Mature Reservoirs Research Articles

A coupled displacement-pressure model for elastic waves induce fluid flow in mature sandstone reservoirs

Elastic (seismic) wave stimulation is considered one of the unconventional enhanced oil recovery (EOR) methods. Increasing water quantity in the high permeability layer of a mature oil reservoir is highly challenging and can significantly decrease the ultimate recovery due to the reservoir heterogeneity. Using seismic waves can be considered low-cost, environmentally friendly, and illuminates the entire reservoir size compared to conventional EOR methods. A numerical model is developed by extending the Quintal approach for seismic attenuation due to wave-induced fluid flow (WIFF) to incorporate capillary pressure in partially saturated porous media and shift undrained boundary conditions to exclude external flow stress for drained boundary conditions. Therefore, the fluid distribution due to the capillary effect makes the developed finite element method (FEM) u-p model more widely applicable for oil recovery in mature reservoirs. A two-layer partially saturated media was subjected to compressive seismic stress at low frequency (3 Hz). The results indicated that the vertical displacement gradients of the bottom and upper layers decline with excitation time for both fully and partially saturated media. On the other hand, partially saturated pore pressure gradients of both the upper and bottom layers have higher amplitudes with excitation time than fully saturated pore pressure gradients due to the influence of capillar pressure. The cumulative crossflow oil volume for 180 days of continuous stimulation was 1176 bbl, 1032 bbl, and 648 bbl in low permeability layers: 200 md, 100 md, and 50 md, respectively. Therefore, the developed model has the potential for field-scale EOR applications. The study also suggests coupling elastic EOR with CO2 flooding to recover more oil due to increasing fluid mobility and relative permeability to oil in low-permeability reservoirs or tight formations.

Clumped isotopes constrain thermogenic and secondary microbial methane origins in coal bed methane

Methane is an economic energy resource and potent greenhouse gas. Distinguishing secondary microbial methane from thermogenic gas is important for natural gas exploration and consideration of subsurface microbial activity in the global carbon cycle, but remains challenging. To understand controls on methane origins in natural gas systems, we investigated the methane clumped isotopologue distributions in the Qinshui Basin high-thermal maturity coal bed methane (CBM) reservoir. Here, near-equilibrium clumped isotopologues distribution (Δ13CH3D and Δ12CH2D2) inferred a temperature interval of 21.6–252.3 °C. The high-temperature thermodynamic equilibrium most likely represents original thermogenic CBM characteristics during coalification. The low-temperature equilibrium clumped isotopologue distributions suggest microbial alteration to CH4 isotopic bond ordering by increased enzymatically catalyzed isotopic exchange. The independent constraints from clumped isotopes, integrated with other geochemical and genomic evidence, confirm notable secondary microbial methane from biodegradation in the highly mature reservoir. Thus, methane clumped isotopes can be used as unequivocal tracers to distinguish secondary microbial methane from thermogenic gases and hence provide the ability to incorporate them separately into global methane budgets.

ANALYSIS OF THE ECONOMIC PERFORMANCE OF PROJECT ADVANCED OIL RECOVERY WITH CO2 INJECTION (EOR/CCUS-CO2) THROUGH FINANCIAL INDICATORS: BRAZILIAN OVERVIEW

Enhanced Oil Recovery (EOR) is a method associated with Carbon Capture, Utilization, and Storage (CCUS) that consists of injecting CO2 into mature oil fields to store CO2 and enhance production. CO2-EOR projects are costly, requiring technical and economic evaluations to determine their viability. This research analyzes various economic parameters in CO2-EOR projects to develop a comprehensive model for assessing their economic viability in Brazil. The model was tested on projects developed by Silva et al. (2010) and included six scenarios of CO2-EOR in mature reservoirs. The results demonstrate the impact on well completion costs. The scenario with the highest oil production had one additional completion and, for this reason, did not show the best Net Present Value (NPV) result. This work also conducts a sensitivity analysis of parameters and reviews their impacts on NPV. Results indicate a significant impact of barrel price and minimum attractiveness rate on the NPV, while finding that the taxation of excess CO2 was not very significant. Low barrel prices (<$9) proved to be unfeasible with negative NPVs.

Influence of elastic modulus on enhanced oil recovery ability of branched-preformed particle gel in porous media

A heterogeneous phase combined flooding system composed of polymers, surfactants, and branched-preformed particle gel (B-PPG) has been successfully applied to enhance oil recovery in mature reservoirs. However, the influence of elastic modulus on the enhanced oil recovery of B-PPG is unclear. Thus, based on the sand-pack flooding experiments and visual flooding experiments, the enhanced oil recovery ability of B-PPG with different elastic modulus and similar particle size was investigated under different injection modes. Results show that under the single-slug injection mode, the higher the elastic modulus, the higher the incremental oil recovery, and the better the ability to enhance oil recovery. With the increase in the elastic modulus from 0.7 Pa to 42.2 Pa, the incremental oil recovery increased from 12.7% to 32.6%. Under the multi-slug alternating injection mode, the incremental oil recovery of injecting low elastic modulus B-PPG slug followed by high elastic modulus B-PPG slug was 2.8% higher than that of injecting high elastic modulus B-PPG slug followed by low elastic modulus B-PPG slug. The incremental oil recovery of B-PPG under the multi-slug alternating injection mode was higher than that under the single-slug injection mode. At the microscopic level, the type of remaining oil was mainly clustered after water flooding. With the increase in the elastic modulus, the ratio of the clustered remaining oil decreased and the ratio of the multi-porous, columnar, and droplet remaining oil increased. Compared with the single-slug injection mode, it was easier to recover the clustered remaining oil by B-PPG flooding under the multi-slug alternating injection mode.

Advancements in Surfactant Carriers for Enhanced Oil Recovery: Mechanisms, Challenges, and Opportunities.

Enhanced oil recovery (EOR) techniques are crucial for maximizing the extraction of residual oil from mature reservoirs. This review explores the latest advancements in surfactant carriers for EOR, focusing on their mechanisms, challenges, and opportunities. We delve into the role of inorganic nanoparticles, carbon materials, polymers and polymeric surfactants, and supramolecular systems, highlighting their interactions with reservoir rocks and their potential to improve oil recovery rates. The discussion includes the formulation and behavior of nanofluids, the impact of surfactant adsorption on different rock types, and innovative approaches using environmentally friendly materials. Notably, the use of metal oxide nanoparticles, carbon nanotubes, graphene derivatives, and polymeric surfacants and the development of supramolecular complexes for managing surfacant delivery are examined. We address the need for further research to optimize these technologies and overcome current limitations, emphasizing the importance of sustainable and economically viable EOR methods. This review aims to provide a comprehensive understanding of the emerging trends and future directions in surfactant carriers for EOR.

Insights into the Injectivity and Propagation Behavior of Preformed Particle Gel (PPG) in a Low-Medium-Permeability Reservoir.

Heterogeneous phase combined flooding (HPCF) has been a promising technology used for enhancing oil recovery in heterogeneous mature reservoirs. However, the injectivity and propagation behavior of preformed particle gel (PPG) in low-medium-permeability reservoir porous media is crucial for HPCF treatment in a low-medium-permeability reservoir. Thus, the injectivity and propagation behavior of preformed particle gel in a low-medium-permeability reservoir were systematically studied by conducting a series of sand pack flooding experiments. The matching factor (δ) was defined as the ratio of the average size of PPG particles to the mean size of pore throats and the pressure difference ratio (β) was proposed to characterize the injectivity and propagation ability of PPG. The results show that with the increase in particle size and the decrease in permeability, the resistance factor and residual resistance factor increase. With the increase in the matching factor, the resistance factor and residual resistance factor increase. The higher the resistance factor and residual resistance factor are, the worse the injectivity of particles is. By fitting the relationship curve, PPG injection and propagation standards were established: when the matching coefficient is less than 55 and β is less than 3.4, PPG can be injected; when the matching coefficient is 55-72 and β is 3.4-6.5, PPG injection is difficult; when the matching coefficient is greater than 72 and β is greater than 6.5, PPG cannot be injected Thus, the matching relationship between PPG particle size and reservoir permeability was obtained. This research will provide theoretical support for further EOR research and field application of heterogeneous phase combined flooding.

Innovative approaches in enhanced oil recovery: A focus on gas injection synergies with other EOR methods

Enhanced Oil Recovery (EOR) techniques have become crucial in extending the productive life of mature oil fields and maximizing resource extraction. Among these, gas injection methods, particularly those involving CO₂, nitrogen, and hydrocarbon gases, have shown significant promise. This review focuses on the innovative synergies achieved by combining gas injection with other EOR methods to enhance recovery efficiency and economic viability. Gas injection techniques work by increasing reservoir pressure and reducing oil viscosity, facilitating easier flow and extraction. When integrated with other EOR methods such as thermal, chemical, and microbial techniques, the synergistic effects can lead to even greater enhancements in oil recovery. For instance, the combination of gas injection with thermal EOR, like steam injection, can improve the displacement of heavy oils by simultaneously reducing viscosity and enhancing thermal conductivity within the reservoir. Similarly, integrating gas injection with chemical EOR methods, such as polymer flooding, can optimize the sweep efficiency by leveraging the mobility control provided by polymers and the pressure maintenance by gases. Recent advancements in monitoring and simulation technologies have further improved the effectiveness of these combined approaches. Real-time reservoir simulation and 4D seismic monitoring allow for precise tracking of gas and fluid movements, enabling dynamic adjustments to injection parameters for optimal performance. Smart well technologies, equipped with advanced downhole sensors, provide continuous data on reservoir conditions, facilitating more responsive and adaptive EOR strategies. However, these innovative synergies are not without challenges. Economic feasibility remains a significant concern, particularly given the high costs associated with gas procurement and the integration of multiple EOR techniques. Additionally, managing the complex interactions between different EOR methods and heterogeneous reservoir conditions requires sophisticated modeling and robust operational protocols. In conclusion, the integration of gas injection with other EOR methods offers a promising pathway to enhance oil recovery rates and extend the lifespan of mature reservoirs. Continued research and development, coupled with cross-industry collaboration, are essential to overcoming the economic and technical challenges associated with these innovative approaches. This review underscores the potential for gas injection synergies to revolutionize EOR practices and drive sustainable growth in the oil and gas industry.

RHEOLOGICAL AND THERMAL EVALUATION OF POLYACRYLAMIDE HYDROGEL PROPERTIES WITH ALUMINUM OR ZINC OXIDE

The increase in demand for oil-based energy and the difficulty in discovering new oil reserves mean that mature reservoirs need to be optimized. These reservoirs have already been widely explored and often have fractures or zones with high permeability contrasts. In these scenarios, the injected recovery fluids tend to flow preferentially, resulting in lower sweeping efficiency and lower oil production. To avoid these problems, conformance control techniques have been used to optimize reservoir sweep. This process works redirecting the injected fluids to the lower permeability segments, which increase the sweep efficiency. Polymeric hydrogels can work by blocking high permeability zones, and these systems consist of hydrophilic polymers, where polyacrylamide derivatives are the most common. To enhance the applicability in drastic reservoir conditions, gels nanocomposites can be produced with novel properties. This work approached the research for the best composition of the polyacrylamide derivative crosslinked with polyethyleneimine and evaluated the addition of zinc or aluminum oxide nanofillers. The study evaluated different oxides contents in terms of mechanical, thermal properties and morphology. The results showed that increasing the ZnO filler provided higher elastic modulus and thermal degradation resistance. These observations correlated with the microscopies, which showed better zinc oxide interaction with polymer matrix.

Revitalizing Reservoirs Nitrogen Kick-off Techniques for Reactivating Inactive Wells

This study explores the use of nitrogen (N2) injection to rejuvenate inactive wells and enhance reservoir productivity. We analyze the mechanism of N2 injection and its effectiveness in stimulating production from dormant wells through case studies and field applications. Our findings highlight the cost-effectiveness and environmental benefits of N2 kickoff in extending the life of mature reservoirs and maximizing hydrocarbon recovery. By examining operational conditions such as gas injection rate and pressure, we identify optimal conditions using Wellflo® simulations. Key factors like water cut, reservoir pressure, gas oil ratio, and productivity index (J) are considered to predict production outcomes. A new metric, the Optimum Economic Factor (OEF), assesses the efficiency of each operation based on production rate, operation length, and nitrogen usage. Our decision matrix, incorporating all examined factors, reveals trends: higher gas injection rates are needed for wells with higher water cut, lower gas oil ratio, lower productivity index, and lower reservoir pressure. We also studied the effects of wellhead pressure, well depth, and coiled tubing size, finding increased frictional pressure gradients with larger coiled tubing. Optimizing nitrogen unloading operations can significantly reduce costs, particularly by paying for coiled tubing packages on an hourly basis instead of daily rates. Our decision matrix facilitates planning and execution, optimizing nitrogen usage and reducing manpower requirements. Overall, our study demonstrates that proper optimization can make nitrogen unloading economically viable in mature oil fields.

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.

Experimental study of adsorption/desorption and enhanced recovery of shale oil and gas by zwitterionic surfactants

Shale reservoirs have the characteristics of low permeability and low porosity. In order to enhance the recovery of shale oil and gas, surfactant flooding is a mature reservoir oil recovery method. However, the adsorption of different surfactants on the reservoir rock surface is restricted, depending on the type of surfactant. Therefore, a zwitterionic surfactant (OPHS) was synthesized from oleic acid, 3-dimethylaminopropylamine and sodium 3-chloro-2hydroxypropanesulfonate, and characterized by FTIR, 1H NMR, and TGA, and the mechanism of the OPHS for enhancing oil and gas recovery on shale surfaces was investigated. The results showed that the critical micelle concentration (CMC) of OPHS surfactant solution is 7.9 × 10-4 mol/L and the γCMC is 27.5 mN/m; the concentration of 0.1 % OPHS surfactant solution could reduce the contact angle of the cores from 127.2° to 38.8°, which resulted in spontaneous imbibition; The absolute Zeta potential of shale particles in the OPHS surfactant solution was measured at 39 mV, whereas in deionized water at 15.3 mV. This difference can be attributed to the formation of a stable hydration film on the surface of shale particles induced by the wetting reversal effect. Spontaneous imbibition experiments showed that a 0.1 % solution of OPHS surfactant was able to increase the recovery rate by more than four times compared to the imbibition solution without added surfactant; In high-pressure gas adsorption/desorption experiments, the OPHS surfactant solution demonstrated a higher affinity for adsorption onto the shale surface. It effectively occupied adsorption sites, ultimately facilitating methane gas desorption from the shale. In summary, OPHS zwitterionic surfactants exhibit the capability to desorb hydrocarbons from shale pores through mechanisms such as wetting reversal and competitive adsorption. This research holds significant potential for advancing the field of shale oil and gas recovery, providing valuable insights for enhancing recovery processes.

A Doomed Reservoir Surprisingly Became a Mature Reservoir with Potential: Water Dump Flooding Case Study in Boca Field

A Doomed Reservoir Surprisingly Became a Mature Reservoir with Potential: Water Dump Flooding Case Study in Boca Field

Multi-Phase Flow Metering in Offshore Oil and Gas Pipelines

Multi-phase flow meters are of huge importance to the offshore oil and gas industry. Unreliable measurements can lead to many disadvantages and even wrong decision-making. It is especially important for mature reservoirs as the gas volume fraction and water cut is increasing during the lifetime of a well. Hence, it is essential to accurately monitor the multi-phase flow of oil, water and gas inside the transportation pipelines. The objective of this review paper is to present the current trends and technologies within multi-phase flow measurements and to introduce the most promising methods based on parameters such as accuracy, footprint, safety, maintenance and calibration. Typical meters, such as tomography, gamma densitometry and virtual flow meters are described and compared based on their performance with respect to multi-phase flow measurements. Both experimental prototypes and commercial solutions are presented and evaluated. For a non-intrusive, non-invasive and inexpensive meter solution, this review paper predicts a progress for virtual flow meters in the near future. The application of multi-phase flow s meters are expected to further expand in the future as fields are maturing, thus, efficient utilization of existin

Oil dispersion characterization of microorganisms producing biosurfactants

The article is dedicated to studying the ability of crude oil emulsification and displacement by bacteria producing low-molecular-weight biosurfactants. Six hydrocarbon-oxidizing cultures of microorganisms were used in this study: 3 strains of Pseudomonas aeruginosa (T1, T4, D2) and 3 Bacillus cultures: Bacillus licheniformis A3, Bacillus subtilis subsp. subtilis A12, Bacillus subtilis A9 from the collection of the Biotechnology Department of Al-Farabi Kazakh National University. The research findings indicate that cells of P. aeruginosa T1 exhibited maximum emulsifying and displacing properties, with an E24 value of 76.4% and an oil displacement ability of 5.1 cm. Among the three genes responsible for the production of low-molecular-weight biosurfactants, the presence of one gene, rhlA, responsible for the synthesis of rhamnolipid biosurfactants, has been confirmed. It was demonstrated that strains P. aeruginosa T1, P. aeruginosa T4, B. subtilis A9, and B. subtilis subsp. subtilis A12 showed high emulsifying activity, making them potentially effective for application in biotechnological processes aimed at enhancing oil recovery from mature reservoirs and in bioremediation processes.

Recent advances and challenges in gas injection techniques for enhanced oil recovery

Gas injection techniques have emerged as a pivotal method in Enhanced Oil Recovery (EOR), aimed at maximizing the extraction of oil from mature reservoirs. Recent advances in this domain have significantly improved the efficiency and effectiveness of gas injection methods, contributing to increased recovery rates and extended reservoir lifespans. This reviews the latest technological innovations and persistent challenges associated with gas injection techniques in EOR. One of the primary advancements in gas injection is the development of more sophisticated gas compositions, including the use of CO₂, nitrogen, and hydrocarbon gases. These gases have been optimized to improve miscibility with crude oil, thereby enhancing displacement efficiency and increasing oil recovery. Moreover, advancements in monitoring and modeling technologies, such as real-time reservoir simulation and 4D seismic monitoring, have enabled more precise control and assessment of gas injection processes, ensuring optimal gas utilization and minimizing environmental impact. Innovations in smart well technologies and downhole monitoring systems have further enhanced the ability to manage and optimize gas injection operations. These technologies provide continuous data on reservoir conditions, enabling dynamic adjustment of injection parameters to maximize recovery. Additionally, the integration of machine learning and artificial intelligence in EOR processes has facilitated predictive analytics, improving decision-making and operational efficiency. Despite these advancements, several challenges persist. The primary challenge lies in the high operational costs and economic feasibility of gas injection projects, particularly in volatile oil markets. Ensuring the long-term stability and effectiveness of injected gases in heterogeneous reservoirs also presents significant technical hurdles. Moreover, environmental concerns related to the use of CO₂ and other gases necessitate the development of more sustainable and eco-friendly injection methods. Addressing these challenges requires ongoing research and development, as well as collaboration between industry stakeholders, to refine gas injection techniques and mitigate associated risks. The future of gas injection in EOR looks promising, with continued innovation poised to overcome existing barriers and drive more efficient and sustainable oil recovery methods. In conclusion, while recent advances in gas injection techniques for EOR have demonstrated considerable potential, overcoming the economic, technical, and environmental challenges remains crucial for the widespread adoption and success of these methods.

Prospects of an Acid Gas Re-Injection Process into a Mature Reservoir

This study provides insights into the experience gained from the investigation of the dynamic behavior of a mature sour hydrocarbon reservoir modeling under an acid gas re-injection process production strategy. The primary objective was to analyze and evaluate the production behavior of proposed injection zones by assessing various injection scenarios and obtaining oil production over time. To achieve that, a workflow was developed to prioritize potential injection areas, select the optimal wells, determine the optimal operational parameters and optimize a pilot application design based on expected performance. Within this framework, the study encompasses diverse acid gas injection schemes on a pilot scale approach, including acid gas combined with waterflooding. The outcome of this analysis will eventually lead to the identification of the most promising and highest-performing injection scheme, elucidating the optimal range of operating parameters. This optimal combination forms the basis for the economic analysis of the venture and the subsequent detailed design of a full-scale application, where real-world implementation will validate the projected results.

Reservoir Analysis for A Low Recovery Factor Mature Reservoir with A Gas Cap and Large Aquifer: A Proposed Coning Correlation

With the development of reservoir engineering and management, enhanced oil recovery (EOR) techniques are becoming increasingly sophisticated. Generally, the recovery factor (RF) for a conventional reservoir can range from around 10% to 60% after four decades of production, with an average recovery factor of around 35%. While the RF of the NGJ field with high porosity (0.25) and permeability (300 to 600 md) is 6.11% after producing for over 40 years, which is rare in such good reservoir conditions. In this work, some classic techniques and several advanced methods were utilized to investigate the reason behind the low RF for this reservoir.A dynamic reservoir simulation was constructed on the basis of a statics petrophysical model. Based on the preliminary simulation study, it was found that gas coning is a common problem in the reservoir. Therefore, a concept of coning correlation function (CCF) is proposed, and the procedures for developing the CCF are explained. The critical oil rate was estimated using the Addington correlation and modified through the proposed coning correlation that varies as a function of time. The estimated critical rate through CCF is used to control flowing bottom hole pressure (FBHP) in the prediction scenarios.

Laboratory evaluation of novel nano composite gel for water shut-off

When extracting oil and gas from underground reservoirs, fluids such as water, CO2, polymer solutions, and surfactant solutions are often injected to displace the hydrocarbon resources. However, the presence of high-permeable layers, channels, and fractures in the reservoirs can hinder the efficiency of the displacement processes. The displacing fluids tend to channel through these high-permeability features, leaving behind significant amounts of hydrocarbon in low-permeability zones, which remain unswept. Recent developments in nanocomposite hydrogels, such as PPGs, have shown promising results for water shutoff due to their thermal stability and deformability. In this study, a preformed particle gel with nano additive (NC-PPG) was developed through free radical polymerization of AM, AMPS, and nanoclay. Nanoclay nanoparticles were found to act as physical cross-linkers in the polymer network, leading to smaller pore sizes and slightly enhanced thermal stability. The addition of an appropriate amount of nanoclay nanoparticles significantly improved the swelling rate and mechanical properties of NC-PPG. The presented composition also showed good salt tolerance, as evidenced by its compatibility with highly saline formation water and the plugging rate and RRF of 0.25% NC-PPG solution, which were 94.3% and 17.6, respectively, in the sand-pack flowing experiment. These results suggest that NC-PPG has the potential to effectively plug the high permeability zones in mature reservoirs, making it a suitable candidate for water shutoff treatment and enhanced oil recovery (EOR) strategies. The ability of NC-PPG to improve sweep efficiency and control water flow in reservoirs can contribute to more efficient oil production and reservoir management practices. Keywords: enhanced oil recovery; water shut-off; plugging efficiency; preformed particle gel; nanoclay; sweep efficiency.

Guest Editorial: Recycling CO2 for EOR? Why Not?

_ Carbon capture and storage (CCS), with the potential for usage, will be crucial if the world is to prevent global warming. Modeling by the European Commission shows that the EU will need to capture, utilize, or store between 300 and 640 million tonnes of CO2 every year by 2050 if it wants to meet its climate-neutrality goal. It is therefore imperative that all industries, particularly the oil and gas sector, play their part to incentivize the development of new storage while enhancing the use of available producing facilities. Speaking at the second CCUS Forum, held in October in Oslo, Norway, the EU’s energy chief Kadri Simson announced that captured emissions can be either stored or recycled into other industrial processes. Though it wasn’t directly stated by the Estonian politician, enhanced oil recovery (EOR) via CO2 injection should be considered as a viable option to both store and reduce emissions. It is important to emphasize that the amount of stored CO2, as a function of EOR, will be greater than CO2 emissions created from oil extraction. CO2 for EOR in US and Canada Since the 1970s, this has been a routine procedure in many US and Canadian projects with mature reservoirs and is usually instigated after the effect of injected produced water has worn off. It has been achieved without government support. While Norway has been injecting captured CO2 in saline aquifers since the mid-1990s, there has been no attempt, and no plans exist, in Europe to use CO2 for EOR. Why not? Balancing increasing energy demand while lowering greenhouse gas (GHG) emissions is one of the greatest conundrums facing the industry today: global consumption is currently around 100 million B/D. According to IEA’s 2022 World Energy Outlook, there are three scenarios. The APS (announced pledges scenario) assumes fossil-fuel demand will peak in 2024 with 98.1 million B/D. The STEPS (stated policies scenario) projection is peak demand in 2035 at 103.2 million B/D, before going into steady long-term decline (Fig. 1). If the NZE (net zero emissions) scenario comes to pass, oil demand never returns to its 2019 level. It foresees demand falling by 2.5% each year on average between 2021 and 2030, and by just under 6% each year from 2030 to 2050. Adopting EOR technologies and upscaling CCS infrastructure could be the answer to meet energy demand and lower emissions before green energy claims the forecast largest stake of the energy mix by mid-century. Exploiting Hydrocarbon’s Heritage and CCS Globally, there are 30 CCS projects in operation, 11 are under construction, and 153 are in development. Sixty-one new facilities were added to the project pipeline in 2022. The CO2 capture capacity of all CCS facilities has grown to 244 mtpa, a rise of 44% over the past 12 months (Global CCS Institute 2022).

A comparative study of thermal enhanced oil recovery method

The world's petroleum consumption is projected to increase steadily, with most of the oil discovered worldwide remaining unrecovered. Thermal Enhanced Oil Recovery (TEOR) techniques have been found to be effective in increasing the oil recovery from mature reservoirs. This paper compares the two most commonly used TEOR methods, In- Situ Combustion (ISC) and hot fluid injection, in the Sudanese Oil Field, Orion Field. The reservoir properties, operating conditions, production performance, technical challenges, and opportunities, including depth limitations, conventional completion problems, and reservoir heterogeneity, were analyzed for each method. Economic feasibility and environmental impacts are also discussed, including factors such as capital and operating costs, oil recovery rates, and carbon emissions. This study offers valuable insights into the practical aspects of implementing TEOR projects in the Sudanese oil field and can inform decision-making in the oil and gas industry, particularly in reservoir engineering, production optimization, and environmental management.