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Management of High Water Cut and Mature Petroleum Reservoirs

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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 (31 May 2022) | Viewed by 24024

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Special Issue Editors

Dr. Pål Østebø Andersen

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Guest Editor

Department of Energy Resources, University of Stavanger, Kristine Bonnevies vei 22, 4021 Stavanger, Norway
Interests: energy transition; special core analysis; spontaneous imbibition; machine learning; hydrogen; fractured and tight reservoirs; enhanced recovery; carbon capture utilization and storage
Special Issues, Collections and Topics in MDPI journals

Dr. Ketil Djurhuus

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Guest Editor

NORCE Norwegian Research Center, Nygårdsgaten 112, 5008 Bergen, Norway
Interests: enhanced oil recovery; injectivity and water quality; water diversion and conformance control; energy transition; NMR; wettability; CO2 and hydrogen underground storage

Dr. Reza Askarinezhad

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Guest Editor

NORCE Norwegian Research Center, 5007 Bergen, Norway
Interests: conformance control and improvement; water shutoff; special core analysis: experimental relative permeability measurements at reservoir conditions; multiphase CO2/reservoir-fluids flow in porous media; CO2 storage and EOR; methane reforming and hydrogen production

Dr. Jonas S. Solbakken

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Guest Editor

NORCE Norwegian Research Center, 5007 Bergen, Norway
Interests: conformance control; enhanced oil recovery; CO2 storage

Special Issue Information

Dear Colleagues,

We wish to invite you to submit a paper for this Special Issue on ‘Management of high water cut and mature petroleum reservoirs’.

An increasing number of mature oil and gas fields approach their economical limit after producing for years supported by water injection or natural pressure drive mechanisms. Reservoir heterogeneity and fluid mobility contrasts cause displacement to be less efficient with time. Large-scale fractures, thief zones or networks of natural fractures challenge matrix displacement during injection. Increasing water production and declining petroleum production rates may be further limited by the separation and treatment capacity and economy of an asset. Good reservoir management requires that existing infrastructure and discovered resources are utilized to their fullest potential and that measures are taken to ensure that valuable natural resources are not abandoned needlessly. Decisions must be taken related to conformance/water diversion, implementing new recovery solutions, drilling new and smart wells, treatment capacity, etc.

This Special Issue aims to contribute with novel research that can extend and secure petroleum energy supply and maximize the utilization of natural resources with minimal environmental footprints.

Original research articles and reviews are welcome. Research areas may include (but are not limited to): enhanced recovery solutions, extending field life, converting the reservoir to an energy or CO2 storage, improved displacement efficiency and maximized resource utilization.

We look forward to receiving your contributions.

Dr. Pål Østebø Andersen
Dr. Ketil Djurhuus
Dr. Reza Askarinezhad
Dr. Jonas S. Solbakken
Guest Editors

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Submitted manuscripts should not have been published previously, nor be under consideration for publication elsewhere (except conference proceedings papers). All manuscripts are thoroughly refereed through a single-blind peer-review process. A guide for authors and other relevant information for submission of manuscripts is available on the Instructions for Authors page. Energies is an international peer-reviewed open access semimonthly journal published by MDPI.

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Keywords

Mature fields
Near-well and deep water diversion
Conformance
Gas or water coning
Improved recovery chemicals
Economic considerations
Disproportionate permeability reduction
Cross flow
Produced water management
Rock–fluid chemical interactions

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Published Papers (9 papers)

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Editorial

Jump to: Research, Review

4 pages, 175 KiB

Open AccessEditorial

Management of High-Water-Cut and Mature Petroleum Reservoirs

by Pål Østebø Andersen, Ketil Djurhuus, Reza Askarinezhad and Jonas S. Solbakken

Energies 2022, 15(22), 8344; https://doi.org/10.3390/en15228344 - 8 Nov 2022

Viewed by 1025

Abstract

An increasing number of oil and gas companies reach their economic limit after years of production, exhausting the support of natural-pressure drive mechanisms in the reservoir and the benefits of water or gas injection [...] Full article

(This article belongs to the Special Issue Management of High Water Cut and Mature Petroleum Reservoirs)

Research

Jump to: Editorial, Review

12 pages, 6767 KiB

Open AccessArticle

An Analytical TOOLBOX for the Characterization of Chalks and Other Fine-Grained Rock Types within Enhanced Oil Recovery Research and Its Application—A Guideline

by Udo Zimmermann, Mona Wetrhus Minde, Merete Vadla Madland and Tine Vigdal Bredal

Energies 2022, 15(11), 4060; https://doi.org/10.3390/en15114060 - 1 Jun 2022

Cited by 3 | Viewed by 1713

Abstract

Analyses of fine-grained rocks like shales, cherts, and specifically chalk are challenging with regards to spatial resolution. We propose a “toolbox” to understand mineralogical alteration in chalk, especially those induced by non-equilibrium fluids or polymers and silicates during production of hydrocarbons. These data are fundamental in experiments related to improved/enhanced oil recovery (IOR/EOR) research with the aim to increase hydrocarbon production in a sustainable and environmentally friendly process. The ‘toolbox’ methods analyse rock–fluid or polymer–rock interaction and can be applied to any fine-grained rock type. In our ‘toolbox’, we include methods for routine analysis and evaluate the economic side of the usage together with the complexity of application and the velocity of data acquisition. These methods are routine methods for identification and imaging of components at the same time by chemical or crystallographic means and here applied to petroleum geology. The ‘toolbox’ principle provides a first workflow to develop a road map with clear focus on objectives for maximizing EOR. Most importantly, the methods provide a robust dataset that can identify mineralogical properties and alterations in very fine-grained rocks over several scales (nanometer-decimeter). Full article

(This article belongs to the Special Issue Management of High Water Cut and Mature Petroleum Reservoirs)

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23 pages, 5097 KiB

Open AccessArticle

Water Weakening of Artificially Fractured Chalk, Fracture Modification and Mineral Precipitation during Water Injection—An Experimental Study

by Tine Vigdel Bredal, Reidar Inge Korsnes, Udo Zimmermann, Mona Wetrhus Minde and Merete Vadla Madland

Energies 2022, 15(10), 3817; https://doi.org/10.3390/en15103817 - 22 May 2022

Cited by 2 | Viewed by 1730

Abstract

This experiment was designed to study the water-weakening effect of artificially fractured chalk caused by the injection of different compositions of brines under reservoir conditions replicating giant hydrocarbon reservoirs at the Norwegian Continental Shelf (NCS). NaCl, synthetic seawater (SSW), and MgCl_2, with same ionic strength, were used to flood triaxial cell tests for approximately two months. The chalk cores used in this experiment originate from the Mons basin, close to Obourg, Belgium (Saint Vast Formation, Upper Cretaceous). Three artificially fractured chalk cores had a drilled central hole parallel to the flooding direction to imitate fractured chalk with an aperture of 2.25 (±0.05) mm. Two additional unfractured cores from the same sample set were tested for comparison. The unfractured samples exposed a more rapid onset of the water-weakening effect than the artificially fractured samples, when surface active ions such as Ca²⁺, Mg²⁺ and SO₄²⁻ were introduced. This instant increase was more prominent for SSW-flooded samples compared to MgCl₂-flooded samples. The unfractured samples experienced axial strains of 1.12% and 1.49% caused by MgCl₂ and SSW, respectively. The artificially fractured cores injected by MgCl₂ and SSW exhibited a strain of 1.35% and 1.50%, while NaCl showed the least compaction, at 0.27%, as expected. Extrapolation of the creep curves suggested, however, that artificially fractured cores may show a weaker mechanical resilience than unfractured cores over time. The fracture aperture diameters were reduced by 84%, 76%, and 44% for the SSW, MgCl₂, and NaCl tests, respectively. Permeable fractures are important for an effective oil production; however, constant modification through compaction, dissolution, and precipitation will complicate reservoir simulation models. An increased understanding of these processes can contribute to the smarter planning of fluid injection, which is a key factor for successful improved oil recovery. This is an approach to deciphering dynamic fracture behaviours. Full article

(This article belongs to the Special Issue Management of High Water Cut and Mature Petroleum Reservoirs)

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26 pages, 9128 KiB

Open AccessArticle

Characteristic Forced and Spontaneous Imbibition Behavior in Strongly Water-Wet Sandstones Based on Experiments and Simulation

by Pål Østebø Andersen, Liva Salomonsen and Dagfinn Søndenaa Sleveland

Energies 2022, 15(10), 3531; https://doi.org/10.3390/en15103531 - 11 May 2022

Cited by 14 | Viewed by 2720

Abstract

Forced and spontaneous imbibition of water is performed to displace oil from strongly water-wet Gray Berea (~130 mD) and Bentheimer (~1900 mD) sandstone core plugs. Two nonpolar oils (n-heptane and Marcol-82) were used as a non-wetting phase, with viscosities between 0.4 and 32 cP and brine (1 M NaCl) for the wetting phase with viscosity 1.1 cP. Recovery was measured for both imbibition modes, and pressure drop was measured during forced imbibition. Five forced imbibition tests were performed using low or high injection rates, using low or high oil viscosity. Seventeen spontaneous imbibition experiments were performed at four different oil viscosities. By varying the oil viscosity, the injection rate and imbibition modes, capillary and advective forces were allowed to dominate, giving trends that could be captured with modeling. Full numerical simulations matched the experimental observations consistently. The findings of this study provide better understanding of pressure and recovery behavior in strongly water-wet systems. A strong positive capillary pressure and a favorable mobility ratio resulting from low water relative permeability were main features explaining the observations. Complete oil recovery was achieved at water breakthrough during forced imbibition for low and high oil viscosity and the recovery curves were identical when plotted against the injected volume. Analytical solutions for forced imbibition indicate that the pressure drop changes linearly with time when capillary pressure is negligible. Positive capillary forces assist water imbibition, reducing the pressure drop needed to inject water, but yielding a jump in pressure drop when the front reaches the outlet. At a high injection rate, capillary forces are repressed and the linear trend between the end points was clearer than at a low rate for the experimental data. Increasing the oil viscosity by a factor of 80 only increased the spontaneous imbibition time scale by five, consistent with low water mobility constraining the imbibition rate. The time scale was predicted to be more sensitive to changes in water viscosity. At a higher oil-to-water mobility ratio, a higher part of the total recovery follows the square root of time. Our findings indicate that piston-like displacement of oil by water is a reasonable approximation for forced and spontaneous imbibition, unless the oil has a much higher viscosity than the water. Full article

(This article belongs to the Special Issue Management of High Water Cut and Mature Petroleum Reservoirs)

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35 pages, 5213 KiB

Open AccessArticle

Prediction of Oil Recovery Factor in Stratified Reservoirs after Immiscible Water-Alternating Gas Injection Based on PSO-, GSA-, GWO-, and GA-LSSVM

by Pål Østebø Andersen, Jan Inge Nygård and Aizhan Kengessova

Energies 2022, 15(2), 656; https://doi.org/10.3390/en15020656 - 17 Jan 2022

Cited by 8 | Viewed by 2173

Abstract

In this study, we solve the challenge of predicting oil recovery factor (

RF

In this study, we solve the challenge of predicting oil recovery factor (

RF

) in layered heterogeneous reservoirs after 1.5 pore volumes of water-, gas- or water-alternating-gas (WAG) injection. A dataset of ~2500 reservoir simulations is analyzed based on a Black Oil 2D Model with different combinations of reservoir heterogeneity, WAG hysteresis, gravity influence, mobility ratios and WAG ratios. In the first model MOD1, RF is correlated with one input (an effective WAG mobility ratio

M^{*}

). Good correlation (Pearson coefficient −0.94), but with scatter, motivated a second model MOD2 using eight input parameters: water–oil and gas–oil mobility ratios, water–oil and gas–oil gravity numbers, a reservoir heterogeneity factor, two hysteresis parameters and water fraction. The two mobility ratios exhibited the strongest correlation with RF (Pearson coefficient −0.57 for gas-oil and −0.48 for water-oil). LSSVM was applied in MOD2 and trained using different optimizers: PSO, GA, GWO and GSA. A physics-based adaptation of the dataset was proposed to properly handle the single-phase injection. A total of 70% of the data was used for training, 15% for validation and 15% for testing. GWO and PSO optimized the model equally well (R² = 0.9965 on the validation set), slightly better than GA and GSA (R² = 0.9963). The performance metrics for MOD1 in the total dataset were: RMSE = 0.050 and R² = 0.889; MOD2: RMSE = 0.0080 and R² = 0.998. WAG outperformed single-phase injection, in some cases with 0.3 units higher RF. The benefits of WAG increased with stronger hysteresis. The LSSVM model could be trained to be less dependent on hysteresis and the non-injected phase during single-phase injection. Full article

(This article belongs to the Special Issue Management of High Water Cut and Mature Petroleum Reservoirs)

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20 pages, 1981 KiB

Open AccessArticle

Petroleum Reservoir Control Optimization with the Use of the Auto-Adaptive Decision Trees

by Edyta Kuk, Jerzy Stopa, Michał Kuk, Damian Janiga and Paweł Wojnarowski

Energies 2021, 14(18), 5702; https://doi.org/10.3390/en14185702 - 10 Sep 2021

Cited by 10 | Viewed by 2255

Abstract

The global increase in energy demand and the decreasing number of newly discovered hydrocarbon reservoirs caused by the relatively low oil price means that it is crucial to exploit existing reservoirs as efficiently as possible. Optimization of the reservoir control may increase the technical and economic efficiency of the production. In this paper, a novel algorithm that automatically determines the intelligent control maximizing the NPV of a given production process was developed. The idea is to build an auto-adaptive parameterized decision tree that replaces the arbitrarily selected limit values for the selected attributes of the decision tree with parameters. To select the optimal values of the decision tree parameters, an AI-based optimization tool called SMAC (Sequential Model-based Algorithm Configuration) was used. In each iteration, the generated control sequence is introduced into the reservoir simulator to compute the NVP, which is then utilized by the SMAC tool to vary the limit values to generate a better control sequence, which leads to an improved NPV. A new tool connecting the parameterized decision tree with the reservoir simulator and the optimization tool was developed. Its application on a simulation model of a real reservoir for which the CCS-EOR process was considered allowed oil production to be increased by 3.5% during the CO₂-EOR phase, reducing the amount of carbon dioxide injected at that time by 16%. Hence, the created tool allowed revenue to be increased by 49%. Full article

(This article belongs to the Special Issue Management of High Water Cut and Mature Petroleum Reservoirs)

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26 pages, 10887 KiB

Open AccessArticle

Multiphase Multicomponent Numerical Modeling for Hydraulic Fracturing with N-Heptane for Efficient Stimulation in a Tight Gas Reservoir of Germany

by Faisal Mehmood, Michael Z. Hou, Jianxing Liao, Muhammad Haris, Cheng Cao and Jiashun Luo

Energies 2021, 14(11), 3111; https://doi.org/10.3390/en14113111 - 26 May 2021

Cited by 7 | Viewed by 2696

Abstract

Conventionally, high-pressure water-based fluids have been injected for hydraulic stimulation of unconventional petroleum resources such as tight gas reservoirs. Apart from improving productivity, water-based frac-fluids have caused environmental and technical issues. As a result, much of the interest has shifted towards alternative frac-fluids. In this regard, n-heptane, as an alternative frac-fluid, is proposed. It necessitates the development of a multi-phase and multi-component (MM) numerical simulator for hydraulic fracturing. Therefore fracture, MM fluid flow, and proppant transport models are implemented in a thermo-hydro-mechanical (THM) coupled FLAC3D-TMVOCMP framework. After verification, the model is applied to a real field case study for optimization of wellbore x in a tight gas reservoir using n-heptane as the frac-fluid. Sensitivity analysis is carried out to investigate the effect of important parameters, such as fluid viscosity, injection rate, reservoir permeability etc., on fracture geometry with the proposed fluid. The quicker fracture closure and flowback of n-heptane compared to water-based fluid is advantageous for better proppant placement, especially in the upper half of the fracture and the early start of natural gas production in tight reservoirs. Finally, fracture designs with a minimum dimensionless conductivity of 30 are proposed. Full article

(This article belongs to the Special Issue Management of High Water Cut and Mature Petroleum Reservoirs)

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15 pages, 5403 KiB

Open AccessArticle

A Surfactant for Enhanced Heavy Oil Recovery in Carbonate Reservoirs in High-Salinity and High-Temperature Conditions

by Yu-Qi Yang, Liang Li, Xiang Wang, Yue-Qun Fu, Xiao-Qing He, Shi-Ling Zhang and Ji-Xiang Guo

Energies 2020, 13(17), 4525; https://doi.org/10.3390/en13174525 - 1 Sep 2020

Cited by 7 | Viewed by 3016

Abstract

In view of the difficulty of producing heavy oil from carbonate reservoirs, the surfactant SDY-1 was synthesized by homogeneous solution polymerization with a homogeneous solution polymerization technique using aliphatic amine polyoxyethylene ether (PAE_n) H(OCH₂CH₂)_nNR(CH₂CH₂O)_nH as the raw material, epichlorohydrin as the reaction intermediate, tetrabutylammonium bromide and pentamethyldivinyltriamine as the promoters, and alkylphenol as the catalyst. Based on the analysis of reservoir fluid and rock properties, the performance of the surfactant SDY-1 was evaluated in terms of its heat resistance, its salinity tolerance, its ability to change the heavy oil–water interfacial tension and rock wettability and its oil washing efficiency. The results show that when the salinity of the formation water is 2.23 × 10⁵ mg/L, the addition of surfactant SDY-1 can lower the super-heavy oil–water interfacial tension with an asphaltene concentration of 30.19 wt.%, which is aged at a temperature of 140 °C for 3 days, from 22.41 to 0.366 mN/m. In addition, the surfactant SDY-1 can change the contact angle of super-heavy oil–water–rock from 129.7 to 67.4° and reduce the adhesion of crude oil to the rock surface by 99.26%. The oil displacement experiment indicates that the oil washing efficiency of the surfactant SDY-1 can reach 78.7% after ageing at a temperature of 140 °C for 3 days. Compared with petroleum sulfonate flooding, the addition of SDY-1 can improve the displacement efficiency by 33.6%, and the adsorption loss is only 0.651 mg/g oil sand. It has broad application prospects for heavy oil reservoirs with high temperatures, high pressures and high asphaltene contents. Full article

(This article belongs to the Special Issue Management of High Water Cut and Mature Petroleum Reservoirs)

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Review

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20 pages, 3037 KiB

Open AccessReview

The Utilization of Ultrasound for Improving Oil Recovery and Formation Damage Remediation in Petroleum Reservoirs: Review of Most Recent Researches

by Ephraim Otumudia, Hossein Hamidi, Prashant Jadhawar and Kejian Wu

Energies 2022, 15(13), 4906; https://doi.org/10.3390/en15134906 - 5 Jul 2022

Cited by 13 | Viewed by 4124

Abstract

The ultrasound method is a low-cost, environmentally safe technology that may be utilized in the petroleum industry to boost oil recovery from the underground reservoir via enhanced oil recovery or well stimulation campaigns. The method uses a downhole instrument to propagate waves into the formation, enhancing oil recovery and/or removing formation damage around the wellbore that has caused oil flow constraints. Ultrasonic technology has piqued the interest of the petroleum industry, and as a result, research efforts are ongoing to fill up the gaps in its application. This paper discusses the most recent research on the investigation of ultrasound’s applicability in underground petroleum reservoirs for improved oil recovery and formation damage remediation. New study areas and scopes were identified, and future investigations were proposed. Full article

(This article belongs to the Special Issue Management of High Water Cut and Mature Petroleum Reservoirs)

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