and surfactants were also optimized. Then, a chelating acid descaling formula was obtained, which was 15~20% of AST-01 chelating acid + 1.5~2.0% of corrosion inhibitor + 2.5% of iron ion stabilizer + 0.3% of drainage aid. A pilot field trial of this descaling formula was applied in a Hechuan X1 well. A remarkable result was obtained in that the shut-in tubing pressure recovery rate was increased by 14 times, the gas production was increased by 10 times, and the gas well resumed to produce continuously again. Full article

(This article belongs to the Topic Enhanced Oil Recovery Technologies)

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18 pages, 8096 KiB

Open AccessArticle

Effects of Clay Minerals and External Pressures on Imbibition in Shales

by Li Lu, Jianting Li, Xuhui Zhang, Yingjun Li and Fujian Ma

Energies 2021, 14(22), 7528; https://doi.org/10.3390/en14227528 - 11 Nov 2021

Cited by 2 | Viewed by 1703

Abstract

Imbibition is an important mechanism of recovery during waterflooding and low flow-back during fracking in shale reservoirs. Experiments were carried out to study the development of imbibition in shale samples. The effects of clay minerals, especially the illite and IS, were mainly investigated [...] Read more.

Imbibition is an important mechanism of recovery during waterflooding and low flow-back during fracking in shale reservoirs. Experiments were carried out to study the development of imbibition in shale samples. The effects of clay minerals, especially the illite and IS, were mainly investigated and discussed. The imbibition under different pressures was conducted and compared. The influence of clay minerals on imbibition in shale is significant and complex. It is shown that the low content of illite and IS and small capillary force lead to small imbibition mass and speed. Formation of new micro fractures due to the swelling of clay minerals can cause the permeability to increase and the imbibition to be speeded up. The pore structure, the content of IS, and the capillary force affect the imbibition process significantly. The external pressure obviously affects the imbibition speed and the final imbibition mass. The content of clay minerals is more important to the formation of new micro fractures than the external pressure. There is a peak in the curve of displacement efficiency versus the content of either clay minerals or illite and IS. The effect of illite and IS more remarkable. Full article

(This article belongs to the Topic Enhanced Oil Recovery Technologies)

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13 pages, 2032 KiB

Open AccessArticle

A Novel Approach to Enhance Crude Oil Recovery Ratio Using Selected Bacterial Species

by Hakima A. Althalb, Izzeddin M. Elmusrati and Ibrahim M. Banat

Appl. Sci. 2021, 11(21), 10492; https://doi.org/10.3390/app112110492 - 8 Nov 2021

Cited by 3 | Viewed by 2610 | Correction

Abstract

The high viscosity and low flow properties of some crude oil make them difficult to extract from oil reservoirs. This study investigated the mechanisms responsible for the enhancement of oil recovery using fractured dolomite core models. Bacterial strains, Nocardia cyriacigeorgica, Bacillus species, [...] Read more.

The high viscosity and low flow properties of some crude oil make them difficult to extract from oil reservoirs. This study investigated the mechanisms responsible for the enhancement of oil recovery using fractured dolomite core models. Bacterial strains, Nocardia cyriacigeorgica, Bacillus species, and Pseudomonasputida, isolated from Libyan oil fields, had the ability to biotransform heavy crude oil by reducing its viscosity and converting heavier components into lighter ones. The efficiencies of the three bacterial strains were assessed using sand-packed column experiments through the injection of bacteria to mimic in-situ oil recovery. The optimum biotransformation values of Libyan Bouri crude oil were determined as 77.1, 61.2, and 61.1% using the Bacillus sp., P. putida, and Nocardia cyriacigeorgica, respectively, at 55 °C. Viscosity analyses showed that these strains resulted in the reduction of the viscosity of the crude oil at two different temperatures of 37 and 55 °C. The highest recovery of residual oil was about 11.3% using Bacillus sp. The study confirmed that the selected bacterial species were capable of displacing additional oil under simulated oil field conditions. Full article

(This article belongs to the Topic Enhanced Oil Recovery Technologies)

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16 pages, 2877 KiB

Open AccessArticle

Integrity Analysis of the Sheath Considering Temperature Effect under Deep and Large-Scale Multi-Section Hydraulic Fracturing

by Xiaoyu Zhang, Lei Wang, Chunhe Yang, Xin Chang, Yintong Guo, Zhenhui Bi and Hanzhi Yang

Energies 2021, 14(21), 7162; https://doi.org/10.3390/en14217162 - 1 Nov 2021

Cited by 2 | Viewed by 1792

Abstract

Different operations make the borehole temperature change and cause periodic stresses, which often cause variations in the stress state of the sheath or damage. In this paper, the effect of temperature on sheath integrity is investigated. First, the mechanical model of sheath is [...] Read more.

Different operations make the borehole temperature change and cause periodic stresses, which often cause variations in the stress state of the sheath or damage. In this paper, the effect of temperature on sheath integrity is investigated. First, the mechanical model of sheath is established and analyzed by shakedown theory. Then, compression experiments of well cement at different temperatures are carried out, and the law of mechanical properties with temperature is obtained. Finally, combining the theoretical analysis and mechanical experiments, the results show that (1) when only the temperature inside the sheath cyclically varies, the negative influence of temperature caused by the practical operations can be negligible. (2) When the internal pressure and temperature act together, the effect of temperature on the sheath is reflected in temperature stress and the change of the cement properties. (3) With the increase of temperature difference (∆T), the cohesion of cement decreases while the internal friction angle increases, and the plasticity characteristics of the cement are enhanced, and the negative effect on the Pmax ascends slowly. (4) The temperature stress is in a positive relationship with the ∆T, and its weakening on the P_max is about 6% to 7%. (5) Combining the temperature stress and the change of the cement properties, total negative effect of temperature on the sheath accounts for 10% to 12%, when ∆T ranges from 60 to 110 °C. Full article

(This article belongs to the Topic Enhanced Oil Recovery Technologies)

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17 pages, 4791 KiB

Open AccessArticle

An Experimental Study of the Influence of the Preflush Salinity on Enhanced Oil Recovery Using Silica-Based Nanofluids

by Tola Sreu, Kyuro Sasaki, Yuichi Sugai and Ronald Nguele

Energies 2021, 14(21), 6922; https://doi.org/10.3390/en14216922 - 21 Oct 2021

Viewed by 2774

Abstract

The underlying effect of preflush salinity and silica nanofluid (Si-NF) on oil production is examined. The influence of salinity on the stability of Si-NFs is studied. A series of sand-pack floodings evaluating oil production was conducted at different concentrations of preflush salinity (0 [...] Read more.

The underlying effect of preflush salinity and silica nanofluid (Si-NF) on oil production is examined. The influence of salinity on the stability of Si-NFs is studied. A series of sand-pack floodings evaluating oil production was conducted at different concentrations of preflush salinity (0 to 4 wt.%), followed by the injection of a Si-NF (0.5 wt.%) at the trail of which postflush water was injected. The effluent water and solids were collected and analyzed using X-ray fluorescence (XRF). Interfacial tension (IFT) and contact angle measurements were conducted on the Si-NF in the presence of salinity to confirm the effect. The Si-NF became unstable and formed precipitate in the presence of salinity. The sand-pack flooding showed that when the preflush salinity was increased, the displacement efficiency (E_D) using the Si-NF and postflush injection was increased (E_D = 44%). The XRF of the precipitated effluent revealed that the preflush salinity and Si-NF caused mineral leaching, which triggered pore clogging. The IFT value reduced from 13.3 to 8.2 mN/m, and the wettability was altered to be more strongly water-wet when the salinity increased. The primary mechanisms of oil recovery using the Si-NF after preflush salinity is attributed mainly to the clogging mechanism. This clogging helps block the high-perm area, shift the fluid flow to the oil-trapped zone, and free the oil out. Other contribution mechanisms are IFT reduction and wettability alteration. Full article

(This article belongs to the Topic Enhanced Oil Recovery Technologies)

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14 pages, 3409 KiB

Open AccessArticle

Synthesis and Molecular Dynamics Simulation of Amphiphilic Low Molecular Weight Polymer Viscosity Reducer for Heavy Oil Cold Recovery

by Chao Ma, Xingyu Liu, Longlong Xie, Yan Chen, Wendong Ren, Wen Gu, Minghua Zhang and Huili Zhou

Energies 2021, 14(21), 6856; https://doi.org/10.3390/en14216856 - 20 Oct 2021

Cited by 7 | Viewed by 2790

Abstract

In order to reduce the viscosity of heavy oil, the performance of emulsifying viscosity reducers is limited. In this study, a new kind of amphiphilic low molecular weight viscosity reducer was prepared by emulsion copolymerization of acrylamide (AM), acrylic acid (AA), 2-acrylamido-2-methylpropanesulfonic acid [...] Read more.

In order to reduce the viscosity of heavy oil, the performance of emulsifying viscosity reducers is limited. In this study, a new kind of amphiphilic low molecular weight viscosity reducer was prepared by emulsion copolymerization of acrylamide (AM), acrylic acid (AA), 2-acrylamido-2-methylpropanesulfonic acid (AMPS), and Butene benzene (PB). The synthesis feasibility and viscosity reduction mechanism of viscosity reducer in heavy oil were explored using Materials Studio software from the perspective of molecular dynamics. The results of the molecular dynamics simulation revealed that the addition of viscosity reducer into heavy oil varied the potential energy, non-potential energy, density and hydrogen bond distribution of heavy oil. Benefiting from its structure, the benzene ring in PB was well embedded in the interlayer structure of asphaltene, contributing to weaken the network structure of the heavy oil. Moreover, the two strong polar groups (COO⁻ and SO₃⁻) of AA and AMPS, which constituted the branched chains of the viscosity reducer’s molecular structure, gradually disassembled the network structure from the ‘inward’ to the ‘outward’ of the heavy oil network structure, thereby driving heavy oil viscosity reduction (as clarified by molecular dynamics). Owing to its temperature resistance, this kind of new amphiphilic low molecular copolymer could be an effective viscosity reducer for heavy oil cold recovery at elevated temperatures. Full article

(This article belongs to the Topic Enhanced Oil Recovery Technologies)

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25 pages, 6867 KiB

Open AccessReview

Unconventional Well Test Analysis for Assessing Individual Fracture Stages through Post-Treatment Pressure Falloffs: Case Study

by Abdulaziz Ellafi and Hadi Jabbari

Energies 2021, 14(20), 6747; https://doi.org/10.3390/en14206747 - 16 Oct 2021

Cited by 3 | Viewed by 3073

Abstract

Researchers and operators have recently become interested in the individual stage optimization of unconventional reservoir hydraulic fracture. These professionals aim to maximize well performance during an unconventional well’s early-stage and potential Enhanced Oil Recovery (EOR) lifespan. Although there have been advances in hydraulic [...] Read more.

Researchers and operators have recently become interested in the individual stage optimization of unconventional reservoir hydraulic fracture. These professionals aim to maximize well performance during an unconventional well’s early-stage and potential Enhanced Oil Recovery (EOR) lifespan. Although there have been advances in hydraulic fracturing technology that allow for the creation of large stimulated reservoir volumes (SRVs), it may not be optimal to use the same treatment design for all stages of a well or many wells in an area. We present a comprehensive review of the main approaches used to discuss applicability, pros and cons, and a detailed comparison between different methodologies. Our research outlines a combination of the Diagnostic Fracture Injection Test (DFIT) and falloff pressure analysis, which can help to design intelligent production and improve well performance. Our field study presents an unconventional well to explain the objective optimization workflow. The analysis indicates that most of the fracturing fluid was leaked off through natural fracture surface area and resulted in the estimation of larger values compared to the hydraulic fracture calculated area. These phenomena might represent a secondary fracture set with a high fracture closure stress activated in neighbor stages that was not well-developed in other sections. The falloff pressure analysis provides significant and vital information, assisting operators in fully understanding models for fracture network characterization. Full article

(This article belongs to the Topic Enhanced Oil Recovery Technologies)

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18 pages, 5595 KiB

Open AccessArticle

Evaluation of Surfactant Mixture for Supercritical Carbon Dioxide Foamed Acid in Carbonate Matrix Acidizing

by Rachmi Kartini, Youngmin Kim and Wonsuk Lee

Energies 2021, 14(20), 6567; https://doi.org/10.3390/en14206567 - 12 Oct 2021

Cited by 8 | Viewed by 2663

Abstract

The effectiveness of matrix acidizing using CO₂ foamed acid is dependent on the duration of foam stability. This paper presents a supercritical CO₂ foamed acid with a surfactant mixture to improve the foam stability in carbonate matrix acidizing. The experimental apparatus [...] Read more.

The effectiveness of matrix acidizing using CO₂ foamed acid is dependent on the duration of foam stability. This paper presents a supercritical CO₂ foamed acid with a surfactant mixture to improve the foam stability in carbonate matrix acidizing. The experimental apparatus was developed to conduct foam-stability and wormhole-propagation tests under high-pressure and high-temperature (HPHT) conditions. The foam decay times of five types of surfactants were measured under atmospheric conditions. Trimax (blend of cocamidopropyl betaine, disodium cocoamphodiacetate, and amine oxide) and Aromox C/12W (coco bis-(2-hydroxyethyl) amine oxide) had a high foam decay time. The surfactant mixture was prepared using these two surfactants. The foam stability tests of the surfactant mixture were performed according to the HCl concentration, surfactant mixing ratio, and injection rate of HCl under HPHT conditions. As a result, the foam stability could be improved by adding an HCl concentration of 20% to the surfactant mixture. Wormhole-propagation tests were performed using Indiana and Indonesian limestones. Because of the supercritical CO₂ foamed acid injection, dominant wormholes were formed in all the core samples; thus, the absolute permeabilities significantly increased. The results of the scanning electron microscopy/energy-dispersive X-ray spectroscopy and thin-section analyses revealed that the number of large pores with pore sizes of ≥0.5 mm increased by the injection of CO₂ foamed acid. Therefore, the supercritical CO₂ foamed acid with the surfactant mixture exhibited a high efficiency of matrix acidizing in carbonate reservoirs. Full article

(This article belongs to the Topic Enhanced Oil Recovery Technologies)

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18 pages, 3072 KiB

Open AccessArticle

A Normalized HLD (HLD_N) Tool for Optimal Salt-Concentration Prediction of Microemulsions

by Virin Kittithammavong, Ampira Charoensaeng and Sutha Khaodhiar

Appl. Sci. 2021, 11(19), 9151; https://doi.org/10.3390/app11199151 - 1 Oct 2021

Cited by 6 | Viewed by 3415

Abstract

Optimal condition-based microemulsion is key to achieving great efficiency in oil removal. One useful empirical equation to predict an optimal condition is a hydrophilic–lipophilic deviation (HLD). However, the K constants of each surfactant should be the same to combine the HLD equations for [...] Read more.

Optimal condition-based microemulsion is key to achieving great efficiency in oil removal. One useful empirical equation to predict an optimal condition is a hydrophilic–lipophilic deviation (HLD). However, the K constants of each surfactant should be the same to combine the HLD equations for the mixed surfactant. Recently, a normalized hydrophilic-lipophilic deviation (HLD_N) was presented to avoid this limitation. This work sought to determine the phase behaviors and predict the optimal salt concentrations, using HLD_N for the mixed surfactant. Sodium dihexyl sulfosuccinate (SDHS) as an anionic surfactant, and alcohol alkyl polyglycol ether (AAE(6EO4PO)) as a nonionic surfactant, were both investigated. Alkanes and diesel were used as a model oil. The results showed that AAE(6EO4PO) enforced both the hydrophilic and the hydrophobic characteristics. The Winsor Type I-III transition was influenced by the ethylene oxide, while the propylene oxide presence affected the Winsor Type III-II inversion. For the HLD_N equation, the average interaction term was 1.82 ± 0.86, which markedly showed a strong correlation with the fraction of nonionic surfactant in the mixed systems. The predicted optimal salt concentrations using HLD_N of SDHS-AAE(6EO4PO) in the diesel systems were close to the experimental results, with an error of <10% that is significantly beneficial due to the shorter time required for optimal determination. Full article

(This article belongs to the Topic Enhanced Oil Recovery Technologies)

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20 pages, 3363 KiB

Open AccessArticle

Methods for Developing Models in a Fuzzy Environment of Reactor and Hydrotreating Furnace of a Catalytic Reforming Unit

by Batyr Orazbayev, Ainur Zhumadillayeva, Kulman Orazbayeva, Lyailya Kurmangaziyeva, Kanagat Dyussekeyev and Sandugash Iskakova

Appl. Sci. 2021, 11(18), 8317; https://doi.org/10.3390/app11188317 - 8 Sep 2021

Cited by 19 | Viewed by 2309

Abstract

Methods for the development of fuzzy and linguistic models of technological objects, which are characterized by the fuzzy output parameters and linguistic values of the input and output parameters of the object are proposed. The hydrotreating unit of the catalytic reforming unit was [...] Read more.

Methods for the development of fuzzy and linguistic models of technological objects, which are characterized by the fuzzy output parameters and linguistic values of the input and output parameters of the object are proposed. The hydrotreating unit of the catalytic reforming unit was investigated and described. On the basis of experimental and statistical data and fuzzy information from experts and using the proposed methods, mathematical models of a hydrotreating reactor and a hydrotreating furnace were developed. To determine the volume of production from the outlet of the reactor and furnace, nonlinear regression models were built, and fuzzy models were developed in the form of fuzzy regression equations to determine the quality indicators of the hydrotreating unit—the hydrogenated product. To identify the structure of the models, the ideas of sequential inclusion regressors are used, and for parametric identification, a modified method of least squares is used, adapted to work in a fuzzy environment. To determine the optimal temperature of the hydrotreating process on the basis of expert information and logical rules of conditional conclusions, rule bases are built. The constructed rule bases for determining the optimal temperature of the hydrotreating process depending on the thermal stability of the feedstock and the pressure in the hydrotreating furnace are implemented using the Fuzzy Logic Toolbox application of the MatLab package. Comparison results of data obtained with the known models, developed models and real, experimental data from the hydrotreating unit of the reforming unit are presented and the effectiveness of the proposed approach to modeling is shown. Full article

(This article belongs to the Topic Enhanced Oil Recovery Technologies)

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15 pages, 1876 KiB

Open AccessArticle

AOT + Polyethylene Glycol Eutectics for Enhanced Oil Recovery

by Cristina Gallego, Alba Somoza, Héctor Rodríguez and Ana Soto

Appl. Sci. 2021, 11(17), 8164; https://doi.org/10.3390/app11178164 - 2 Sep 2021

Cited by 4 | Viewed by 2717

Abstract

Eutectic solvents are currently being proposed as useful chemicals for enhanced oil recovery (EOR). In this work, for the first time, the preparation of eutectics based on surfactants and polymers was proposed for this application. These chemicals can be tailored to offer the [...] Read more.

Eutectic solvents are currently being proposed as useful chemicals for enhanced oil recovery (EOR). In this work, for the first time, the preparation of eutectics based on surfactants and polymers was proposed for this application. These chemicals can be tailored to offer the most desired properties for oil recovery: water/oil interfacial tension reduction and increase of the aqueous phase viscosity, while concomitantly facilitating their handling due to their liquid character at ambient conditions. Sodium bis(2-ethylhexyl)sulfosuccinate (AOT) and polyethylene glycol (PEG) of three different molecular weights (namely 600, 1000, and 2000 g/mol) were paired in a search for eutectic behaviors. Melting temperatures for all the systems were determined by differential scanning calorimetry. The most promising combination was AOT + PEG-600, which exhibited a melting point of 275 K and thermal stability up to 473 K at a 40:60 molar ratio. A promising value of 5.1 × 10⁻² mN/m was obtained for the interfacial tension between the optimized formulation and crude oil. The formulation was tested in core-holder experiments to extract oil from a sandstone rock at room temperature, achieving an encouraging 34% of additional oil recovery after the secondary extraction. Full article

(This article belongs to the Topic Enhanced Oil Recovery Technologies)

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19 pages, 4672 KiB

Open AccessArticle

Crude Oil–Brine–Rock Interactions in Tight Chalk Reservoirs: An Experimental Study

by Samira Mohammadkhani, Benaiah U. Anabaraonye, Armin Afrough, Rasoul Mokhtari and Karen Louise Feilberg

Energies 2021, 14(17), 5360; https://doi.org/10.3390/en14175360 - 28 Aug 2021

Cited by 14 | Viewed by 2862

Abstract

We present a systematic study of crude oil–brine–rock interactions in tight chalk cores at reservoir conditions. Flooding experiments are performed on outcrops (Stevns Klint) as well as on reservoir core plugs from Dan field, the Ekofisk and Tor formations. These studies are carried [...] Read more.

We present a systematic study of crude oil–brine–rock interactions in tight chalk cores at reservoir conditions. Flooding experiments are performed on outcrops (Stevns Klint) as well as on reservoir core plugs from Dan field, the Ekofisk and Tor formations. These studies are carried out in core plugs with reduced pore volumes, i.e., short core samples and aged with a dynamic ageing method. The method was evaluated by three different oil compositions. A series of synthetic multicomponent brines and designed fluid injection scenarios are investigated; injection flow rates are optimized to ensure that a capillary-dominant regime is maintained. Changes in brine compositions and fluid distribution in the core plugs are characterized using ion chromatography and X-ray computed tomography, respectively. First, we show that polar components in the oil phase play a major role in wettability alteration during ageing; this controls the oil production behavior. We also show that, compared to seawater, both formation water and ten-times-diluted seawater are better candidates for enhanced oil recovery in the Dan field. Finally, we show that the modified flow zone indicator, a measure of rock quality, is likely the main variable responsible for the higher oil recoveries observed in Tor core samples. Full article

(This article belongs to the Topic Enhanced Oil Recovery Technologies)

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21 pages, 5422 KiB

Open AccessArticle

Experimental Study on the Initiation and Propagation of Multi-Cluster Hydraulic Fractures within One Stage in Horizontal Wells

by Zhenhui Bi, Lei Wang, Hanzhi Yang, Yintong Guo, Xin Chang and Jun Zhou

Energies 2021, 14(17), 5357; https://doi.org/10.3390/en14175357 - 28 Aug 2021

Cited by 10 | Viewed by 2401

Abstract

Competitive propagation of fractures initiated from multiple perforation clusters is universal in hydraulic fracturing of unconventional reservoirs, which largely influences stimulation. However, the propagation mechanism of multi-fractures has not been fully revealed for the lack of a targeted laboratory observation. In this study, [...] Read more.

Competitive propagation of fractures initiated from multiple perforation clusters is universal in hydraulic fracturing of unconventional reservoirs, which largely influences stimulation. However, the propagation mechanism of multi-fractures has not been fully revealed for the lack of a targeted laboratory observation. In this study, a physical simulation experiment system was developed for investigating the initiation and propagation of multi-cluster hydraulic fractures. Different from the traditional hydro-fracking test system, the new one was equipped with a multi-channel shunting module and a strain monitoring system, which could guarantee the full fracture extension at each perforation clusters and measure the internal deformation of specimens, respectively. Several groups of true tri-axial fracturing tests were performed, considering the factors of in situ stress, cluster spacing, pumping rate, and bedding structures. The results showed that initiation of multi-cluster hydraulic fractures within one stage could be simultaneous or successive according to the difference of the breakdown pressure and fracturing fluid injection. For simultaneous initiation, the breakdown pressure of the subsequent fracture was lower than or equal to the value of the previous fracture. Multiple fractures tended to attract and merge. For successive initiation, the breakdown pressures of fractures were gradually increasing. The subsequent fracture tended to intersect with or deviated from the previous fracture. Multiple fractures interaction was aggravated by the decrease of horizontal stress difference, bedding number and cluster spacing, and weakened by the increase of pump rate. The propagation area of multiple fractures increased with the pump rate, decreased with the cluster spacing. The strain response characteristics corresponded with the initiation and propagation of fracture, which was conducive to understanding the process of the fracturing. The test results provide a basis for optimum design of hydraulic fracturing. Full article

(This article belongs to the Topic Enhanced Oil Recovery Technologies)

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8 pages, 2527 KiB

Open AccessArticle

New Method of Oil Reservoir Rock Heterogeneity Quantitative Estimation from X-ray MCT Data

by Irena Viktorovna Yazynina, Evgeny Vladimirovich Shelyago, Andrey Andreevich Abrosimov and Vladimir Stanislavovich Yakushev

Energies 2021, 14(16), 5103; https://doi.org/10.3390/en14165103 - 19 Aug 2021

Cited by 11 | Viewed by 2158

Abstract

This paper considers a new method for “pore scale” oil reservoir rock quantitative estimation. The method is based on core sample X-ray tomography data analysis and can be directly used to both classify rocks by heterogeneity and assess representativeness of the core material [...] Read more.

This paper considers a new method for “pore scale” oil reservoir rock quantitative estimation. The method is based on core sample X-ray tomography data analysis and can be directly used to both classify rocks by heterogeneity and assess representativeness of the core material collection. The proposed heterogeneity criteria consider the heterogeneity of pore size and heterogeneity of pore arrangement in the sample void and can thus be related to the drainage effectiveness. The classification of rocks by heterogeneity at the pore scale is also proposed when choosing a reservoir engineering method and may help us to find formations that are similar at pore scale. We analyzed a set of reservoir rocks of different lithologies using the new method that considers only tomographic images and clearly distributes samples over the structure of their pore space. Full article

(This article belongs to the Topic Enhanced Oil Recovery Technologies)

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13 pages, 4617 KiB

Open AccessArticle

Enhanced Oil Recovery with Size-Dependent Interactions of Nanoparticles Surface-Modified by Zwitterionic Surfactants

by Han Am Son and Taehun Lee

Appl. Sci. 2021, 11(16), 7184; https://doi.org/10.3390/app11167184 - 4 Aug 2021

Cited by 8 | Viewed by 2472

Abstract

This study reports the size-dependent interactions of silica nanoparticle (NP) dispersions with oil, which facilitate oil recovery from sandstone rock. Herein, we studied various 7–22 nm sized colloidal silica NPs (CSNPs; the colloidal state when dispersed in aqueous solutions) and fumed silica nanoparticles [...] Read more.

This study reports the size-dependent interactions of silica nanoparticle (NP) dispersions with oil, which facilitate oil recovery from sandstone rock. Herein, we studied various 7–22 nm sized colloidal silica NPs (CSNPs; the colloidal state when dispersed in aqueous solutions) and fumed silica nanoparticles (FSNPs; the dry powder state). Interfacial tension at the oil-nanofluids interface declined with decreasing NP size in a range from 7 to 22 nm. This is because NP spatial density at the interface increased with smaller particle size, thereby, the interface area per NP decreased to approximately 1/30, and interfacial energy had reduced enough. In addition, smaller NPs more strongly were adsorbed to the rock because of improved diffusion in suspension and increased adsorption density. This caused creating a wedge film between oil and rock, which changed the oil contact angle. Due to this effect, core flooding experiments indicated that oil recovery increased with decreasing particle size. However, FSNP dispersions exhibited low recovery factor because of particle aggregation. This phenomenon may facilitate massive permeability reduction, thus causing oil trapping inside rock pore. We found that both the sizes and types of CSNPs and FSNP affected the Interfacial tension at oil-water interface and rock surface wettability, which influenced ultimate oil recovery. Full article

(This article belongs to the Topic Enhanced Oil Recovery Technologies)

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30 pages, 5216 KiB

Open AccessReview

Exploiting Microbes in the Petroleum Field: Analyzing the Credibility of Microbial Enhanced Oil Recovery (MEOR)

by Marzuqa Quraishi, Shashi Kant Bhatia, Soumya Pandit, Piyush Kumar Gupta, Vivek Rangarajan, Dibyajit Lahiri, Sunita Varjani, Sanjeet Mehariya and Yung-Hun Yang

Energies 2021, 14(15), 4684; https://doi.org/10.3390/en14154684 - 2 Aug 2021

Cited by 31 | Viewed by 9514

Abstract

Crude oil is a major energy source that is exploited globally to achieve economic growth. To meet the growing demands for oil, in an environment of stringent environmental regulations and economic and technical pressure, industries have been required to develop novel oil salvaging [...] Read more.

Crude oil is a major energy source that is exploited globally to achieve economic growth. To meet the growing demands for oil, in an environment of stringent environmental regulations and economic and technical pressure, industries have been required to develop novel oil salvaging techniques. The remaining ~70% of the world’s conventional oil (one-third of the available total petroleum) is trapped in depleted and marginal reservoirs, and could thus be potentially recovered and used. The only means of extracting this oil is via microbial enhanced oil recovery (MEOR). This tertiary oil recovery method employs indigenous microorganisms and their metabolic products to enhance oil mobilization. Although a significant amount of research has been undertaken on MEOR, the absence of convincing evidence has contributed to the petroleum industry’s low interest, as evidenced by the issuance of 400+ patents on MEOR that have not been accepted by this sector. The majority of the world’s MEOR field trials are briefly described in this review. However, the presented research fails to provide valid verification that the microbial system has the potential to address the identified constraints. Rather than promising certainty, MEOR will persist as an unverified concept unless further research and investigations are carried out. Full article

(This article belongs to the Topic Enhanced Oil Recovery Technologies)

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13 pages, 2070 KiB

Open AccessArticle

Impact of Chelating Agent Salt Type on the Enhanced Oil Recovery from Carbonate and Sandstone Reservoirs

by Amjed Hassan, Mohamed Mahmoud and Shirish Patil

Appl. Sci. 2021, 11(15), 7109; https://doi.org/10.3390/app11157109 - 31 Jul 2021

Cited by 12 | Viewed by 2834

Abstract

In this paper, chelating agents were introduced as standalone fluids for enhancing the oil recovery from carbonate and sandstone reservoirs. Chelating agents such as glutamic acid di-acetic acid (GLDA), ethylene-diamine-tetra acetic acid (EDTA), and hydroxyl-ethylethylene-diamine-tri-acetic acid (HEDTA) were used. Chelating agents can be [...] Read more.

In this paper, chelating agents were introduced as standalone fluids for enhancing the oil recovery from carbonate and sandstone reservoirs. Chelating agents such as glutamic acid di-acetic acid (GLDA), ethylene-diamine-tetra acetic acid (EDTA), and hydroxyl-ethylethylene-diamine-tri-acetic acid (HEDTA) were used. Chelating agents can be found in different forms such as sodium, potassium, or calcium salts. There is a significant gap in the literature about the influence of salt type on the hydrocarbon recovery from carbonate and sandstone reservoirs. In this study, the impact of the salt type of GLDA chelating agent on the oil recovery was investigated. Potassium-, sodium-, and calcium-based high-pH GLDA solutions were used. Coreflooding experiments were conducted at high-pressure high-temperature (HPHT) conditions using carbonate and sandstone cores. The used samples had porosity values of 15–18%, and permeability values were between 10 and 75 mD. Seawater was injected as a secondary recovery process. Thereafter, a GLDA solution was injected in tertiary mode, until no more oil was recovered. In addition to the recovery experiments, the collected effluent was analyzed for cations concentrations such as calcium, magnesium, and iron. Moreover, dynamic adsorption, interfacial tension, and contact angle measurements were conducted for the different forms of GLDA chelating agent solutions. The results of this study showed that incremental oil recovery between 19% and 32% of the Original Oil in Place (OOIP) can be achieved, based on the salt type and the rock lithology. Flooding carbonate rocks with the calcium-based GLDA chelating agent yielded the highest oil recovery (32% of OOIP), followed by that with potassium-based GLDA chelating agent, and the sodium-based GLDA chelating agent yielded the lowest oil recovery. The reason behind that was the adsorption of the calcium-based GLDA on the rock surface was the highest without reducing the rock permeability, which was indicated by the contact angle, dynamic adsorption, and flooding experiments. The outcome of this study will help in maximizing the oil recovery from carbonate and sandstone reservoirs by suggesting the most suitable salt type of chelating agents. Full article

(This article belongs to the Topic Enhanced Oil Recovery Technologies)

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8 pages, 1709 KiB

Open AccessArticle

Influences of the Water Cut of Pumping Oil and the Mineralization of the Associated Water on the Rate of Sludging

by Kirill Vyatkin, Victor Mordvinov, Pavel Ilushin and Anton Kozlov

Appl. Sci. 2021, 11(15), 6678; https://doi.org/10.3390/app11156678 - 21 Jul 2021

Cited by 12 | Viewed by 2062

Abstract

The problem of the formation of organic deposits on the inside surfaces of borehole equipment and oilfield pipelines, which is urgent for all active oil fields, was considered in the study. The formation of these deposits leads to decreased lifespans for oilfield equipment [...] Read more.

The problem of the formation of organic deposits on the inside surfaces of borehole equipment and oilfield pipelines, which is urgent for all active oil fields, was considered in the study. The formation of these deposits leads to decreased lifespans for oilfield equipment and accidents involving oil pipelines and wells. The aim of our work was to estimate the dependencies of the organic deposition’s formation-rate factor on the water cut of the investigated water–oil emulsion and the mineralization of the water phase. Examination via generation of asphaltene–resin–paraffin deposits on the surfaces of cold rods was carried out with a “Cold Finger” CF-4 unit. Coefficients of specific oil sludging, fluid sludging and rate sludging have been determined. It has been defined that in the definite oilfields, the rate of sludging does not increase as the water content in the emulsion increases. As water-phase mineralization increases, this value remains practically constant. Full article

(This article belongs to the Topic Enhanced Oil Recovery Technologies)

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15 pages, 2750 KiB

Open AccessReview

Physical Simulation Experimental Technology and Mechanism of Water Invasion in Fractured-Porous Gas Reservoir: A Review

by Mengfei Zhou, Xizhe Li, Yong Hu, Xuan Xu, Liangji Jiang and Yalong Li

Energies 2021, 14(13), 3918; https://doi.org/10.3390/en14133918 - 30 Jun 2021

Cited by 17 | Viewed by 2594

Abstract

In the development process for a fractured-porous gas reservoir with developed fracture and active water, edge water or bottom water easily bursts rapidly along the fracture to the production well, and the reservoir matrix will absorb water, reducing the gas percolation channel and [...] Read more.

In the development process for a fractured-porous gas reservoir with developed fracture and active water, edge water or bottom water easily bursts rapidly along the fracture to the production well, and the reservoir matrix will absorb water, reducing the gas percolation channel and increasing the gas phase percolation resistance of the reservoir matrix, therefor reducing the stable production capacity and recovery efficiency of the gas reservoir. For this reason, this paper investigates physical simulation experimental technology and mechanisms as reported by both domestic and foreign scholars regarding water invasion in fractured-porous gas reservoirs. In this paper, it is considered that the future trend and focus of water invasion experiments will be to establish a more realistic three-dimensional physical model on the basis of fine geological description, combined with gas reservoir well pattern deployment and production characteristics, and to fully consider the difference between horizontal and vertical water invasion along the reservoir side; at the same time, dynamic parameters such as model pressure field and water saturation field can be obtained in real time. Based on this understanding of the water invasion mechanism of fractured-porous gas reservoirs, we propose the next research direction and the development countermeasures such as water controls, drainage, and dissolved water seals and water locks to combat water invasion in reservoirs, along with the injection of gas to replenish formation energy, etc., so as to slow down and control the influence of water invasion. Full article

(This article belongs to the Topic Enhanced Oil Recovery Technologies)

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