Enhanced Oil Recovery Methods Research Articles

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.

Low-Salinity Waterflooding for EOR in Field A of Western Offshore Basin: A Pilot Study Analysis with Laboratory and Simulation Studies—Early Observations

Carbonate reservoirs hold vast oil reserves, but their complex properties make traditional enhanced oil recovery (EOR) methods challenging. This study explores the application of low-salinity water flooding (LSWF) as a novel EOR method for India’s largest offshore carbonate oil field. Conventional EOR techniques were deemed unsuitable due to reservoir heterogeneity, pressure decline, high temperature, and the offshore location. Favorable factors for LSWF included successful seawater flooding history, medium-weight crude oil, and existing infrastructure. Following core flooding experiments demonstrating a 6–16% increase in oil recovery, a multi-pronged evaluation process was implemented. Single-well chemical tracer tests (SWCTT) and reservoir simulations confirmed the potential of LSWF. A specific target area was chosen based on reservoir characteristics, production data, and available facilities. Simulations predicted a 1.5% incremental oil recovery using diluted seawater (25% salinity) at 30% pore volume injection. After a positive techno-economic analysis, the first offshore LSWF project in India was completed within 3 years. Initial monitoring results are encouraging. This study highlights the successful journey of LSWF from concept to field deployment in a challenging carbonate reservoir, showcasing its potential for revitalizing such fields. Furthermore, this work provides valuable data relevant to Indian offshore environments, where factors like salinity, mineralogy, and crude oil composition pose unique challenges compared to other LSWF applications. These detailed data fill a critical gap in the existing literature.

Application of power-law committee machine to combine five machine learning algorithms for enhanced oil recovery screening

One of the main challenges in screening of enhanced oil recovery (EOR) techniques is the class imbalance problem, where the number of different EOR techniques is not equal. This problem hinders the generalization of the data-driven methods used to predict suitable EOR techniques for candidate reservoirs. The main purpose of this paper is to propose a novel approach to overcome the above challenge by taking advantage of the Power-Law Committee Machine (PLCM) technique optimized by Particle Swam Optimization (PSO) to combine the output of five cutting-edge machine learning methods with different types of learning algorithms. The PLCM method has not been used in previous studies for EOR screening. The machine learning models include the Artificial Neural Network (ANN), CatBoost, Random Forest (RF), K-Nearest Neighbors (KNN), and Support Vector Machine (SVM). The CatBoost is used for the first time in this work for screening of EOR methods. The role of the PSO is to find the optimal values for the coefficients and exponents of the power-law model. In this study, a bigger dataset than those in previous studies, including 2563 successful worldwide EOR experiences, was gathered. A bigger dataset improves the generalization of the data-driven methods and prevents overfitting. The hyperparameters of the individual machine-learning models were tuned using the fivefold cross-validation technique. The results showed that all the individual methods could predict the suitable EOR method for unseen cases with an average score of 0.868. Among the machine learning models, the KNN and SVM had the highest scores with a value of 0.894 and 0.892, respectively. Nonetheless, after combining the output of the models using the PLCM method, the score of the predictions improved to 0.963, which was a substantial increase. Finally, a feature importance analysis was conducted to find out the most influential parameters on the output. The novelty of this work is having shown the ability of the PLCM technique to construct an accurate model to overcome the class-imbalance issue in EOR screening by utilizing different types of data-driven models. According to feature importance analysis, oil gravity and formation porosity were recognized as the most influential parameters on EOR screening.

Идентификация компонентного состава твердой углеводородной фазы в пласте и оценка ее влияния на поведение подвижного флюида баженовской свиты в процессе разработки залежи

The purpose of the work is to identify the composition of the initial reservoir hydrocarbon (HC) system of the Bazhenov formation, as well as to assess the influence of the presence of a heavy solid hydrocarbon phase (bitumen) in the formation on the production of mobile fluids using PVT modeling methods. The article describes the necessary experiments to determine the component composition of the C81+ fraction and the PVT properties of the formation mobile fluid taken from the well and the bitumen extract from the rock, and also presents their results. In addition, the properties of fractions up to C81+ were calculated depending on the molecular weight for PVT modeling (extension of the Katz-Firuzabadi table). One of the important parts of the article is the assessment of the ratio of bound and free oil in the original reservoir system. Based on geochemical research data, an analysis was performed to assess the component composition of the original system (using the example of the Bazhenov Formation) using rock pyrolysis and studying formation fluid and bitumen. Using the results of studies of reservoir fluid samples, a PVT model was built and tuned. This PVT model was used to assess the properties of the initial reservoir hydrocarbon system and was adjusted to the fraction of the solid phase in the reservoir at the initial reservoir conditions. After this, based on the PVT model, an assessment was made of the influence of the presence of a solid phase in the composition of the reservoir system on the behavior of a mobile hydrocarbon fluid during reservoir development for depletion, as well as on the use of enhanced oil recovery methods (injection of associated petroleum gas and thermal methods of influencing the reservoir).

A comprehensive review direct methods to overcome the limitations of gas injection during the EOR process

Among the Enhanced Oil Recovery (EOR) methods, gas-based EOR methods are very popular all over the world. The gas injection has a high ability to increase microscopic sweep efficiency and can increase production efficiency well. However, it should be noted that in addition to all the advantages of these methods, they have disadvantages such as damage due to asphaltene deposition, unfavorable mobility ratio, and reduced efficiency of macroscopic displacement. In this paper, the gas injection process and its challenges were investigated. Then the overcoming methods of these challenges were investigated. To inhibit asphaltene deposition during gas injection, the use of nanoparticles was proposed, which were examined in two categories: liquid-soluble and gas-soluble, and the limitations of each were examined. Various methods were used to overcome the problem of unfavorable mobility ratio and their advantages and disadvantages were discussed. Gas-phase modification has the potential to reduce the challenges and limitations of direct gas injection and significantly increase recovery efficiency. In the first part, the introduction of gas injection and the enhanced oil recovery mechanisms during gas injection were mentioned. In the next part, the challenges of gas injection, which included unfavorable mobility ratio and asphaltene deposition, were investigated. In the third step, gas-phase mobility control methods investigate, emphasizing thickeners, thickening mechanisms, and field applications of mobility control methods. In the last part, to investigate the effect of nanoparticles on asphaltene deposition and reducing the minimum miscible pressure in two main subsets: 1- use of nanoparticles indirectly to prevent asphaltene deposition and reduce surface tension and 2- use of nanoparticles as a direct asphaltene inhibitor and Reduce MMP of the gas phase in crude oil was investigated.

An Overview of Oil Recovery Techniques: From Primary to Enhanced Oil Recovery Methods

As we all know, numerous methods have been invented for better managing of the reservoirs to recover the trapped oil from them as much as possible. These techniques included primary techniques that were implemented primarily at the beginning of this industry. As these techniques were not effective enough, secondary techniques, like; water flooding and gas injection methods were created and the amount of recovered oil were increased, as well. On the contrary, the demand for more oil was raised up and it was felt that much more effective techniques are necessary. It resulted to creation of Enhanced Oil Recovery Techniques and these techniques are included; thermal methods (steam injection, steam assisted gravity drainage and in-situ combustion), Chemical methods (alkali flooding, surfactant flooding, polymer flooding, foam flooding, and combination of alkali-surfactant-polymer flooding), and microbial EOR. The most promising technique is microbial EOR because of being cost-effective and ecofriendly. GEMEOR (Genetically Engineered MEOR) and EEOR (Enzyme Enhanced Oil Recovery) are two new trends of MEOR that own potential hopes in petroleum industry.

Spontaneous imbibition of modified salinity brine into different lithologies: an improvement of comprehensive scaling used for fractured reservoir simulation

AbstractSpontaneous water imbibition into matrix blocks can be a significant oil recovery mechanism in fractured reservoirs. Many enhanced oil recovery methods, such as injection of modified salinity brine, are proposed for improving spontaneous imbibition efficacy. Many scaling equations are developed in the literature to predict spontaneous imbibition oil recovery. However, almost none of them included the impact of the diversity in ionic composition of injected and connate brines and the blending/interaction of a low salinity imbibing brine with a higher salinity connate brine. In this research, these two issues are included to propose new scaling equations for the scaling of spontaneous imbibition oil recovery by modified salinity imbibing brines. This study uses experimental data of the spontaneous imbibition of modified salinity brines into oil-saturated rock samples with different lithologies containing an irreducible high salinity connate brine. The collected tests from the literature were performed at high temperatures and on aged altered wettability cores. The results of 110 available spontaneous imbibition laboratory experiments (85, 12 and 13 tests on chalks, dolomites and sandstones, respectively) are gathered. This research initially shows the poor ability of three selected convenient scaling equations from the literature to scale imbibition recovery by modified salinity brine. Then, our newly proposed technique to find the scaling equation for spontaneous imbibition recovery by modified salinity brine, during the abovementioned conditions in limestones (Bassir et al. in J Pet Explor Prod Technol 13(1): 79–99, 2023. https://doi.org/10.1007/s13202-022-01537-7) is used in chalks, dolomites and sandstones to develop the three new scaling equations. Finally, a new general equation to scale imbibition recovery by modified salinity brine for all four lithologies is presented. Moreover, for each of the four datasets (chalk, dolomite, sandstone and all the four lithologies), the scaled data by the new equations is matched by two mathematical expressions based on the Aronofsky et al. model and the Fries and Dreyer model. These mathematical expressions can be used to develop transfer functions in reservoir simulators for a more accurate prediction of oil recovery by spontaneous imbibition of modified salinity brine in fractured reservoirs.

APPLICATION PROGRESS OF INSITU POLYMER GEL IN OILFIELD CONFORMANCE CONTROL TREATMENT

Many oilfields around the world are using enhanced oil recovery methods to maximize oil production. Longterm water flooding processes have led to water channeling in mature reservoirs, which is a severe problem in oilfields. Polymer gel is widely used as a plugging agent to reduce water production. Previously, the conventional polymer gel is extensively used for blocking the thief zones, but the performance of conventional polymer gel is not satisfactory in high salinity and high temperature conditions due to rapid syneresis and thermal degradation. The amphiphilic polymer is taking much attention for polymer gel formulation because they are more salt resistant in low concentration compared to high concentration conventional HPAM polymer. In this paper, the crosslinking mechanism of insitu polymer gel is reviewed. The related difficulties and development prospects of polymer gels are presented. It provides a basis for the application of polymer gel in oilfield conformance control treatment. This will help researchers to develop polymer gels to improve oil recovery under economic conditions to meet the requirements of oilfields.

An Ethane-Based CSI Process and Two Types of Flooding Process as a Hybrid Method for Enhancing Heavy Oil Recovery

Combining multiple secondary oil recovery (SOR)/enhanced oil recovery (EOR) methods can be an effective way to maximize oil recovery from heavy oil reservoirs; however, previous studies typically focus on single methods. In order to optimize the combined process of ethane-based cyclic solvent injection (CSI) and water/nanoparticle-solution flooding, a comprehensive understanding of the impact of injection pressure, water, and nanoparticles on CSI performance is crucial. This study aims to provide such understanding through experimental evaluation, advancing the knowledge of EOR methods for heavy oil recovery. Three approaches (an ethane-based CSI process, water flooding, and nanoparticle-solution flooding) were applied through a cylindrical sandpack model with a length of 95.0 cm and a diameter of 3.8 cm. Test 1 conducted an ethane-based CSI process only. Test 2 conducted a combination approach of CSI–water flooding–CSI–nanoparticle-solution flooding–CSI. Specifically, the injection pressure of the first CSI phase in Test 2 was gradually increased from 3500 to 5500 kPa. The second and the third CSI phases had the same injection pressure as Test 1 at 5500 kPa. The CSI process ceased once the oil recovery was less than 0.5% of the original oil in place (OOIP) in a single cycle. Results show that the ethane-based CSI process is sensitive to injection pressure. A high injection pressure is crucial for optimal oil recovery. The first CSI phase in Test 2, where the injection pressure was increased gradually, resulted in a 2.9% lower oil recovery and five times as much ethane consumption compared to Test 1, which applied a high injection pressure. It was also found that water flooding improved the oil recovery in the CSI process. In Test 2, the oil recovery factor of the second CSI phase increased by 57% after the water flooding process, which is likely due to the formation of water channels and a dispersed oil phase that increased the contact area between ethane and oil. Although the nanoparticle-solution flooding only had 0.3% oil recovery, after that the third CSI phase stimulated another 10.8% of OOIP even when the water saturation achieved more than 65%. This demonstrated that the addition of nanoparticles can maintain the stability of the foam and enhance the transfer of ethane to the heavy oil. Finally, Test 2 reached a total oil recovery factor of 76.1% on a lab scale, an increase of 45% compared to the single EOR method, which proved the combination process is an efficient method to develop a heavy oil field.

Global enhanced oil recovery assessment: A comprehensive data-driven analysis using self-organizing maps

This study presents a comprehensive analysis of Enhanced Oil Recovery (EOR) methods' application in the global oil industry, identifying trends and main factors influencing their adoption. A wealth of unstructured and scattered data from public documents covering traditional EOR methods and newer technologies was processed to create a reliable global database, encompassing 1237 EOR projects in reservoirs around the world. Data science techniques and self-organizing maps (SOM) were employed for data analysis, dimensionality reduction, and visualization of complex problems, proving suitable for high-dimensionality and incomplete data. The research integrates various data modalities and data science visualization techniques, enabling a high-level representation of EOR projects' self-contained knowledge, and providing a comprehensive view of EOR application worldwide. The study reveals implicit interrelationships between multiple variables and EOR methods, identifying trends, research and development directions, and better-informed decisions. In-depth analysis showed that factors impacting the choice, application, and success of EOR methods include technical properties of reservoirs, local, commercial, and temporal aspects. Despite the diffusion of secondary and tertiary recovery technologies, a concentration of EOR methods exists in specific regions. Factors influencing EOR projects' implementation, maintenance, and expansion range from technical reasons, deselected reserves, and infrastructure to incentive policies and regulatory aspects of each country, business structure, and global economic scenario. Both petrophysical and non-petrophysical variables influence the application of EOR methods. Availability and costs of purchasing and transporting injection fluids greatly impact decision-making processes. The analysis contributes to understanding the complex network of factors influencing EOR, and this work can aid in making more informed decisions in the industry and research for EOR applications.

Methane foam performance evaluation in fractured oil-wet carbonate systems at elevated pressure and temperature conditions

This study investigates the potential of foam flooding for enhanced oil recovery in oil-wet fractured systems under reservoir conditions. Two surfactants with distinct ionic properties were employed in combination with methane to generate foam via simultaneous injection into propped fractures, aiming to optimize the diversion of gas from fractures to the matrix for improved oil recovery. Core flooding experiments demonstrated the critical roles of total injection rate and foam quality in controlling foam performance. Increasing the total injection rate from 1 to 3 cm³/min enhanced foam generation rates and foam lamella stability, facilitating better interactions between fractures and the matrix. However, beyond an injection rate of 4 cm³/min, there was a decline in apparent viscosity and mobility reduction factor. Foam strength was directly proportional to higher foam quality within the 50 to 80% range, but beyond 85% foam quality, fluctuations in pressure drop signaled the formation of weaker, less stable foams. Micro-scale experiments validated these macroscopic findings, revealing that smaller bubbles were associated with higher flow rates and lower foam qualities. This research contributes valuable insights into both micro and macro-scale in-situ foam generation, which can inform the design and application of foam-based enhanced oil recovery methods in fractured reservoirs.

Biphasic interfacial functioning improvement using naturally derived Hop and Dill surfactants in carbonate reservoirs

This study mainly focuses on the application of environmentally friendly surfactants in enhanced oil recovery (EOR). Two natural and environmentally friendly surfactants of Hop and Dill were introduced to observe their visions of fluid/fluid/rock interfacial activity of surfactant solutions as ion tuned EOR method. Investigations of interfacial tension (IFT) reduction and wettability alteration toward a water-wetting tendency were conducted to evaluate the improvement of oil recovery factor. Dynamic displacement tests of carbonate porous medium flooding including both secondary and tertiary flooding were conducted to observe the validity of IFT reduction and wettability alteration (contact angle decrease, CA) effects. IFT measurements showed that Dill and Hop surfactants can reduce the initial IFT of 28 mN/m to 2.443 and 5.614 mN/m, respectively. Ion concentration tuning showed that 10,000 ppm of NaCl is the optimum concentration that could enhance the optimization value of Dill surfactant from 91.27% to 92.8% (with 17.46% improvement compared with CMC of Dill). In addition, NaCl salt at the same concentration improved the effectiveness of Hop surfactant by 6.1%. Meanwhile, the used surfactants reduced the contact angle from 151° to 75° and 65° for Dill and HOP, respectively. Ion tuning showed that 10,000 ppm of salinity effect could enhance the optimization by Dill and Hop to 70.86 and 71.54%, respectively. Zeta potential measurements proved that the contact angle results in a complementary manner. Core flood tests validated previous results through the improvements in the recovery of oil by 8.56 and 10.11% original oil in place (OOIP) for HOP and Dill natural surfactants, respectively.

OPPORTUNITIES TO INCREASE THE ECONOMIC EFFICIENCY OF CO2 USE PROJECTS

Against the background of structural problems of the oil and gas industry, an increase in the share of hard-to-recover reserves, an increase in greenhouse gas emissions, and an unstable macroeconomic situation, the issue of improving the efficiency of field development, both from a technological and economic point of view, is acute. The results of the studies show that without the use of modern methods of improving oil recovery, maintaining stable production levels across the industry is becoming more difficult. Today, the efficiency of oil extraction by the main development methods is considered unsatisfactory, given the growing global consumption of petroleum products.Over the years, global interest in enhanced oil recovery has increased, and research is underway to find a scientifically sound approach to selecting the most efficient oil field development technologies.Despite the large number of experiments and the accumulated practical experience in using enhanced oil recovery methods, there is currently a wide gap between the needs of oil field stakeholders and the supply of services to implement these methods.Environmental issues are also important. Significant amounts of greenhouse gas emissions and the need for their disposal suggest the search for optimal ways to use them. Reducing СО2 emissions is a complex process involving capturing it in industrial plants, transporting it from capture sites to use sites, and locating it in geological sites.The subject of the study is to assess the feasibility of using СО2 as a method of increasing oil recovery.The article presents the results of a technical and economic assessment of the feasibility of using СО2 in an injection agent to improve oil recovery using the example of one of the fields in the West Siberian oil and gas province. The assessment showed that from a technological point of view, it is advisable to use the method, additional oil production is 3–7 %. However, additional tax incentives are required for interventions to become economically effective, as the interventions are highly capital intensive. The authors proposed an incentive option to ensure a positive economic effect, as well as to avoid a decrease in tax revenues compared to the basic option with water injection.

Phase equilibria calculations of a hydrocarbon system consisting water and asphaltene using association equation of state: A generalized auto-tune procedure

A generalized algorithm is proposed for four-phase flash calculations in hydrocarbon-water systems in which asphaltene has tendency to be precipitated. The systems which are going to be studied in this paper can be either single phase, two-phase, three-phase or four-phase of gas, oil-rich, asphaltene-rich and aqueous phases. The properties of vapor and oil-rich (liquid) phases can be predicted using any EOS while Henry's law is performed for calculating the properties of water-rich (aqueous) phase. In addition, an association equation of state (AEOS) has been used to predict the amount of the precipitated asphaltenes at different conditions. Using the proposed algorithm, one can predict the number and types of phases and also the properties of each phase, as accurate as possible. As tuning of EOS models is tedious and time consuming, a generalized and auto-tune method based on sensitivity and optimization algorithms is also applied in this study so that the best model could be found easily, quickly and automatically. The proposed approach proved to be efficient, and very good agreement between the results of the presented method and experimental data was found for different test problems. This new procedure can be very useful in compositional reservoir simulation of certain enhanced oil recovery methods and in surface facility process simulation.

Experimental and numerical modeling of a novel surfactant flooding: Core scale to reservoir models

This comprehensive study delves into an application of surfactant flooding as a robust enhanced oil recovery (EOR) technique, incorporating both core-scale experiments and reservoir-scale numerical simulations. The research's focal point is to evaluate a novel surfactant's performance in extending oil recovery efficiency within an oil reservoir. The study commences with thorough laboratory experiments at the core scale, illuminating the interplay of fluids within porous media. Transitioning seamlessly to reservoir-scale numerical modeling, the research replicates real-world reservoir conditions. Various well configurations are scrutinized to optimize surfactant flooding strategies for EOR purposes. A key aspect of this analysis is the in-depth examination of the sensitivity of numerical simulations to changes in relative permeability curves during surfactant injection, enabling a robust assessment of the performance of surfactant injection in a broad spectrum of uncertainties. Comparative experiments elucidated the significant influence of a surfactant molecular structure, with aliphatic variants showcasing superior oil displacement efficiency. Moreover, combining surfactant and polymer proved pivotal, enhancing reservoir sweep efficiency and significantly boosting oil recovery. This work establishes a comprehensive framework for evaluating chemical flooding, including surfactant and polymer, as a potent EOR method by bridging the gap between core-scale experiments and reservoir-scale simulations.

Experimental study of asphaltene deposition during CO2 and flue gas injection EOR methods employing a long core

Gas injection is a well-known method for enhancing oil recovery (EOR). The utilization of greenhouse gases, such as carbon dioxide (CO2) or flue gas, offers the dual advantage of reducing greenhouse gas emissions while potentially enhancing the sweep efficiency in oil recovery. Nevertheless, one of the notable challenges encountered when using these gases is the precipitation and deposition of asphaltenes, leading to formation damage and a decrease in reservoir permeability, particularly in the case of light oil reservoirs. In this study, CO2 and flue gas were injected into an elongated core sample comprising four individual core plugs under reservoir conditions to displace the light live oil. The recovery factor and asphaltene deposition along the core holder were assessed and compared as two crucial parameters within the gas injection scenario. Our results indicate a significantly higher recovery factor of 86% achieved with CO2 injection compared to 36% with flue gas injection, attributable to differences in their interfacial tension and miscibility. However, the CO2 injection method exhibits more pronounced formation damage. Individual assessment of each core plug reveals that permeability impairment is most acute in the initial two core plugs, situated closer to the injection face of the extended core. These findings enhance our understanding of the mechanisms contributing to permeability impairment resulting from asphaltene deposition during CO2 and flue gas injection for EOR.

Chevron Applies Some Unconventional Thinking To Try To Make Shale EOR a Standard Treatment

In the shale business, the closest thing now to enhanced oil recovery (EOR) is improved techniques. During an earnings call last November an analyst asked EOG Resources executives about their enhanced completion technique which EOG reported was adding 20% to first-year well production in the Permian. Improved completions have allowed operators to significantly increase early production year after year, but after that, steep declines are a given. Back in 2016, EOG was talking about how it was increasing oil production significantly by injecting millions of cubic feet of gas a day into wells in the Eagle Ford. It triggered an EOR field-testing boom by competitors hoping to match reported reserve increases of “30 to 70%.” In a 2017 JPT story, Deepak Devegowda, a petroleum engineering professor at the University of Oklahoma, said, “This is the name of the game. Everybody is talking about EOR and pumping money into trials of EOR.” Now the only mention of the acronym EOR on EOG’s website is an item in its corporate history timeline for 2016: “We commercialized the first enhanced oil recovery process, or EOR, in shale.” In recent years, reported shale EOR work has been mostly in the form of occasional papers describing production uplift by companies selling ways to increase production by injecting gas or chemicals. EOR effectiveness isn’t the issue, according to Todd Hoffman, a petroleum engineering professor at Montana Tech University who wrote two papers evaluating EOG’s methods cited in two Chevron papers. “The EOG field work showed us that these projects can produce significant additional oil and be economically positive,” he said. The problem is that drilling and fracturing wells delivers “higher economic returns than the EOG-style EOR projects with the huge compressors, high gas rates, and high injection pressures.” Last year in the middle of this EOR drought, Chevron did something different. It delivered two papers revealing a major company-scale effort to find ways to use chemical and gas injections to economically produce more oil. The papers presented at the 2023 Unconventional Resources Technology Conference (URTeC) reported on field tests of surfactants and natural gas injection on Permian Basin wells which delivered sufficiently encouraging results to justify an expanded testing program. (URTeC 3870505 and URTeC 3871386). Chevron described a systematic effort by its corporate technical unit and its Mid-Continent business unit to rethink shale EOR methods based on the unconventional nature of flow through fractured reservoirs and the economic realities in a business where new EOR technology is competing with the profitable status quo. Its methods challenge accepted notions about the role of EOR. In SPE’s disciplines, EOR normally falls under the production topic, “marginal aging fields.” What Chevron tested is better described by the topic, “well interventions.” Rather than looking at these techniques as a way to eke out the last barrels from old wells, the papers describe methods that can be deployed earlier in the life of these short-lived wells.

EVALUATION OF CONTINUOUS AND WATER ALTERNATING GAS (WAG) CO2 INJECTION ON X FIELD RECOVERY FACTOR

Indonesia is a country rich in natural resources. The wealth of Indonesia's natural resources is not only limited to agricultural and plantation products, but also from mineral and hydrocarbon mining or oil and gas. Indonesia's oil production has continued to decline in the last 10 years until the national consumption rate is much higher than national production. One of the causes of the decline in oil production in Indonesia is the condition of Indonesia's oil fields, which are currently mature fields. To overcome the problem of old fields that still have economic oil reserves, enhanced oil recovery (EOR) can be used. One of the EOR methods that can be used is the CO2 injection method using continuous and WAG injection schemes. The study was conducted in X field with oil-wet carbonate rock composition with waterdrive and fluid expansion driving mechanism. The basecase production scheme using 5 production wells produces a recovery factor of 34.3%, while continuous CO2 injection produces a recovery factor of 32%, and CO2-WAG produces a recovery factor of 42%. Continuous CO2 injection has the lowest recovery factor because early gas breaktrough occurs due to a large mobility ratio and causes gas fingering, hindering the oil production process. The most suitable injection method is CO2-WAG 1 cycle using a 1:1 ratio, CO2 injection volume of 6.661 MSCF/D, injection water volume of 37.4 MBBL/D with a recovery factor of 43.46%.

New Trends in Biosurfactants: From Renewable Origin to Green Enhanced Oil Recovery Applications.

Enhanced oil recovery (EOR) processes are technologies used in the oil and gas industry to maximize the extraction of residual oil from reservoirs after primary and secondary recovery methods have been carried out. The injection into the reservoir of surface-active substances capable of reducing the surface tension between oil and the rock surface should favor its extraction with significant economic repercussions. However, the most commonly used surfactants in EOR are derived from petroleum, and their use can have negative environmental impacts, such as toxicity and persistence in the environment. Biosurfactants on the other hand, are derived from renewable resources and are biodegradable, making them potentially more sustainable and environmentally friendly. The present review intends to offer an updated overview of the most significant results available in scientific literature on the potential application of biosurfactants in the context of EOR processes. Aspects such as production strategies, techniques for characterizing the mechanisms of action and the pros and cons of the application of biosurfactants as a principal method for EOR will be illustrated and discussed in detail. Optimized concepts such as the HLD in biosurfactant choice and design for EOR are also discussed. The scientific findings that are illustrated and reviewed in this paper show why general emphasis needs to be placed on the development and adoption of biosurfactants in EOR as a substantial contribution to a more sustainable and environmentally friendly oil and gas industry.

Structuring and preliminary selection of enhanced oil recovery methods for the current reservoir conditions of Block C2N, Joint Venture Petrovictoria (Venezuela)

Global heavy oil reserves are the largest hydrocarbon resource in the world, with Venezuela's heavy oil reserves accounting for 87% of initial oil reserves; 258.3 out of 297.7 billion barrels. Primary oil production from such formations does not allow achieving a high recovery factor, which is only 5 to 10% due to the high viscosity of the reservoir oil and low mobility. The main purpose of the work is to determine the hierarchy and, with its help, preliminary selection of enhanced oil recovery (EOR) methods for the current reservoir conditions of the Carabobo 2 North block of the Petrovictoria joint venture, Venezuela. The methodology for selecting promising enhanced oil recovery methods for the created geological model of one of the objects for the potential application of enhanced oil recovery (EOR) methods in Venezuela (Orinoco Belt, Carabobo 2 North Block) is formed using applicability criteria. An EOR for an object based on the theory of fuzzy sets is proposed and evaluated. The main purpose of the work is to create a hierarchy and preliminary selection of methods for increasing oil recovery for the current conditions of the formation of the Carabobo 2 North block of the Petrovictoria joint venture, Venezuela. The method of selection (screening) of promising methods of increasing oil recovery for the created geological model of one of the objects of potential application of the Venezuelan EOR (North, Orinoco Belt), formed using the criteria of applicability and selection of the most promising EOR for the object, based on the theory of fuzzy sets, is presented and tested Keywords: heavy oil; enhanced oil recovery (EOR); EOR selection (screening); Orinoco Belt.