Research

13 pages, 5100 KiB

Open AccessArticle

Experimental Study and Numerical Simulation of an Electrical Preheating for SAGD Wells in Heavy Oil Reservoirs

by Chao Wang, Yongbin Wu, Chihui Luo, Youwei Jiang, Yunjun Zhang, Haoran Zheng, Qiang Wang and Jipeng Zhang

Energies 2022, 15(17), 6102; https://0-doi-org.brum.beds.ac.uk/10.3390/en15176102 - 23 Aug 2022

Cited by 1 | Viewed by 1049

Abstract

It is necessary to establish effective communication between two horizontal wells during the preheating period of steam-assisted gravity-drainage (SAGD). However, the preheating time is usually very long, which results in high steam consumption and CO₂ emissions. There is little research on the [...] Read more.

It is necessary to establish effective communication between two horizontal wells during the preheating period of steam-assisted gravity-drainage (SAGD). However, the preheating time is usually very long, which results in high steam consumption and CO₂ emissions. There is little research on the effects of different wellbore fluids during the preheating period. The heat transfer and heating characteristics of different wellbore fluids–water, heat-conduction oil, and air–were explored by using physical experiments and numerical simulations. In this study, the results indicated that the heat-transfer performance of heat-conduction oil is the best. The numerical simulation’s results indicated that compared with the wellbore saturated with water, the heat-conduction oil reduced the viscosity of crude oil, and energy consumption was not obvious during the preheating stage. The super-heavy oil flowed into the wellbore due to the solubility of the heat-conduction oil and its own gravity. As a result, the super-heavy oil content in the wellbore gradually accumulated, increasing the risk of coking. Those experiments showed that the use of electrical heating provides good potential to improve SAGD efficiency during the preheating period, and water is the best injection fluid for wellbores during the electrical heating process. Full article

(This article belongs to the Special Issue Advances of Enhanced Oil Recovery Theory and Method)

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14 pages, 1429 KiB

Open AccessArticle

Mathematical Justification for Optimizing Operating Conditions of Gas and Gas Condensate Producing Wells

by Alexander Cheremisin, Eduard Usov, Boris Kolchanov, Andrey Krylov, Alexander Valkovich, Pavel Lykhin, Vladimir Ulyanov, Ekaterina Khogoeva and Alexander Podnebesnykh

Energies 2022, 15(10), 3676; https://0-doi-org.brum.beds.ac.uk/10.3390/en15103676 - 17 May 2022

Viewed by 1278

Abstract

The paper investigated the problem of selecting/finding the optimal process conditions for gas condensate wells. The well process conditions imply a set of parameters that characterize its operation. The optimization of process conditions provides for the efficient operation of an oil and gas [...] Read more.

The paper investigated the problem of selecting/finding the optimal process conditions for gas condensate wells. The well process conditions imply a set of parameters that characterize its operation. The optimization of process conditions provides for the efficient operation of an oil and gas field while meeting the defined boundary and initial conditions, and allows for the process/production goal to be achieved. This paper proposed using the tree-structured Parzen estimator (TPE), which allows for the results from previous iterations to be considered, in order to identify the most promising region of conditions, thereby increasing the optimization efficiency. The movement of multiphase fluid inside the pipeline system (also in the borehole) must be calculated to solve the process optimization problem. The optimization module was integrated into the hydraulic and unsteady state multiphase flow calculations inside the well and the pipeline. The platform created allows for the process conditions at gas condensate fields to be identified via the use of numerical methods. The proposed optimization algorithm was tested in delivering the task of optimizing the process conditions in 13 producing wells in a part of a real gas condensate field in Western Siberia. The engineering problem of optimizing the production of gas and the gas condensate was solved as a consequence of the calculations performed. Full article

(This article belongs to the Special Issue Advances of Enhanced Oil Recovery Theory and Method)

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14 pages, 4298 KiB

Open AccessArticle

Creation of a Hydrodynamic Digital Model of a Laboratory Core Experiment of Surfactant Polymer Impact on Oil Recovery, in Order to Determine Parameters for Further Full-Scale Simulation

by Alexander Cheremisin, Vasiliy Lompik, Margarita Spivakova, Alexey Kudryashov, Kiryl Karseka, Denis Mityurich and Alexander Podnebesnykh

Energies 2022, 15(9), 3440; https://0-doi-org.brum.beds.ac.uk/10.3390/en15093440 - 08 May 2022

Cited by 2 | Viewed by 1229

Abstract

The work aimed to solve the problem of determining, validating, and transferring model parameters of flooding using chemical enhanced oil recovery (EOR) from a core experiment to a full-scale hydrodynamic model. For this purpose, a digital hydrodynamic model describing the process of oil [...] Read more.

The work aimed to solve the problem of determining, validating, and transferring model parameters of flooding using chemical enhanced oil recovery (EOR) from a core experiment to a full-scale hydrodynamic model. For this purpose, a digital hydrodynamic model describing the process of oil displacement by the surfactant and polymer solution on the core is created and the digital model is matched to achieve convergence with the historical data. This approach allows the uncertainties associated with the limited number of experiments to be removed to fully describe the parameters of the chemical surfactant polymer flooding model and form a database that could subsequently be replicated at various field sites, having the composition of reservoir fluids and distribution of rock composition in the core material as the basis. Besides, the digital model allows for verification of physical and chemical properties of surfactants and polymers, values of the adsorption of chemical agents on rocks, and the behavior of relative permeability in the hydrodynamic model of EOR before making predictions on the full-scale model and to improve the quality of forecast cases. Full article

(This article belongs to the Special Issue Advances of Enhanced Oil Recovery Theory and Method)

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14 pages, 4208 KiB

Open AccessArticle

Optimization of Well Control during Gas Flooding Using the Deep-LSTM-Based Proxy Model: A Case Study in the Baoshaceng Reservoir, Tarim, China

by Qihong Feng, Kuankuan Wu, Jiyuan Zhang, Sen Wang, Xianmin Zhang, Daiyu Zhou and An Zhao

Energies 2022, 15(7), 2398; https://0-doi-org.brum.beds.ac.uk/10.3390/en15072398 - 24 Mar 2022

Cited by 2 | Viewed by 1394

Abstract

Gas flooding has proven to be a promising method of enhanced oil recovery (EOR) for mature water-flooding reservoirs. The determination of optimal well control parameters is an essential step for proper and economic development of underground hydrocarbon resources using gas injection. Generally, the [...] Read more.

Gas flooding has proven to be a promising method of enhanced oil recovery (EOR) for mature water-flooding reservoirs. The determination of optimal well control parameters is an essential step for proper and economic development of underground hydrocarbon resources using gas injection. Generally, the optimization of well control parameters in gas flooding requires the use of compositional numerical simulation for forecasting the production dynamics, which is computationally expensive and time-consuming. This paper proposes the use of a deep long-short-term memory neural network (Deep-LSTM) as a proxy model for a compositional numerical simulator in order to accelerate the optimization speed. The Deep-LSTM model was integrated with the classical covariance matrix adaptive evolutionary (CMA-ES) algorithm to conduct well injection and production optimization in gas flooding. The proposed method was applied in the Baoshaceng reservoir of the Tarim oilfield, and shows comparable accuracy (with an error of less than 3%) but significantly improved efficiency (reduced computational duration of ~90%) against the conventional numerical simulation method. Full article

(This article belongs to the Special Issue Advances of Enhanced Oil Recovery Theory and Method)

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21 pages, 1401 KiB

Open AccessArticle

A Production Performance Model of the Cyclic Steam Stimulation Process in Multilayer Heavy Oil Reservoirs

by Tingen Fan, Wenjiang Xu, Wei Zheng, Weidong Jiang, Xiuchao Jiang, Taichao Wang and Xiaohu Dong

Energies 2022, 15(5), 1757; https://0-doi-org.brum.beds.ac.uk/10.3390/en15051757 - 26 Feb 2022

Cited by 3 | Viewed by 1768

Abstract

Cyclic steam stimulation (CSS) is a typical enhanced oil recovery method for heavy oil reservoirs. In this paper, a new model for the productivity of a CSS well in multilayer heavy oil reservoirs is proposed. First, for the steam volume of each formation [...] Read more.

Cyclic steam stimulation (CSS) is a typical enhanced oil recovery method for heavy oil reservoirs. In this paper, a new model for the productivity of a CSS well in multilayer heavy oil reservoirs is proposed. First, for the steam volume of each formation layer, it is proposed that the total steam injection volume will be split by the formation factor (Kh) for the commingled steam injection mode. Then, based on the equivalent flow resistance principle, the productivity model can be derived. In this model, the heavy oil reservoir is composed of a cold zone, a hot water zone, and a steam zone. Next, using the energy conservation law, the equivalent heating radius can be calculated with the consideration of the steam overlay. Simultaneously, a correlation between the threshold pressure gradient (TPG) and oil mobility is also applied for the productivity formula in the cold zone and the hot water zone. Afterward, this model is validated by comparing the simulation results with the results of an actual CNOOC CSS well. A good agreement is observed, and the relative error of the cumulative oil production is about 2.20%. The sensitivity analysis results indicate that the effect of the bottom hole pressure is the most significant, followed by the TPG, and the effect of the steam overlay is relatively slight. The formation factor can affect the splitting of the steam volume in each layer; thus, the oil production rate will be impacted. The proposed mathematical model in this paper provides an effective method for the prediction of preliminary productivity of a CSS well in a multilayer heavy oil reservoir. Full article

(This article belongs to the Special Issue Advances of Enhanced Oil Recovery Theory and Method)

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13 pages, 4511 KiB

Open AccessArticle

Experimental Investigation of a Mechanically Stable and Temperature/Salinity Tolerant Biopolymer toward Enhanced Oil Recovery Application in Harsh Condition Reservoirs

by Chunming Xiong, Falin Wei, Song Zhang, Cheng Cai, Jing Lv, Liming Shao and Dianlin Wang

Energies 2022, 15(5), 1601; https://0-doi-org.brum.beds.ac.uk/10.3390/en15051601 - 22 Feb 2022

Cited by 2 | Viewed by 1356

Abstract

In search of robust polymers for enhanced oil recovery (EOR) application in reservoirs with harsh conditions, a water-soluble biopolymer was thoroughly investigated in this work to evaluate its applicability in such reservoirs. The experimental data revealed that compared to the commonly used EOR [...] Read more.

In search of robust polymers for enhanced oil recovery (EOR) application in reservoirs with harsh conditions, a water-soluble biopolymer was thoroughly investigated in this work to evaluate its applicability in such reservoirs. The experimental data revealed that compared to the commonly used EOR polymer, HPAM, the biopolymer was more efficient in thickening a brine solution as a result of its peculiar conformation. The presence of an electrolyte has almost no effect on the rheology of the biopolymer solution, even at an extremely high salt concentration (20 wt% NaCl). The relation between viscosity and the concentration curve was well fitted to the power-law model. Moreover, the rigid polymer chains rendered the polymer solution superior tolerance to elevated temperatures and salinity, but also led to considerable retention within tight porous media. The adsorption behavior was characterized by the average thickness of the hydrodynamic adsorbed layer on sand grains. The mechanical degradation was assessed by forcing the polymer solutions to flow through an abrupt geometry at ultra-high shear rates. The slight viscosity loss compared to HPAM proved the high mechanical stability of this polymer. These properties made it a promising alternative to HPAM in polymer flooding in the near future for high permeability oil reservoirs with harsh conditions. Full article

(This article belongs to the Special Issue Advances of Enhanced Oil Recovery Theory and Method)

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18 pages, 6835 KiB

Open AccessArticle

Asphaltene Inhibition and Flow Improvement of Crude Oil with a High Content of Asphaltene and Wax by Polymers Bearing Ultra-Long Side Chain

by Xinyuan Li, Shu Lu, Meifei Niu, Ruzhen Cheng, Yanjun Gong and Jun Xu

Energies 2021, 14(24), 8243; https://0-doi-org.brum.beds.ac.uk/10.3390/en14248243 - 07 Dec 2021

Cited by 6 | Viewed by 2781

Abstract

A high content of asphaltene and wax in crude oil leads to difficulties in the recovery and transportation of crude oil due to the precipitation of asphaltenes and the deposition of waxes. Comb-like polymers were found to be capable of inhibiting the aggregation [...] Read more.

A high content of asphaltene and wax in crude oil leads to difficulties in the recovery and transportation of crude oil due to the precipitation of asphaltenes and the deposition of waxes. Comb-like polymers were found to be capable of inhibiting the aggregation of asphaltenes and crystallization of waxes. In this work, comb-like bipolymers of α-olefins/ultra-long chain (C18, C22 and C28) alkyl acrylate were synthesized and characterized by FT-IR and ¹H NMR spectra. The results show that, for a model oil containing asphaltene, the initial precipitation point (IPP) of asphaltene was prolonged by UV, and the asphaltene particle size was reduced after adding the biopolymers, as revealed by dynamitic light scattering (DLS). The bipolymer containing the longer alkyl chain had a better asphaltene inhibition effect. However, DSC and rheological results show that the wax appearance temperature (WAT) of the typical high asphaltene and high wax content of crude oil was obviously reduced by adding bipolymers with shorter alkyl chains. The bipolymer (TDA2024-22) with a mediate alkyl chain (C22) reduced the viscosity and thixotropy of the crude oil by a much larger margin than others. Compared with the previously synthesized bipolymer with phenyl pendant (PDV-A-18), TDA2024-22 exhibited a better performance. Therefore, bipolymers with appropriate alkyl side chains can act as not only the asphaltene inhibitors but also wax inhibitors for high asphaltene and wax content of crude oil, which has great potential applications in the oil fields. Full article

(This article belongs to the Special Issue Advances of Enhanced Oil Recovery Theory and Method)

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12 pages, 4312 KiB

Open AccessArticle

Feasibility of Gas Injection Efficiency for Low-Permeability Sandstone Reservoir in Western Siberia: Experiments and Numerical Simulation

by Alexey Sorokin, Alexander Bolotov, Mikhail Varfolomeev, Ilgiz Minkhanov, Azat Gimazov, Evgeny Sergeyev and Angelica Balionis

Energies 2021, 14(22), 7718; https://0-doi-org.brum.beds.ac.uk/10.3390/en14227718 - 18 Nov 2021

Cited by 5 | Viewed by 1584

Abstract

Gas injection is one of the prospective methods in the development of unconventional oil reserves. Before implementation in the field, it is necessary to justify the effectiveness of using gas agents in specific object conditions. Experiments of oil displacement on physical models with [...] Read more.

Gas injection is one of the prospective methods in the development of unconventional oil reserves. Before implementation in the field, it is necessary to justify the effectiveness of using gas agents in specific object conditions. Experiments of oil displacement on physical models with subsequent numerical modeling can provide the information necessary to justify the feasibility of using gas injection in specific reservoir conditions. This work is devoted to a series of experiments determining the minimum miscibility pressure (MMP) on a slim tube model and the analysis of oil displacement dynamics for various gas compositions, as well as numerical modeling. Displacement experiments were carried out using a recombined oil sample from one of the fields in Western Siberia. The MMP was determined by the classical method of inflection point on the displacement efficiency versus injection pressure curve, which was 34.6 MPa for associated petroleum gas (APG) and 49.9 MPa for methane. The dysnamics of oil displacement for different gas compositions at the same injection pressure showed that APG and carbon dioxide (CO₂) are the most effective in the conditions of the studied field. The influence of the gas composition on the gas breakthrough point was also shown. It is revealed that the change in the concentration of the displacing agent in the outgoing separation gas helps define in more detail the process of displacement and the processes implemented in this case for various displacing gas agents. Similarly, it is shown that the displacing efficiency of a gas agent in a miscibility injection mode is affected by the configuration of wells when it is necessary to achieve MMP in reservoir conditions. For the immiscible gas injection mode, no influence of the well configuration was observed. Full article

(This article belongs to the Special Issue Advances of Enhanced Oil Recovery Theory and Method)

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