Increase Oil Production Research Articles

IMMISCIBLE VISCOUS FINGERING MODELING OF TERTIARY POLYMER FLOODING BASED ON REAL CASE OF HEAVY OIL RESERVOIR MODEL

In immiscible displacements, lower viscosity injected fluids with higher mobility than crude oil can create viscous fingers, affecting displacement efficiency. The Buckley–Leverett approach for relative permeabilities (kr) may not represent accurately 2D features like increased water saturation in viscous fingering. Based on the physics issue, this work applies Sorbie's 4-Steps methodology to a 3D simulation of an offshore heavy oil reservoir focusing on waterflooding and tertiary polymer flooding, assessing their impact on oil production forecasts. It also explores the application of this methodology to coarse grid simulation models, employing pseudo kr functions by data assimilation. During tertiary polymer injection, two processes were identified in oil displacement: viscous crossflow mechanism and oil bank mobilization by a second finger. This combination resulted in earlier and increased oil production. For both strategies, refining the grid increased simulation runtime from minutes to days compared to coarse grids, making it impractical for intensive processes. From data assimilation, the best solution with matched field indicators reduced runtime from days to minutes. This study expanded the 4-Steps methodology for 3D reservoir simulation, proposing kr as uncertainties. Data assimilation enhances the methodology, generating pseudo kr for coarser grid simulations, reducing computational costs, and capturing small-scale phenomena.

VALUE OF OIL FIELD INTEGRATED MODEL DEVELOPMENT

Today, there is practically no doubt about the need to use geological and dynamic models for the development of oil fields. Most of the world's companies actively use them and are guided by the results obtained as a result of their construction and calculations on them. At the same time, the value of creating integrated models of oil fields at a late stage of development among specialists in various fields raises many questions and doubts. In the work performed, an integrated model is understood as a combination of three models into a single calculation system: a geological and dynamic model of the field, models of all wells and a model of the surface development network. The latter includes both a production and transportation system and a system for injecting formation stimulation agents. Opinions differ on the need and feasibility of creating integrated models, since there are no statistics on their widespread use and the benefits obtained from this in the form of additional oil production or cost savings.This article shows the results of creating an integrated model of a large N oil field, which has been in operation for more than 60 years and is at a late stage of development. The work was carried out on the domestic software complex, during which the parameters of the initial information and factors affecting the quality of creating an integrated model were determined. When creating an integrated model, information about the real position of pipelines, their dimensional characteristics, as well as the reliability of measurements of wellhead pressures and volumes of pumped fluid are important. As a result of the construction and adaptation, the possibilities of practical application of the integrated model were determined, such as determining the state of pipelines and identifying bottlenecks in them. In the process of work, the database of various services is synchronized. In practice, the narrow section of the oil pipeline identified on the model was replaced, and additional oil production from the section was obtained. Thus, the value of creating an integrated model in the form of the actual result of its application in order to increase oil production is shown.

Prospects and current state of chemical EOR methods applied in Kazakhstan

At present, at almost all fields of the Republic of Kazakhstan the main technology of oil recovery enhancement is the traditional method of waterflooding of productive formations. Many oil and gas fields in Kazakhstan are at a late stage of development and are categorized as «mature» fields. In the global experience of mature field development, the key focus is on the application of enhanced oil recovery (EOR) techniques - chemical, thermal, gas and microbiological methods. This paper considers the application of chemical EOR at a number of Kazakh fields such as Zaburunye, North Buzachi, Kalamkas, East Moldabek. As the results of the pilot studies have shown, the most effective EOR here is the application of polymer flooding. It should also be noted that polymer flooding is successfully applied in Kazakhstan for high-viscosity oil fields such as North Buzachi (oil viscosity 316-417 mPa·s), East Moldabek (oil viscosity 246-377 mPa·s). In this case, water cut, smoothing of injectivity profile and, as a result, increase of oil production is achieved. Successful application of the technology largely depends on the parameters of physical and chemical impact at each stage - the volume of injection of gel-polymer composition, concentration of ingredients, the flow rate of filtered water, the presence and linear size of cracks, the permeability of pore channels and etc. Polymer flooding applied in Kazakhstan showed its technological and economic efficiency on the example of pilot tests, laboratory studies, which reduces water cut and increases oil production. Widespread use of EOR methods would allow increasing recoverable oil reserves by at least 5-10 %. Keywords: Enhanced Oil Recovery (EOR); gas Injection; hydrocarbon recovery methods; chemical EOR methods; thermal EOR methods; oil production; polymer flooding; oil recovery.

Development of technology for intensification of oil production using emulsion based on natural gasoline and solutions of nitrite compounds

This article focuses on the issue of enhancing oil production by eliminating asphalt, resin, and paraffin deposits (ARPD). These deposits pose significant challenges, including equipment clogging, reduced well productivity, and increased maintenance costs. Moreover, paraffin deposits can damage well equipment, cause accidents, and halt hydrocarbon production. The study involved laboratory and field experiments at the Uzen field to evaluate the efficiency of removing and dissolving paraffin using an emulsion composed of gas gasoline and nitrite compound solutions. Previous studies conducted at NGDU Uzenneft were critically analyzed for comparison. The scientific innovation of this research lies in the development of an emulsion based on gas gasoline and nitrite compound solutions to remove ARPD. The composition was designed to exclude highly aggressive components. It utilized a previously developed emulsion base and incorporated ammonium nitrite, slightly acidified with hydrogen chloride (0.1% by mass), to promote an exothermic reaction.The effectiveness of this technology was measured by changes in daily oil production rates, the duration of the treatment's effect, and changes in the well productivity coefficient before and after treatment.Results indicate that the developed technology successfully removed paraffin from the bottomhole zone of oil wells and increased oil production in 5 out of 6 wells at the Uzen field. The positive effect lasted 17-27 days, with oil inflow increasing by 17-174%. This led to a total additional oil production of 1528 tons from the five wells. Keywords: bottomhole formation zone; asphalt-resin-paraffin deposits; nitrite composition; surfactants; enhanced oil recovery.

Optimization of ESP performance through chemical treatment using a single capillary in the Apiay field

The future of production in the Apiay field lies in the T2 formation, although it poses significant challenges, such as high fluid encrustation and heavy crude oil production. These issues have led to strong emulsion problems and operational issues with many wells' electro-submersible pumping systems (ESPs). In response, companies have decided that all wells with ESP equipment in the T2 formation should undergo downhole treatment using capillary scale inhibitors and fluidity improvers. However, due to operational and design constraints, some wells only have one capillary, making it difficult to prioritize and decide on a single treatment. Ecopetrol and ChampionX have collaborated to develop a new flow improver that can be applied with the scale inhibitor in the same capillary without causing incompatibility or affecting product performance. This innovative solution was implemented in five wells, using 600 ppm for the flow improver, and 25 ppm for the scale inhibitor, resulting in a significant increase in crude oil production by up to 79%, USD 55.000 in cost savings in capillary system installation, 29% energy savings, and reduced emissions. This successful application is innovative and unique in Colombia, and it sets an example for other fields facing similar challenges in the couuntry, offering a promising approach to leverage heavy crude oil production and transform the future of these fields.

Supercritical water upgrading of heavy oil: Effects of reservoir minerals on pyrolysis product distribution

Supercritical water upgrading (SCWU) is a promising technology for heavy oil recovery and refining, in which minerals could act as catalysts, but the effect on the upgraded product distribution remains unclear. In this study, heavy oil upgrading experiments in supercritical water (SCW) were carried out at 400°C and 25 MPa to investigate the effects of reservoir minerals such as quartz, carbonate, feldspar and clay minerals on the upgrading process. The result indicated that carbonate minerals and clay-bearing minerals produced noticeable benefits to the SCWU of heavy oil process. In carbonate minerals, dolomite showed the strongest catalytic effect in promoting hydrothermal cracking of hydrocarbon macromolecules, with a 5.6 % reduction in heavy fraction and a 12.2 % increase in light fraction of the upgraded oil. Clay-bearing minerals mainly exhibited oil-enhancing and coking-inhibiting benefits, calcium montmorillonite exhibited the most significant increase in oil production of 9 %, while zeolite most significantly reduced the coke activation energy by 62 %. Regarding the catalytic mechanism, the catalytic effect of carbonates originated from the MgO and CaO sites on the surface. For clay minerals, the acidic catalytic sites exist in the interlayer domains of montmorillonite and in the pores of zeolite provided higher catalytic efficiencies in oil production. This study demonstrated the feasibility of using natural minerals as inexpensive catalysts for supercritical water upgrading of heavy oil.

Numerical simulation study of the effect of different factors on supercritical CO2 BLEVE

Abstract Global warming is harmful to the environment and CO2 is one of the major greenhouse gases. CCS-EOR technology can increase oil production and sequester CO2. During the storage and transportation of high-pressure CO2, BLEVE may occur. In this study, the dynamic pressure parameters in the supercritical CO2 BLEVE process were numerically simulated by using numerical simulation, and the effects of initial temperature and initial charge on the dynamic pressure parameters in the supercritical CO2 BLEVE process were mainly discussed. By thoroughly investigating the dynamic pressure of BLEVE of supercritical CO2, we can better understand and predict the conditions under which such accidents occur, and further improve the safety of industrial processes.

Research and Practice on Implementing Segmented Production Technology of Horizontal Well during Extra-High Water Cut Stage with Bottom Water Reservoir

Bohai X oilfield has reached the extra-high water cut stage of more than 95%, dominated by the bottom water reservoir. The oilfield mainly adopts horizontal-well exploitation, with the characteristics of high difficulty and low success rate for well water plugging. To solve the above problem, the segmented production technology of horizontal wells was developed to guide oilfield applications and tap their potential. In the segmented design stage, the horizontal section is objectively segmented by drilling condition analysis, optimally based on drilling through interlayers or permeability discrepancy formation, simultaneously combined with the numerical simulation method. When implementing measures, annulus chemical packer materials are squeezed between segments to effectively inhibit the fluid flow between the open hole and the sand-packing screen pipe. Moreover, the packers are used to seal between segments to effectively restrain the flow between the screen and the central tube, achieving the establishment of compartments. In the production process, the valve switch on the central tube can be independently controlled by a remotely adjustable method to achieve optimal production. This segmented production technology was successfully tested for the first time in Bohai oilfield. Up to now, a total of six compartment measures have been implemented, remarkably decreasing water cut and increasing oil production for horizontal wells in the bottom water reservoir. This method does not require water testing, and the optimal production section can be chosen through segmented independent production, greatly improving the success rate of water-plugging measures for horizontal wells. This technology opens up a new mode for the efficient development of horizontal wells in bottom water reservoirs and is planned to be widely promoted and applied in similar oilfields.

Experimental design and manufacturing of a smart control system for horizontal separator based on PID controller and integrated production model

During oil production, the reservoir pressure declines, causing changes in the hydrocarbon components. To ensure better separation of produced phases, separator dimensions should also be adjusted. It is not possible to change the dimensions of the separator during production. Therefore, to improve the separation of the phases, the level of the separator needs to be adjusted. An intelligent system is required to ensure that the liquid level is maintained at the desired level for optimal phase separation during changes in reservoir pressure. In this study, a novel correlation is presented to measure the desired liquid level using new separator pressures. For this purpose, an intelligent system was built in the laboratory and tested in different operational conditions. The intelligent system effectively maintained the desired liquid level of the separator through a new correlation technique. The system accomplished this by acquiring new separator pressure readings collected by installed sensors. This approach helped mitigate the negative effects of the slug flow regime and minimized issues such as foam formation and over-flushing of the separator. It could achieve a 99.1% separation efficiency between gas and liquid phases. This was possible during liquid and gas flow rates ranging from 0 to 2.35 and 8–17 m3/h, respectively. The system could operate under bubble, stratified, plug, and slug flow regimes. Then the intelligent model obtained from lab experiments was integrated into the production model for the southern Iranian oil field. The smart model increased oil production by 13% and prevented the separator from over-flushing in 840 days.

Separate-layer injection scheme optimization based on integrated injection information with artificial neural network and residual network

Abstract Separate-layer injection technology is a highly significant approach for enhancing oil recovery in the later stages of oilfield production. Both separate-layer and general injection information are crucial parameters in multi-layer oilfield injection systems. However, the significance of general injection information is usually overlooked during the optimization process of separate-layer injection. Moreover, conventional optimization schemes for separate-layer injection fails to meet the immediate and dynamic demands of well production. Consequently, a separate-layer injection optimization method based on ANN-Res model was proposed. Firstly, the primary controlling factors for production were identified through grey correlation analysis and ablation experiments. Then, a data-driven model was established with artificial neural network (ANN), in which the residual block was utilized to incorporate general injection information, eventually formed an ANN-Res model that integrates separate-layer and general injection information. Finally, a workflow for separate-layer injection optimization was designed in association with the ANN-Res model. Analysis of primary controlling factor for production shows that the combination of separate-layer and general injection information for production prediction leads to redundancy. The results of injection-production prediction demonstrate that the ANN-Res model is significantly better than that of the ANN model which only inputs separate-layer or general injection information. Furthermore, the result of optimization proves the proposed method can be successfully applied to injection optimization, realizing the purpose of increasing oil production and decreasing water cut, thereby improving oilfield development.

Reservoir Simulations of Hydrogen Generation from Natural Gas with CO2 EOR: A Case Study

This paper addresses the problem of hydrogen generation from hydrocarbon gases using Steam Methane Reforming (SMR) with byproduct CO2 injected into and stored in a partially depleted oil reservoir. It focuses on the reservoir aspects of the problem using numerical simulation of the processes. To this aim, a numerical model of a real oil reservoir was constructed and calibrated based on its 30-year production history. An algorithm was developed to quantify the CO2 amount from the SMR process as well as from the produced fluids, and optionally, from external sources. Multiple simulation forecasts were performed for oil and gas production from the reservoir, hydrogen generation, and concomitant injection of the byproduct CO2 back to the same reservoir. EOR from miscible oil displacement was found to occur in the reservoir. Various scenarios of the forecasts confirmed the effectiveness of the adopted strategy for the same source of hydrocarbons and CO2 sink. Detailed simulation results are discussed, and both the advantages and drawbacks of the proposed approach for blue hydrogen generation are concluded. In particular, the question of reservoir fluid balance was emphasized, and its consequences were presented. The presented technology, using CO2 from hydrogen production and other sources to increase oil production, also has a significant impact on the protection of the natural environment via the elimination of CO2 emission to the atmosphere with concomitant production of H2.

The effect of aquathermolysis catalyst on the processing of Yarega oil

This study focuses on the synthesis of oil-soluble precursor catalysts using iron and nickel and evaluates their performance through laboratory simulations of aquathermolysis processes under varying temperature and duration conditions. The investigation highlights that the initial oil sample exhibits high resin content (27 %) and asphaltenes (∼4 %). Gas phase analysis reveals a significant increase in the levels of n-C1-C5 hydrocarbons and C4–C10 isomers (up to 3.5–4 times compared to control experiments), indicating substantial alterations in the oil's composition. After thermal steam treatment (TST), the viscosity of all samples decreases in comparison to the initial oil. For instance, when using an iron talate catalyst, the viscosity drops to 575 mPa s, which is approximately 10.5 times lower than the initial oil viscosity of 6027 mPa s. Additionally, experiments involving iron-based catalysts consistently exhibit reduced viscosity compared to control experiments, achieving a 2.2-fold decrease after a 72-h duration (from 1928 mPa s to 743 mPa s).Economic evaluations were conducted, demonstrating an additional oil production increase of 2855 tons. The net discounted income over a span of 4 years, resulting from the application of this catalytic aquathermolysis technology, totaled 40,652,750 russian rubles.

Synergizing Solar Power with Enhanced Oil Recovery: Integrating Solar-Assisted Methods into Existing EOR Techniques

This study investigates the utilization of solar energy to enhance the efficiency of oil recovery processes, known as Solar Assist-Enhanced Oil Recovery (SA-EOR). The project objectives involve assessing the feasibility and effectiveness of integrating solar technologies with traditional oil recovery methods, such as steam injection or water flooding, to improve oil production rates and reduce operational costs. Methods employed include computational modeling, laboratory experiments, and field trials to evaluate various solar-assisted techniques and their impact on oil recovery. Key findings suggest that solar integration can enhance oil recovery by optimizing thermal processes, improving fluid mobility, and reducing environmental footprint. Additionally, the study underscores the economic viability and sustainability of SA-EOR solutions in the context of evolving energy landscapes. Overall, this research contributes valuable insights into the potential of solar technologies to revolutionize conventional oil recovery practices and advance towards more efficient and environmentally friendly energy production methods. Methods, termed Solar Assist-Enhanced Oil Recovery (SA-EOR). The objective is to investigate the efficacy of utilizing solar power to optimize thermal processes in oil extraction, such as steam injection or water flooding. Through computational modeling, laboratory experiments, and field trials, various SA-EOR techniques are evaluated for their potential to enhance oil recovery rates and reduce environmental impact. Findings indicate promising opportunities for leveraging solar energy to improve fluid mobility, optimize reservoir conditions, and ultimately increase oil production efficiency. This research underscores the significance of SA-EOR methods in advancing sustainable energy practices within the oil industry while addressing pressing environmental concerns.

The effect of fir wood SLS surfactant concentration on the characteristics of light crude oil

As time progresses, oil production will gradually depletes considering limited oil reserves. This is why, an advanced stage method known as tertiary oil recovery is required. One of these methods is known as Enhanced Oil Recovery method. In this laboratory study, one specific surfactant fluid was used, namely Fir wood sodium lignosulfonate (SLS) with varying concentrations of 0.50; 1.00; 1.50; 2.00; 2.50; and 3.00% each crude oil 39 ° API. This study aims to witness the stability of SLS surfactant fluid in chemical injection. SLS surfactant injection is carried out to increase oil production in the reservoir. In this study, there are various stages in order to test the characteristics of the SLS surfactant, so it can be declared as effective in oil sweeping, namely phase behaviour test, density testing, phase behaviour test, interfacial tension test, and adsorption test. Density test is carried out to determine the density of a fluid. Phase behaviour test is intended to see the stability of emulsion obtained from the utilization of SLS surfactant. The main objective of surfactant utilization is to reduce interfacial tension which leads to IFT test. The IFT (interfacial tension) results of the SLS surfactant fluid are determined from the results of the stable phase behaviour test which evidently shows the critical micelle concentration (CMC) point, so it can properly reduce the interfacial tension of oil and formation water in the reservoir. Interfacial tension test was carried out to determine the interfacial tension between SLS surfactant and oil. Adsorption test is carried out to witness the level of fluid adsorption onto the rock surface. On static adsorption test, the result showed for 2 % surfactant concentration is 9.526 mg/gr. Dynamic adsorption test was conducted on the same concentration show results of respectively 1.865 mg/gr.

Carbon capture storage and carbon capture utilization storage as energy transition strategy for the Indonesian oil and gas sector towards net zero emissions

The transportation and industrial sectors are the backbone of the Indonesian economy. These two sectors can grow and develop because of the support of energy from oil and gas or electricity from fossil sources. Meanwhile, energy from fossil sources, especially oil and gas, is one source of CO2 emissions that must be reduced. The Indonesian government continues to increase oil and gas production to meet domestic needs. On the other hand, the government is also trying to reduce emissions towards Net Zero Emissions by 2060 in line with the ratification of the Paris Agreement, with a target of reducing emissions by 314 million tons of CO2e in 2030 and 1,526 million tons of CO2e 30 years later. This condition is certainly a challenge for the government and the national oil and gas sector to achieve this target, the government has presented several strategies to boost upstream oil and gas investment while meeting the NZE target. Carbon Capture Storage and Carbon Capture Utilisation and Storage are one of the technologies of choice in the oil and gas sector in the energy transition period towards NZE. This strategy was chosen because it has great potential in carbon capture and can be used to increase oil production. The application picks up after 2025, with the amount of CO2 captured potentially 6 million tons annually in 2030 and reaching around 160 million tons annually in 2060.

Global Genetic Algorithm for Automating and Optimizing Petroleum Well Deployment in Complex Reservoirs

Locating petroleum-productive wells using informed geological data, a conventional means, has proven to be tedious and undesirable by reservoir engineers. The former numerical simulator required a lengthy trial-and-error process to manipulate the variables and uncertainties that lie on the reservoir to determine the best placement of the well. Hence, this paper examines the use of a global genetic algorithm (GA) to optimize the placement of wells in complex reservoirs, rather than relying on gradient-based (GB) methods. This is because GB approaches are influenced by the solution’s surface gradient and may only reach local optima, as opposed to global optima. Complex reservoirs have rough surfaces with high uncertainties, which hinders the traditional gradient-based method from converging to global optima. The explicit focus of this study was to examine the impact of various initial well placement distributions, the number of random solution sizes and the crossover rate on cumulative oil production, the optimization of the synthetic reservoir model created by CMG Builder, CMOST, and IMEX indicated that using a greater number of random solutions led to an increase in cumulative oil production. Despite the successful optimization, more generations are required to reach the optimal solution, while the application of GA on our synthetic model has proven efficient for well placement; however, different optimization algorithms such as the improved particle swarm (PSO) and grey wolf optimization (GWO) algorithms could be used to redefine well-placement optimization in CMG.

A mini-review on biosurfactants from natural-based resources: Sources, production, and application in oil industries

Increasing energy demand and depletion of producing wells around the globe necessitate oil industries to seek alternative mechanisms to increase oil production. Among various chemical enhanced oil recovery (CEOR) unveiled today, surfactants have become indispensable chemical agents in oil industries because of their wide applications in both onshore and offshore operational activities. Unfortunately, considerable numbers of these surfactants are synthetic causing treatment and disposal of effluents uneconomical to oil industries. This arises due to strong legislation laws enforced by governing bodies to ensure cleaner and safer environments. Consequently, the search for biodegradable surfactants from natural-based resources has revolved around the oil industries aimed at reducing the impacts of synthetic products both environmentally and economically. Plants are widely recognised as natural resources to obtain biosurfactants from their naturally producing saponins. In addition, other chemical compounds derived directly from plant parts are converted to biosurfactants commonly referred to as green biosurfactants. However, researchers have expressed reservations about sustainable biosurfactant production from plants due to limited access to plant resources. The present review discusses the types, properties, sources, synthesis, and applications of biosurfactants in EOR. Furthermore, the paper presents prospects of biosurfactants in EOR and proposes a sustainable production mechanism.

INFLUENCE OF ASSOCIATED PETROLEUM GAS COMBUSTION VOLUMES ON AVERAGE ANNUAL SURFACE AIR TEMPERATURE INCREASE IN WESTERN SIBERIA

On April 2016, Russia signed the Paris Climate Agreement, under which by 2030 it pledged to significantly reduce greenhouse gas emissions to no more than 70 % of 1990 levels annually. However, this may be hindered by a number of factors, in particular the significant increase in oil production at new oil and gas fields being brought into commercial development. Most of these facilities are concentrated in inaccessible areas with poor infrastructure, which significantly complicates the process of associated petroleum gas utilization and calls into question the fulfillment of commitments made. At the moment, carbon regulation in Russia is at the initial stage: in 2018, the level of greenhouse gas emissions from Russia amounted to only 52 % of the 1990 level. This has a significant contribution to the change in the temperature background of oil-producing regions, the main one being Western Siberia. Therefore, the study of such a massive anthropogenic impact on the environment, such as the mass flaring of associated petroleum gas on an industrial scale, is confidently correlated with Russia's stated strategic goals to significantly reduce the amount of CO2 emissions into the atmosphere.

MODEL-BASED ANALYSIS TO EVALUATE THE EFFECT OF POLYMER PROPERTIES AND PHYSICAL PHENOMENA ON POLYMER FLOODING OPERATIONS

Polymer flooding, known for enhancing heavy oil displacement, may encounter efficiency-limiting physical phenomena. This work assesses the impact of key factors like viscosity, shear rate, and adsorption in field applications using a model-based approach on the EPIC001 case, a real offshore Brazilian heavy oil reservoir. In simulation results, increasing the displacing fluid viscosity using apparent or zero-shear functions, oil production and economic returns show improvements over waterflooding. The shear rate effect slightly increases oil production and enhances injectivity loss due to shear-thinning in polymer flow. However, modeling it increases computation costs, as it extends simulation run time from minutes to days, making it impractical for intensive processes like production optimization. An analysis of the method’s effectiveness shows that it varies based on the adsorption level considered. At its highest value, even with a higher oil recovery factor, the economic return was lower than using waterflooding. Combining shear rate and adsorption has a minimal impact on field indicators when compared to adsorption alone. This work enhances the comprehension of physical phenomena and non-Newtonian behavior in tertiary polymer flooding on heavy oil reservoirs and its impact on the production forecast. It also highlights important considerations for modeling-based procedures.

Challenges and Opportunities for Pilot Scaling-Up Extraction of Olive Oil Assisted by Pulsed Electric Fields: Process, Product, and Economic Evaluation

This study aimed to investigate the impact of Pulsed Electric Fields (PEF) technology in the extraction of olive oil on a pilot scale, using the “Galega Vulgar” olive variety as raw material. The extraction assisted by PEF had a malaxation time of 30 min and was compared with the traditional process of 45 min of malaxation. The main quality parameters of olive oil and the PEF’s cost-benefit assessment were performed. The incorporation of PEF in olive oil production reduced the malaxation stage by 33% without compromising the yield or extra-virgin classification. This efficiency leads to a potential 12.3% increase in annual olive oil production, with a 12.3% and 36.8% rise in revenue and gross profit, respectively. For small-scale production, the considerable upfront investment required for PEF equipment may be a challenge in terms of return on investment. In this scenario, opting for a renting scheme is the best economic solution, especially given the seasonal nature of olive oil production. In medium- to large-scale production, the investment in PEF is a sound investment since it is possible to achieve, with an equipment cost of EUR 450,000 and a production output of 5 tons per hour, an annual ROI of 20%.