Improving heavy oil recovery using a top-driving, CO2-assisted hot-water flooding method in deep and pressure-depleted reservoirs

Shi, Lanxiang; Liu, Peng; Shen, Dehuang; Chen, Xi; Zhang, Yunjun

doi:10.1016/j.petrol.2018.10.088

Cited by 24 publications

(10 citation statements)

References 19 publications

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“…7,8 Oil is produced out of the reservoir by its own energy, which is due to its pressure. 9 In this case, the solutiongas drive (common in heavy oil production), 10 gas-cap drive, 11 and water drive 12 are the three major principal recovery drive systems. The second strategy to recover an oil reservoir is the application of processes like gas injection or water flooding.…”

Section: Introductionmentioning

confidence: 99%

“…The recovery of oil reservoirs is partitioned into three phases, named as primary, secondary, and tertiary. , Oil is produced out of the reservoir by its own energy, which is due to its pressure . In this case, the solution-gas drive (common in heavy oil production), gas-cap drive, and water drive are the three major principal recovery drive systems. The second strategy to recover an oil reservoir is the application of processes like gas injection or water flooding. , After running the first two recovery methods, over 50% of the original oil-in-place (OOIP) stays unproduced .…”

Section: Introductionmentioning

confidence: 99%

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Experimental Investigation and Modeling of Fluid and Carbonated Rock Interactions with EDTA Chelating Agent during EOR Process

et al. 2023

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The injection of chemical fluids into oil reservoirs is gaining widespread attention in light of the declining conventional oil resources by recovering more hydrocarbons. This study is focused on using a chemical called ethylenediaminetetraacetic acid (EDTA) chelating agent in a carbonate reservoir to shed light on contact angle differences of 625 aged thin sections and rock dissolution under the influence of different pHs, temperatures, chelating times, and various chelating agent concentrations in seawater. According to a rock dissolution test, at least 5 wt % of EDTA chemical is needed to obtain oil recovery. A ζ potential test and scanning electron microscopy (SEM) images revealed that the mechanism of adsorption at low pH values and the expansion of the electrical double layer (EDL) at high pH values were responsible for wettability alteration, and an increase in EDTA concentration intensified each mechanism. Interfacial tension (IFT) measurements also showed that adding 1 and 10 wt % of the EDTA to the seawater solution reduced the IFT by 67.75% and 76.08%, respectively. The contact angle experiments demonstrated an increase in the mechanism that leads rock to behave more hydrophilically as pH, solution temperature, and chelating agent concentration in saltwater increased. Artificial neural network (ANN) methods also led to the introduction of a model to predict the contact angle employing multilayer perceptron neural networks (MPNN) and cascade feedforward neural networks (CFFNN). The CFFNN with two hidden neurons and trained by the Levenberg–Marquardt backpropagation algorithm is the most accurate model when comparing the accuracy of models for predicting contact angle values. The CFFNN model indicated that the weight percentage of the chelating chemical, which has a share of about 90%, had the greatest influence on the contact angle, and chelating time, with a share of less than 10%, had the least.

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Section: Introductionmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

Experimental Investigation and Modeling of Fluid and Carbonated Rock Interactions with EDTA Chelating Agent during EOR Process

et al. 2023

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“…The operating conditions, reservoir characteristics, IFT, formation temperature, and CO 2 purity are the common factors that control the degree of miscibility during CO 2 injection. Moreover, the gas injection rate and the location where the gas is injected can significantly affect the CO 2 performance (Perera et al, 2016;Shi et al, 2019). Using a high injection rate can help in maintaining the reservoir pressure, but it may lead to faster gas breakthrough (Talebian et al, 2014;Jia et al, 2019).…”

Section: Introductionmentioning

confidence: 99%

“…The CO 2 -EOR approach presents a very attractive technique compared to conventional approaches such as waterflooding, especially in depleted reservoirs (Ampomah et al, 2016;Shi et al, 2019;Imanovs et al, 2020). The depleted reservoirs usually have low oil saturation; therefore, using waterflooding could lead to trapping the remaining oil and reducing the overall oil recovery (Hawkes et al, 2004;Raza et al, 2017).…”

Section: Introductionmentioning

confidence: 99%

Dual Benefits of Enhanced Oil Recovery and CO2 Sequestration: The Impact of CO2 Injection Approach on Oil Recovery

et al. 2022

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Injection of CO2 to enhance oil recovery is widely used due to its multiple advantages such as mobilizing the oil and sequestration of carbon dioxide. Injection of CO2 can enhance oil recovery by reducing oil viscosity and improving overall fluid mobility. However, several problems are associated with CO2 injection such as viscous fingering, gravity override, and CO2 channeling that results in early gas breakthrough, low sweep efficiency, and low ultimate oil recovery. In this study, dual benefits of CO2 injection are presented: enhancing oil recovery and sequestering carbon dioxide. In this work, different scenarios of field scale simulation were conducted to evaluate oil recovery during CO2 injection, and the CMG (Computer Modeling Group) software package was used. Three main scenarios were examined which are CO2 injection into the reservoir, CO2 injection into the aquifer, and CO2 injection into the aquifer followed by waterflooding. Also, three well configurations were utilized—all injectors and producers are drilled vertically, all wells are drilled horizontally, and vertical injectors and horizontal producers are used. Therefore, the oil recovery profiles were examined for nine scenarios over a 20-year period. In all simulated models, CO2 injection was started at the residual oil saturation (Sor) conditions, to represent the cases of depleted oil reservoirs. The results indicated that the highest oil recovery of 73% of the original oil-in-place (OOIP) can be achieved by injecting CO2 into the reservoir, utilizing vertical injectors and producers. While injecting CO2 into aquifers can significantly enhance oil recovery by around 68–70% of the OOIP, using horizontal wells can provide more oil recovery (67.7%) than that using vertical wells (54.8%), in the same conditions. Moreover, around 7,928 tons of carbon dioxide can be sequestered in underground formations, on average. Finally, CO2 injection outperformed the conventional waterflooding, where 68 and 12% of the OOIP were obtained, respectively. Overall, injection of CO2 into the depleted reservoir can provide dual benefits of CO2 sequestration and improved oil recovery. CO2 can be injected into the water zone resulting in a slow release of CO2 which will reduce the fluid viscosity, enhance oil recovery, and reduce the greenhouse effect.

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“…[12][13][14][15] Hot water flooding is scarcely used in practice considering that hot water flooding may lead to low sweep efficiency. 16,17 At present, the injection of thermal-chemical fluid, including hot water and viscosity reducer, is generally used to reduce the viscosity of crude oil and increase the sweep efficiency of heat flow by injecting gas foam. It had been proved by the core flooding test and field application that foam assisted steam flooding can recover more oil than the conventional steam flooding.…”

Section: Introductionmentioning

confidence: 99%

Application of flue‐gas foam in thermal‐chemical flooding for medium‐depth heavy oil reservoirs

Líu

et al. 2019

Energy Science & Engineering

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Heat loss in wellbore during steam injection is considerable due to the deep burial of medium‐depth heavy oil reservoirs, leading to a low steam quality in the bottom of well. As for hot water flooding, the mobility ratio between oil and water is small, which decreases oil recovery. Flue‐gas foam assisted thermal‐chemical flooding is a new method for heavy oil reservoir. Compared to hot water flooding, flue‐gas foam assisted thermal‐chemical flooding can decrease oil viscosity, achieving higher sweep efficiency. However, the combined mechanisms of all the injected components have not been studied systematically. In this work, the role of CO2, viscosity reducer and hot water for oil viscosity reduction and distribution characteristics of residual oil were studied using the numerical simulation methods. Results show that although the percentage of viscosity reduction contribution of viscosity reducer can be as high as 60%, only wider range of this effect can help recover more remaining oil effectively. In the presence of flue‐gas foam, CO2 and viscosity reducer can decrease oil viscosity in the upper and bottom layers of the reservoir, respectively. Two parameters of the area proportion of removed‐oil (ARRO) and the average removed‐oil saturation (SDRO) are defined. It is believed that both ARRO and SDRO are quite small for the hot water flooding, which is assisted by viscosity reducer. The flue‐gas foam can obviously expand the area of removed‐oil, but the average removed‐oil saturation is slightly lower. The combination of flue‐gas foam and viscosity reducer is a promising displacement method.

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Improving heavy oil recovery using a top-driving, CO2-assisted hot-water flooding method in deep and pressure-depleted reservoirs

Cited by 24 publications

References 19 publications

Experimental Investigation and Modeling of Fluid and Carbonated Rock Interactions with EDTA Chelating Agent during EOR Process

Experimental Investigation and Modeling of Fluid and Carbonated Rock Interactions with EDTA Chelating Agent during EOR Process

Dual Benefits of Enhanced Oil Recovery and CO2 Sequestration: The Impact of CO2 Injection Approach on Oil Recovery

Application of flue‐gas foam in thermal‐chemical flooding for medium‐depth heavy oil reservoirs

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