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The Optimization of Well Testing Operations for Oil and Gas Field

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A special issue of Energies (ISSN 1996-1073). This special issue belongs to the section "H1: Petroleum Engineering".

Deadline for manuscript submissions: closed (30 November 2023) | Viewed by 19777

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Special Issue Editors

Dr. Dmitriy Aleksandrovich Martyushev

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Guest Editor

Department of Oil and Gas Technologies, Perm National Research Polytechnic University, 614000 Perm, Russia
Interests: well testing; carbonate reservoirs; acid treatment; EOR methods; hydraulic fracturing; acidizing; fractured reservoirs
Special Issues, Collections and Topics in MDPI journals

Prof. Dr. Freddy Humberto Escobar

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Guest Editor

Department of Petroleum Engineering, Universidad Surcolombiana, Neiva 410001, Colombia
Interests: well testing; pressure; reservoir engineering

Special Issue Information

Dear Colleagues,

The main tool for obtaining information about the state of the field at all stages of the life of the field is well testing. In complex fields and expensive well operations, in order to reduce costs, assess economic risks and make optimal decisions in the process of field development, it is important to determine the hydrodynamic properties of the reservoir, identify impermeable boundaries, analyze the current state of the reservoir and change the reservoir properties of the reservoir over time, to evaluate the effectiveness of various geological and technical measures.

Conducting hydrodynamic studies in horizontal wells encounters significant difficulties. This is due to the delivery of instrumentation to the horizontal part of the wellbore, the absence of specially designed instrumentation systems for these purposes, and imperfection of the methods for processing the results of hydrodynamic studies of horizontal wells, leading to significant errors in determining the filtration parameters of the reservoir.

The problems associated with the interpretation of the results of hydrodynamic studies of horizontal wells belong to the class of inverse problems of underground hydromechanics. A distinctive feature of the problems associated with the study of mathematical models of real filtration processes in porous media is that the nature of the initial information (pressure recovery or drop curves, flow rate stabilization curves) about the reservoir is determined by the capabilities of the field experiment. Another factor that must be taken into account when solving these problems is the presence of errors in the experimental data.

In this regard, the development and improvement of equipment, technology and methods of interpretation of hydrodynamic studies in horizontal wells are urgent tasks of underground hydromechanics and oilfield practice for solving problems of oil field development.

Dr. Dmitriy Aleksandrovich Martyushev
Prof. Dr. Freddy Humberto Escobar
Guest Editors

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Keywords

pressure transient analysis
interpretation of horizontal well tests
new approaches to well testing processing
pressure drop curve analysis approaches
evaluation studies radius (drainage) wells
anisotropy assessment based on well testing data

Published Papers (10 papers)

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Research

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21 pages, 9131 KiB

Open AccessArticle

Microfluidic Studies on Minimum Miscibility Pressure for n-Decane and CO₂

by Dmitrii Pereponov, Michael Tarkhov, Desmond Batsa Dorhjie, Alexander Rykov, Ivan Filippov, Elena Zenova, Vladislav Krutko, Alexey Cheremisin and Evgeny Shilov

Energies 2023, 16(13), 4994; https://0-doi-org.brum.beds.ac.uk/10.3390/en16134994 - 27 Jun 2023

Cited by 3 | Viewed by 1087

Abstract

Oil production is a complex process that can be made more efficient by applying gas enhanced oil recovery (EOR) methods. Thus, it is essential to know the minimum miscibility pressure (MMP) and minimum miscibility enrichment (MME) of gas in oil. Conventional slim-tube experiments for the measurement of MMP require hundreds of millilitres of real or recombined oil and last over 30 days. Advances in microfluidic technology allow the reduction of the amount of fluid and the time required in determining MMP (or MME), hence making the process rapid. In this study, we developed a microfluidic model with a stochastically distributed pore network, porosity of 74.6% and volume of 83.26 nanolitres. Although the volume was six orders of magnitude smaller than the slim tube, it retained the same proportions, guaranteeing a proper comparison between the tests. This microfluidic chip allowed the study of the MMP of n-decane with carbon dioxide at two different temperature conditions. The experimental results coincided with the results received both from conventional and microfluidic experiments. Furthermore, a numerical simulation of a section of the microfluidic model under the experimental conditions presented results within acceptable margins of the experimental ones. The results of the presented methodology indicate the potential to replace conventional technology for the measurement of MMP with microfluidic technology. Its promise lies in accelerating laboratory tests and increasing the reliability of experimental results and, subsequently, the quality of field gas EOR operations. Full article

(This article belongs to the Special Issue The Optimization of Well Testing Operations for Oil and Gas Field)

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18 pages, 3749 KiB

Open AccessArticle

Design of a Polymer Composition for the Conformance Control in Heterogeneous Reservoirs

by Inzir Raupov, Mikhail Rogachev and Julia Sytnik

Energies 2023, 16(1), 515; https://0-doi-org.brum.beds.ac.uk/10.3390/en16010515 - 03 Jan 2023

Cited by 8 | Viewed by 1685

Abstract

The article is devoted to the issue of a low sweep efficiency in the heterogeneous terrigenous reservoirs containing remaining oil. Water plugging operations that redirect the injection fluid flows into unswept zones, are one approach to enhancing the oil recovery in these reservoirs. The commonly used chemical reagents in these treatments are acrylate polymer solutions. The polymer solutions must reach the target water-saturated zones and form a strong gel barrier there. Furthermore, the polymer compositions should have a low initial viscosity to provide a good injectivity and penetration ability. Therefore, the methods of adjusting the gelation time are necessary. There are numerous studies in modern scientific society devoted to the study of water-plugging polymer compositions. However, aspects, such as the effect of the hydrogen index on gelation, have received insufficient attention. In this paper, we describe the features of the developed polymer composition, based on a hydrolyzed polymer of acrylonitrile with a controlled gelation time for the chemically enhanced oil recovery. The component composition and the concentration levels were selected, based on the alterations in the hydrogen index of the polymer solution. It was scientifically proven that by adhering to a neutral hydrogen index, it is possible to improve the properties of the polymer composition. Moreover, using a model of a heterogeneous reservoir, it was confirmed that the proposed polymer composition achieves selective plugging. As a result of the polymer gel treatment, the water cut decreased by 4% and the displacement coefficient of oil increased by 20%, in comparison with the effect of the original composition without a gel-time modifier. Full article

(This article belongs to the Special Issue The Optimization of Well Testing Operations for Oil and Gas Field)

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17 pages, 3183 KiB

Open AccessArticle

Influences of Well Test Techniques and Uncertainty in Petrophysics on Well Test Results

by Abdulaziz M. Abdulaziz, Mohamed K. Ali and Omalsaad F. Hafad

Energies 2022, 15(19), 7414; https://0-doi-org.brum.beds.ac.uk/10.3390/en15197414 - 09 Oct 2022

Cited by 1 | Viewed by 1190

Abstract

In the present study, well logs and well test data of both conventional build-up tests and Mini-DST from different oil and gas fields are utilized to evaluate the effects of uncertainty in petrophysics and test techniques on well test results. This includes producing wells from the Nile Delta and Western Desert-Egypt together with published results from West Qurna oil field-Iraq. Results indicated that permeability is strongly dependent on petrophysics interpretation, particularly pay thickness, while the radius of investigation is significantly dependent on fluid properties, especially compressibility. The skin factor calculations showed great sensitivity towards the pressure measurements with medium influences on porosity and oil viscosity. The calculations of Mini DST and Build-up test are compared within the uncertainty context for effective permeability, radius of investigation, and skin factor, and the findings are discussed in detail. In all cases, error analysis indicated that well test results and interpretation of conventional build up data are largely stable and may reduce overall uncertainty to 30% of the corresponding Mini-DST results/interpretation. The results of this study not only characterize each input parameter involved in the interpretation of well test data but also confirms the superiority of conventional build-up on Mini-DST techniques. Full article

(This article belongs to the Special Issue The Optimization of Well Testing Operations for Oil and Gas Field)

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12 pages, 2578 KiB

Open AccessArticle

Employing GMDH-Type Neural Network and Signal Frequency Feature Extraction Approaches for Detection of Scale Thickness inside Oil Pipelines

by Abdullah M. Iliyasu, Abdulilah Mohammad Mayet, Robert Hanus, Ahmed A. Abd El-Latif and Ahmed S. Salama

Energies 2022, 15(12), 4500; https://0-doi-org.brum.beds.ac.uk/10.3390/en15124500 - 20 Jun 2022

Cited by 11 | Viewed by 1636

Abstract

In this paper, gamma attenuation has been utilised as a veritable tool for non-invasive estimation of the thickness of scale deposits. By simulating flow regimes at six volume percentages and seven scale thicknesses of a two phase-flow in a pipe, our study utilised a dual-energy gamma source with Ba-133 and Cs-137 radioisotopes, a steel pipe, and a 2.54 cm × 2.54 cm sodium iodide (NaI) photon detector to analyse three different flow regimes. We employed Fourier transform and frequency characteristics (specifically, the amplitudes of the first to fourth dominant frequencies) to transform the received signals to the frequency domain, and subsequently to extract the various features of the signal. These features were then used as inputs for the group method for data Hiding (GMDH) neural network framework used to predict the scale thickness inside the pipe. Due to the use of appropriate features, our proposed technique recorded an average root mean square error (RMSE) of 0.22, which is a very good error compared to the detection systems presented in previous studies. Moreover, this performance is indicative of the utility of our GMDH neural network extraction process and its potential applications in determining parameters such as type of flow regime, volume percentage, etc. in multiphase flows and across other areas of the oil and gas industry. Full article

(This article belongs to the Special Issue The Optimization of Well Testing Operations for Oil and Gas Field)

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15 pages, 6249 KiB

Open AccessArticle

Optimization of Oil Productivity from the Ultra−Depth Strike−Slip Fault−Controlled Carbonate Reservoirs in Northwestern China

by Xinxing He, Rujun Wang, Jianping Yang, Shiyin Li, Chao Yao and Guanghui Wu

Energies 2022, 15(9), 3472; https://0-doi-org.brum.beds.ac.uk/10.3390/en15093472 - 09 May 2022

Cited by 9 | Viewed by 2015

Abstract

The largest ultra−deep (>7000 m) strike−slip fault−controlled oilfield was found in the tight Ordovician carbonates in the Tarim Basin. Because oil production wells in the Fuman Oilfield generally have bottom water, a reasonable production design is of significant importance for extending the water−free oil recovery period and improving oil recovery. However, there is no economical and effective quantitative method to determine a reasonable production capacity and a corresponding reasonable work system for stable−production wells in fault−controlled fractured carbonate reservoirs. In this contribution, we integrated the dynamic and static data of different types of wells in the Fuman Oilfield. It was found that there is a positive relationship between well−controlled dynamic reserves and reasonable productivity, and the productivity corresponding to the upper limit of the reserve can be defined as reasonable productivity. Further, we proposed a correlation equation between well−controlled dynamic reserves and reasonable productivity that shows the reasonable productivity of a stable well from the well−controlled dynamic reserve, which was obtained by combining the well productivity test and analogous well productivity test methods. The relationship between the reasonable productivity per unit nozzle and the rational productivity was obtained according to the determined matching relationship between the reasonable productivity of the stable−production well and the nozzle. The application results show that it can not only quickly determine the reasonable production capacity of stable−production wells but also deepen the understanding of the quantitative characteristics of the production capacity of the Fuman Oilfield. It also provides insight in the rational production allocation of new wells and optimize the development design, which supports the 1500 × 10⁴ bbl/year oil production from the ultra−deep fractured carbonate reservoirs along the strike−slip fault zones in the Tarim Basin. Full article

(This article belongs to the Special Issue The Optimization of Well Testing Operations for Oil and Gas Field)

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19 pages, 3852 KiB

Open AccessArticle

Extraction of Time-Domain Characteristics and Selection of Effective Features Using Correlation Analysis to Increase the Accuracy of Petroleum Fluid Monitoring Systems

by Abdulilah Mohammad Mayet, Seyed Mehdi Alizadeh, Karina Shamilyevna Nurgalieva, Robert Hanus, Ehsan Nazemi and Igor M. Narozhnyy

Energies 2022, 15(6), 1986; https://0-doi-org.brum.beds.ac.uk/10.3390/en15061986 - 09 Mar 2022

Cited by 28 | Viewed by 2026

Abstract

In the current paper, a novel technique is represented to control the liquid petrochemical and petroleum products passing through a transmitting pipe. A simulation setup, including an X-ray tube, a detector, and a pipe, was conducted by Monte Carlo N Particle-X version (MCNPX) code to examine a two-by-two mixture of four diverse petroleum products (ethylene glycol, crude oil, gasoline, and gasoil) in various volumetric ratios. As the feature extraction system, twelve time characteristics were extracted from the received signal, and the most effective ones were selected using correlation analysis to present reasonable inputs for neural network training. Three Multilayers perceptron (MLP) neural networks were applied to indicate the volume ratio of three kinds of petroleum products, and the volume ratio of the fourth product can be feasibly achieved through the results of the three aforementioned networks. In this study, increasing accuracy was placed on the agenda, and an RMSE < 1.21 indicates this high accuracy. Increasing the accuracy of predicting volume ratio, which is due to the use of appropriate characteristics as the neural network input, is the most important innovation in this study, which is why the proposed system can be used as an efficient method in the oil industry. Full article

(This article belongs to the Special Issue The Optimization of Well Testing Operations for Oil and Gas Field)

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10 pages, 1185 KiB

Open AccessArticle

Conditions for Effective Application of the Decline Curve Analysis Method

by Dmitriy A. Martyushev, Inna N. Ponomareva and Vladislav I. Galkin

Energies 2021, 14(20), 6461; https://0-doi-org.brum.beds.ac.uk/10.3390/en14206461 - 09 Oct 2021

Cited by 6 | Viewed by 1294

Abstract

Determining the reliable values of the filtration parameters of productive reservoirs is the most important task in monitoring the processes of reserve production. Hydrodynamic studies of wells by the pressure build-up method, as well as a modern method based on production curve analysis (Decline Curve Analysis (DCA)), are some of the effective methods for solving this problem. This paper is devoted to assessing the reliability of these two methods in determining the filtration parameters of terrigenous and carbonaceous productive deposits of oil fields in the Perm Krai. The materials of 150 conditioned and highly informative (obtained using high-precision depth instruments) studies of wells were used to solve this problem, including 100 studies conducted in terrigenous reservoirs (C₁v) and 50 carried out in carbonate reservoirs (C₂b). To solve the problem, an effective tool was used—multivariate regression analysis. This approach is new and has not been previously used to assess the reliability of determining the filtration parameters of reservoir systems by different research methods. With its use, a series of statistical models with varying degrees of detail was built. A series of multivariate mathematical models of well flow rates using the filtration parameters determined for each of the methods is constructed. The inclusion or non-inclusion of these filtration parameters in the resulting flow rate models allows us to give a reasonable assessment of the possibility of using the pressure build-up method and the DCA method. All the constructed models are characterized by high statistical estimates: in all cases, a high value of the determination coefficient was obtained, and the probability of an error in all cases was significantly less than 5%. As applied to the fields under consideration, it was found that both methods demonstrate stable results in terrigenous reservoirs. The permeability determined by the DCA method and the pressure build-up curve does not control the flow of the fluid in carbonate reservoirs, which proves the complexity of the filtration processes occurring in them. The DCA method is recommended for use to determine the permeability and skin factor in the conditions of terrigenous reservoirs. Full article

(This article belongs to the Special Issue The Optimization of Well Testing Operations for Oil and Gas Field)

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Review

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20 pages, 6689 KiB

Open AccessReview

A Comprehensive Review of the Role of CO₂ Foam EOR in the Reduction of Carbon Footprint in the Petroleum Industry

by Ayomikun Bello, Anastasia Ivanova and Alexey Cheremisin

Energies 2023, 16(3), 1167; https://0-doi-org.brum.beds.ac.uk/10.3390/en16031167 - 20 Jan 2023

Cited by 12 | Viewed by 2351

Abstract

By trapping CO₂ and storing it in matured and depleted geological formations, atmospheric CO₂ release can be reduced. Carbon capture and storage on a large scale can help to stabilize atmospheric greenhouse gas emissions. This can be achieved by using anthropogenic CO₂ for enhanced oil recovery (EOR), which encourages advances in secure CO₂ storage while enhancing the oil production process. This interaction is expected to hasten the development of CO₂ storage technology and lower emissions from oil producing operations. Reducing CO₂ mobility in the reservoir is crucial to achieving this goal as effectively as possible, and in situ foam generation offers a viable solution. It has been shown that implementing a blend of CO₂ and foaming solution considerably reduces CO₂ mobility and front propagation. Although there have been a few reviews of carbon capture, utilization, and storage (CCUS), none of these have concentrated on the role of foam EOR in achieving carbon neutrality. Therefore, in this brief review, methods for achieving carbon neutrality with foam EOR are comprehensively reviewed. In order to store CO₂, the utilisation of atmospheric CO₂ to generate foam is the main topic of this review. This approach can boost financial incentives for the energy sector, help to lower carbon emissions, and make it possible to produce oil from depleted reservoirs in a more sustainable way. Thus, identifying and examining the governing mechanisms that affect CO₂ storage during foam flooding as well as reviewing the various techniques for estimating CO₂ storage under actual reservoir circumstances are among the goals of this work. Full article

(This article belongs to the Special Issue The Optimization of Well Testing Operations for Oil and Gas Field)

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21 pages, 2318 KiB

Open AccessReview

The Comprehensive Overview of Large-Volume Surfactant Slugs Injection for Enhancing Oil Recovery: Status and the Outlook

by Dmitriy Podoprigora, Roman Byazrov and Julia Sytnik

Energies 2022, 15(21), 8300; https://0-doi-org.brum.beds.ac.uk/10.3390/en15218300 - 07 Nov 2022

Cited by 8 | Viewed by 2314

Abstract

Despite the development of alternative energy sources, oil and gas still remain the predominant energy sources in most countries in the world. Due to gradual hydrocarbon reserve depletion and the existing downward trend in the production level, there is a need to search for methods and technical approaches to level off the falling rates. Chemically enhanced oil recovery methods (EOR) by surfactant solution injections are one of the possible approaches for addressing this issue in already developed fields. Most often, surfactants are injected together with polymers or alkalis. These technologies are called surfactant–polymer (SP) and alkali–surfactant–polymer (ASP) flooding. Basically, SP and ASP have been distributed in China and Canada. In this article, in addition to these countries, we paid attention to the results of pilot and full-scale tests of SP and ASP in Russia, Hungary, and Oman. This study was a comprehensive overview of laboratory and field tests of surfactant solutions used for oil displacement in SP and ASP technologies. The first part of the article discussed the physical fundamentals of the interaction of oil with surfactants. The second part presented the main chemical reagents used to increase oil recovery. In the third part, we described the main facilities used for the preparation and injection of surfactants. Further, the results of field tests of SP and ASP in the abovementioned countries were considered. In the discussion part, based on the considered results, the main issues and uncertainties were identified, based on which some recommendations were proposed for improving the process of preparation and injection of surfactants to increase oil recovery. In particular, we identified an area of additional laboratory and scientifically practical research. The outcomes of this work will provide a clearer picture of SP and ASP, as well as information about their limitations, current challenges, and potential paths forward for the development of these technologies from an economic and technological point of view. Full article

(This article belongs to the Special Issue The Optimization of Well Testing Operations for Oil and Gas Field)

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18 pages, 3022 KiB

Open AccessReview

Experience in the Application of Hydrocarbon Optical Studies in Oil Field Development

by Inzir Raupov, Ramis Burkhanov, Azat Lutfullin, Alexander Maksyutin, Andrey Lebedev and Elena Safiullina

Energies 2022, 15(10), 3626; https://0-doi-org.brum.beds.ac.uk/10.3390/en15103626 - 16 May 2022

Cited by 19 | Viewed by 2077

Abstract

This article reviews the results of measurement of optical properties of oil, such as polarimetry, refractometric, luminescent-bituminological research, IR-spectrometry and UV-visible-NIR spectrometry used to solve geo-bituminology development of hydrocarbon deposits. The authors pay special attention to optical research in the field of UV-visible-NIR electromagnetic radiation, the results of which allow us to estimate the residual oil reserves, separate production for each formation during the operation of multi-layer objects, determine the producing gas-oil ratio, density and content of hydrocarbons, efficiency of hydraulic fracturing, flow-reducing technologies, and injection of solvents of heavy oil sediments, etc. The published approaches to methods of optical research, which are carried out by laboratories or in-well devices, have been analyzed. This article analyzes the main advantages and disadvantages of current technologies for determining the optical properties of oil. The authors propose wellhead devices for determining the optical properties of oil in UV-visible-NIR radiation (190–1100 nm) and their functional schemes, with a description of the operating principle. Full article

(This article belongs to the Special Issue The Optimization of Well Testing Operations for Oil and Gas Field)

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