Secondary Oil Recovery Research Articles

3-D Modelling and Simulation of a Reservoir for Surfactant-Polymer Flooding Using Eclipse Software

Surfactant-polymer flooding is a tertiary enhanced oil recovery method used to recover oil that remained in the reservoir after the primary and secondary oil recovery mechanisms. Predicting the pressure in the reservoir is important for oil production as pressure changes with time. A suitable approach to achieve this task is to derive fluid flow equation based on the reservoir characteristics and solve them numerically which provide the solution to the mathematical fluid flow model (diffusivity equation). In this study, 3-D reservoir was modelled using Eclipse software. The fluid flow equations in a porous media were derived based on the simulated model and the reservoir conditions. Numerical solution using implicit formulation to solve the mathematical fluid flow model (diffusivity equation) was investigated by developing Python codes using Jupyter library to ascertain the pressure distribution for the reservoir and imported into Eclipse simulator. Simulation was carried out using surfactant-polymer and reservoir properties to determine the oil recovery. The results of the study showed that pressure increases with time as oil production continued, and water saturation decreased for the grid-cells of the reservoir. Waterflooding had oil recovery of 38.0% and water-cut of 59.0%, while surfactant flooding had oil recoveries of 42.0%, 46.5%, 49.0% and water-cut of 57.0%, 51.0%, 46.3%. In addition, polymer flooding had oil recoveries of 44.3%, 48.4%, 54.0% and water-cut of 50.0%, 45.0% and 33.0% respectively at different concentrations of 0.3%wt. 0.4%wt. and 0.5%wt.

A comparative study on natural vs. synthesized polymers combined with silica nanoparticles to maximize secondary oil recovery

A comparative study on natural vs. synthesized polymers combined with silica nanoparticles to maximize secondary oil recovery

Advancing Water Deoiling Efficiency in Petroleum Production: A Comprehensive Case Study of Hybrid Flotation Technology Integration

_ The efficient management of increasing water cuts in oil fields is paramount for sustaining profitability and minimizing environmental impact. This article presents a comprehensive case study conducted by Saudi Aramco, focusing on the integration of hybrid flotation technology into a gravity water/oil separator (WOSEP) to enhance deoiling efficiency and reduce operational costs and carbon emissions. The retrofit involved merging enhanced gravity separation with induced gas flotation (IGF) within the same vessel, resulting in significant improvements in deoiling capacity, outlet oil-in-water content reduction, and operational efficiency. Detailed insights into the design, operation, and performance of hybrid flotation systems are provided, offering valuable guidance for similar initiatives in the petroleum industry. Introduction Petroleum production facilities face escalating challenges with increasing water-production rates during crude-oil extraction, particularly in waterflooding operations for secondary oil recovery. This trend not only escalates operational costs but also intensifies environmental concerns, particularly regarding energy consumption and carbon emissions associated with water-handling processes. In response to these challenges, Saudi Aramco embarked on a pioneering initiative to enhance water-deoiling efficiency by integrating hybrid flotation technology into a conventional gravity WOSEP. This case study presents a comprehensive analysis of the design, implementation, and outcomes of this transformative project, offering valuable insights for the broader petroleum industry. Methodology The upgrade process commenced with an assessment of the existing WOSEP system and its operational challenges. Recognizing the impending capacity constraints and escalating oil-in-water content, Saudi Aramco’s engineering team opted for a holistic approach that combined enhanced gravity separation with IGF within the same vessel. The retrofit involved reconfiguring the internal components of the WOSEP to accommodate the hybrid flotation system, including the installation of advanced plate-pack internals for gravity separation and the integration of IGF cells for additional oil removal. Rigorous testing and optimization procedures were conducted to ensure seamless integration and optimal performance of the hybrid system. Gas/Oil Separation Plant Process Description In a typical gas/oil separation plant, the initial phase involves the extraction of crude oil, associated gas, and produced water from wells via a production manifold. These constituents are then directed to a three-phase separator, also known as a high-pressure production trap (HPPT). In the HPPT, free water droplets are separated from the oil through gravity separation, aided by demulsifier injection at the production header. The separated free water is discharged to a WOSEP, typically a gravity separator, for deoiling.

Assessment of the Biogenic Souring in Oil Reservoirs under Secondary and Tertiary Oil Recovery

Assessment of the Biogenic Souring in Oil Reservoirs under Secondary and Tertiary Oil Recovery

A Study on the Effect of New Surfactant Proportions on the Recovery Improvement of Carbonate Reservoir

The strategy of integrating water injection and chemical additives in combining secondary and tertiary oil recovery techniques has been widely investigated in enhancing oil recovery efficiency. Nevertheless, there is a lack of sufficient evidence on the effectiveness of a mixture of cationic and nonionic surfactants combined with water injection techniques in enhancing recovery in the application of carbonate reservoirs. Therefore, it is particularly critical to explore the impact of this combination strategy in enhancing recovery in fractured carbonate reservoirs. The recovery enhancement effect can be assessed by conducting phase behavior experiments and determining interfacial tension and contact angle. Further, the effectiveness of specific surfactant ration solutions in enhancing recovery can be verified by performing drive-off experiments. The results show that low mineralization water and surfactants have a significant synergistic effect in enhancing the recovery efficiency of carbonate reservoirs, with the optimal ratio of cationic to non-ionic surfactants being 2.5:1. The optimized surfactant ratio is able to increase the recovery of carbonate reservoirs by 20% compared to the original recovery rate.

Optimization of oil recovery using heated low salinity water (HLSW) in the horizontal sand pack column during water flooding: radiotracer intervention

Water-flooding is a prevalent technique for secondary oil recovery that is capable to increase oil recovery by up to 45%. Due to its accessibility, affordability, and simplicity, water flooding is the most frequently used secondary oil recovery technique. However, the efficiency of conventional water flooding is limited by capillary forces which holds the residual crude oil in pore structures. Moreover, during water flooding operation, the injected fluid does not penetrate sufficiently due to low permeability or presence of channelling inside the sandstone reservoir. Therefore, in this study, thermal recovery was introduced to 100ppm (0.1g/L) low salinity water (LSW) in order to investigate the percentage of oil recovery during water flooding. A horizontal sand pack column was used for water flooding experiment and temperature and injections rate are the parameters to be optimised with respect to percentage of oil recovery. The column was initially packed with 125micrometer sieved sand to ensure constant homogeneity is achieved. Initially, formation water which comprised with NaCl, CaCl2 and MgSO4 was introduced inside the column together with light oil and was aged overnight. TAPIS oil with viscosity of 0.001382 Pa.s (1.382cP) was used as light-oil in this study. The injection rate was set to 1 mL/min, 2 mL/min, and 3 mL/min respectively whereas, the temperature of the LSW was heated at 50 °C, 70 °C, and 90 °C subsequently. Heated water was supplied continuously throughout the sand pack which was heated using water blanket to retain heat at 70°C (reservoir temperature). In conclusion, 3 mL/min and 70°C were identified as optimum parameters and the oil recovery experiment was proceeded with liquid radiotracer using Technecium-99m (Tc-99m) intervention and resulted with 73% of yield. Nevertheless, the radiotracer intervention only provides the Residence Time Distribution (RTD) model which describe the behaviour of the sand pack during water flooding process.

Analysis of the digital transformation processes of the oil and gas industry

Most modern digital technologies, which are part of the fourth industrial revolution, can be used to improve the efficiency of production processes in the oil and gas industry, in particular, in exploration, planning and optimisation of well construction and maintenance operations, secondary oil and gas recovery methods and enhanced oil and gas recovery. Information flow management can significantly reduce operating costs associated with oil and gas field logistics. Production processes in the oil and gas industry are accompanied by the collection, transmission, processing and storage of significant amounts of information aimed at making and implementing the necessary decisions. In these conditions, big data management technologies are becoming increasingly important. The proliferation of digital technologies, given the peculiarities of oil and gas technologies, requires improvement of measures and means of protection against unauthorised interference with information flow management processes. The use of distributed ledger technology makes data leakage impossible and provides a high level of protection of the information field. The conducted research has identified areas of rational use of simulation software and special applications in the form of automated calculation algorithms in modelling the work processes of oil and gas equipment. Simulation programs do not require a mathematical description of the oil and gas machine's workflow, but are ineffective in the case of a significant number of calculation operations. The use of an automated calculation algorithm is advisable if it is necessary to involve numerous arrays of source data, the analysis of which involves the implementation of numerous calculation procedures. Increasing the share of digital technologies in the educational process involves the widespread introduction of electronic document management, the legalisation of electronic signatures and distance learning methods.

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.

The use of biological catalyst (enzyme) for enhanced oil recovery in Niger Delta

This study is aimed at using bio-catalyst (enzymes) for enhanced oil recovery in Niger Delta. Three different enzymes produced from microbial isolates with code ID; LPE1, LPE2 and AME were use in analyzing enzymes effect on the rock-fluid and fluid-fluid interaction test to simulate the conditions in the reservoir. The tests carried out include; wettability, interfacial tension (IFT) and adhesion test. The results from these tests show that addition of enzymes to rock-fluid interface has the potential of enhancing recovery of crude oil. From the result, the use of enzyme caused an alteration in the wettability of the rock from oil-wet to water-wet with a 33° difference. The selected enzyme LPE1 showed a significant difference in reduction of interfacial tension by a factor of 4, while LPE2 and AME did not show any significant difference. In conclusion, the wettability and IFT tests results were the basis for choosing LPE1 for core flooding process. Enzyme (LPE1) flooding after waterflood was able to give an additional 11.5 % oil recovery. From the results, the percentage recovery is a pointer to the fact that when the primary and secondary oil recovery methods are no longer viable in terms of economics, the Enyme enhanced oil recovery is the best method of mobilizing trapped crude oil in the Secondly, there is no negative effect on the crude oil quality using the enzyme-EOR because the enzymes only increase the rate of the chemical reaction on the rock media without undergoing any permanent chemical change.

Dual-responsive emulsion system: Unraveling pH and host-guest interactions for emulsion stability and enhanced oil recovery

Surfactants facilitate the formation of crude oil emulsions in the petroleum reservoir and reduce oil-water interfacial tension, playing a crucial role in tertiary oil recovery. The host-guest interactions between β-cyclodextrin (β-CD) and surfactant molecules can regulate the solubility and hydrophobic interactions of surfactants, further regulating the interfacial and solution aggregation behaviors of the system. A ternary system composed of β-CD, nonionic surfactant Span 80, and anionic amino acid surfactant was designed to act as emulsion stabilizers and promote emulsion formation. Due to the pH responsiveness of the amino acid surfactant and host-guest interactions between the hydrophobic tail of the surfactant and β-CD, the emulsions exhibit dual responsiveness. The pH and β-CD host-guest interaction dual responsiveness determines the emulsion properties. By adjusting the proportion of β-CD in the ternary system and solution pH, the stability, droplet morphology, and rheological properties of the emulsions are all significantly affected. Interactions among emulsion stabilizers as well as their interfacial behaviors were analyzed using 1H NMR spectroscopy and interfacial tension analysis. This type of emulsion was also tested in core flooding experiments, clearly showing that the response of the emulsions to host-guest interactions can enhance crude oil recovery. Incorporating a higher concentration of β-CD into the system can boost additional secondary oil recovery by approximately 32%, while its pH responsiveness facilitates the demulsification of the system after the flooding. These research findings not only highlight the unique properties of the multi-responsive emulsion but also deepen our understanding of the interactions between surfactants. The ternary stabilizer system developed in this study demonstrates broad potential applications in flooding and oil-water separation.

Synthesis of colloidal silica nanofluid and assessment of its impact on interfacial tension (IFT) and wettability for enhanced oil recovery (EOR)

Ever-increasing global energy demand, from one hand and reduced oil initially in place in oil reservoirs due to production and reduced natural reservoir production capacity, on the other hand, has encouraged researchers to investigate different methods to improve and increase enhanced oil recovery (EOR) from oil reservoirs. One method is to employ nanotechnology in injected water, where nanoparticles could affect interfacial tension (IFT) between water and oil and wettability through properties, including high specific surface area and nanoparticle size. However, a major challenge in using nanoparticles in injected water is the instability of these particles in water, which ultimately reduces the efficiency of EOR. These particles cannot be stabilized through conventional methods at a large scale. In this study, stabilized silica nanoparticles were synthesized in the water phase using sodium silicate and sol–gel processes. The stability of this nanofluid was studied in seawater, and then its effect on IFT and changing wettability was examined. According to the results, seawater containing 40 times diluted nanofluid could obtain 41% reduced IFT and 40% alteration in wettability of carbonate core becoming more water-wet and ultimately 13.7% improved final oil recovery in secondary oil recovery and 8.3% improved final oil recovery in third EOR.

Modeling and semi-analytical solution for immiscible and miscible fingers formation during enhanced oil recovery

ABSTRACT The fingering phenomenon arises during the secondary and tertiary oil recovery processes when injected fluid (water, gases, nano/biomaterials, or polymer particles) shoots through a porous medium at a relative speed. Oil recovery is influenced by various factors including the fluid type, capillary pressure, permeability, and porous material structure. All these elements play crucial roles in determining the success and efficiency of the oil recovery process. Many scientists have debated the fingering phenomenon from different perspectives. Here, we developed mathematical models with and without considering mass flow rates of oil and water for an inclined oil layer flowing through a homogenous porous medium to generate immiscible fingers. Furthermore, a mathematical model of miscible viscous finger formation with carbonated water injection (flooding) during the enhanced oil recovery process (EOR) has been analyzed in this paper. To solve each of these mathematical models, we used the recently developed approach known as the Method of Directly Defining the inverse Mapping (MDDiM). We found approximate solutions to the nonlinear partial differential equations (PDEs), which describe each modeling of the fingering phenomenon in a homogeneous porous medium by incorporating gravitational effects for several types of flooding and discussed the effects of the saturation rate.

Study of imbibition phenomenon in homogeneous porous medium model for oil recovery with temporal-fractional approach

In this article, the phenomenon of countercurrent imbibition in a specific displacement method occurs within a dipping homogeneous porous medium. This phenomenon plays a vital role in the process of oil recovery, which motivates our analysis. To overcome the difficulties associated with the nonlinear partial differential equation governing the countercurrent imbibition phenomenon, we have been using two distinct methods: the natural transform decomposition method and the variational iteration transform method with their convergence analysis for solutions. These techniques give different perspectives and enable us to obtain approximate solutions. Notably, both the proposed methods demonstrate the potential for substantial production of oil during the secondary oil recovery process in the petroleum industry. The obtained results by the proposed methods show the efficiency in optimizing the oil recovery rate.

Corrosion Analysis and Prevention of Tubing Nipples in Four Wells

A high-temperature and high-pressure gas field in an oil field requires the use of super 13 chromium material due to corrosive environments. In the recent production process, there have been four consecutive cases of corrosion, fracture, and perforation of tubing nipples, which have brought enormous economic losses to the oilfield. This article analyzes the failure causes of these four tubing nipples and proposes preventive measures. In this paper, the macroscopic morphology, chemical composition, mechanical properties, metallography, and microscopic morphology of four failed tubing nipples have been analyzed. Combined with the field service conditions and string structure of the tubing nipples, it is believed that the failure of the tubing nipples is mainly due to the connection of carbon steel and stainless steel materials, forming a typical galvanic corrosion galvanic cell. The geometric and environmental factors of the materials exacerbate this corrosion. Eventually, severe galvanic corrosion occurred on the inner surface of the tubing nipple, resulting in severe wall thinning or partial perforation, and four tubing nipples failed. The failed tubing nipples in Wells A, B, and C have erosion marks, which are caused by the action of high pressure and high flow rate fluids in the well; The inner surface of the tubing nipple in Well D is rusty yellow, mainly due to the corrosion of its inner wall caused by the acid fracturing fluid injected earlier. At the same time, the string structure of four wells shows that the tubing nipple is located at the variable diameter node of the string. When the fluid in the well flows from the large hole into the smaller hole, the fluid in the well will change there, and its flow rate and pressure will also increase, further exacerbating the erosion in this area. With the development of deep wells containing carbon dioxide in oil fields and the application of carbon dioxide injection secondary oil recovery technology, the use of 13Cr martensitic stainless steel is also increasing. In order to avoid the occurrence of similar accidents that will bring huge economic losses to the oil field, it is recommended that the material of the pipe string (including accessories) of such wells be confirmed using a portable direct reading spectrometer before entering the well.

Review of Offshore Chemical Flooding Field Applications and Key Lessons Learned

Summary This paper presents an overview of both current advancements and field applications of offshore chemical flooding technologies. Along with offshore oilfield development strategies that require the maximization of oil production in a short development cycle, chemical flooding can become a potential avenue to accelerate oil production in secondary oil recovery mode. This makes it different from onshore chemical flooding processes that mostly focus on enhanced oil recovery in mature or maturing reservoirs. The advancements in offshore chemical flooding field applications are reviewed and analyzed. By summarizing offshore application cases, the presented analysis also assesses the chemical formulations applied or studied and injection/production facilities required in offshore environments. The main technical challenges are also discussed for scaling up the applications on offshore platforms or floating production storage and offloading (FPSO) systems. The chemical flooding technologies reviewed include polymer flooding, surfactant-polymer (SP) flooding, and alkaline-surfactant-polymer (ASP) flooding. By assessing the technology readiness level of these technologies, this study presents their perspectives and practical relevance for offshore chemical flooding applications. It has been long realized that chemical flooding, especially polymer flooding, can improve oil recovery in offshore oil fields. The applications in Bohai Bay (China), Dalia (Angola), and Captain (North Sea) provide the know-how workflows for offshore polymer flooding from laboratory to full-field applications. It is feasible to implement offshore polymer injection either on a platform or in an FPSO system. It is recommended to implement polymer flooding at an early stage of reservoir development to maximize the investment in offshore facilities. By tuning the chemistry of polymer products, they can present very good compatibility with seawaters. Therefore, choosing a proper polymer is no longer a big issue for offshore polymer flooding. There are also some interesting findings reported on the development of novel surfactant chemistries for offshore applications. The outcome from a number of small-scale trials, including the single-well chemical tracer tests on surfactant, alkaline-surfactant (AS), and SP in offshore Malaysia, Abu Dhabi, Qatar, and South China Sea, provided valuable insights for the feasibility of chemical flooding in offshore environments. However, the technology readiness levels of surfactant-based chemical flooding processes are still low, partially due to their complex interactions with subsurface fluids and the lack of interest in producing residual oil from matured offshore reservoirs. Based on the lessons learned from offshore applications, it can be concluded that several major challenges still need to be overcome in terms of large well spacing, reservoir voidage, produced fluid treatment, and high operational expense to successfully scale up surfactant-based chemical flooding processes for offshore applications. Key Terms and Phrases offshore chemical flooding; polymer flooding; surfactant-based chemical flooding; offshore application cases; lessons learned

Experimental investigations of enhanced oil recovery using porous SiO2 aerogel nanosuspensions with emulsifying effects

To address problematic low reservoir recovery rates, a new porous SiO2 aerogel nanosuspension (NS) with emulsifying effects was developed, and its microstructure and flow characteristics were analysed with physical property and rheological tests. Moreover, macro- and microlevel flooding experiments were carried out to explore the mechanism for enhanced oil recovery (EOR). The results showed that the final recovery rates were 58.23% and 60.68% with 0.8 PV NS and NS foam slug, respectively, which were 10.03% and 13.62% higher than those of secondary oil recovery. Oil-water emulsions with different emulsification degrees were generated after sufficiently oscillating the NS and condensate oil mixture. NS flooding exhibited evident nonpiston characteristics in the early stage, and particles were transferred from water into the oil phase, which resulted in differential emulsification of the oil. The oil flow status was altered from flakes to droplets due to emulsification and the changing passage cross-section caused by particle accumulation. With NS foam flooding, the oil was first replaced by coherent large bubbles and then migrated under the effects of multiple systems. A particle circumfluence layer around the foam absorbed oil to generate an adhesive oil film.

Evaluation of rock-fluid interaction in a carbonate reservoir: Backflow test and reactive transport simulations

Water injection is one of the most used secondary oil recovery methods. However, when injected into a carbonate reservoir, it disturbs the equilibrium between the porous rock and the formation water, altering the geochemical system. The aim of this work is to evaluate the rock-fluid chemical interaction associated with seawater injection into a carbonate reservoir, based on field flow tests and flow simulations using COORES™ and ARXIM. Though previous studies were carried out under laboratory conditions, in this work, for the first time, rock-fluid interaction was observed and quantified during a field test in a high-temperature and high-pressure reservoir. Chemical analysis of produced water during the flow test showed that calcium and alkalis concentrations were higher than those calculated by the simple mixture of injected and formation waters, confirming the existence of chemical reactions under reservoir conditions. Reactive transport simulations were used to determine kinetic parameters related to calcite dissolution and dolomite precipitation in the reservoir. The results of this study enhance the understating of chemical interactions between injected fluids and carbonate reservoirs and provide data for more reliable simulations. These could lead to more accurate predictions regarding produced water composition and pH, anticipating the likelihood of reservoir collapse and scaling issues.

Tertiary oil recovery and CO2 storage from laboratory injection of CO2 or water-saturated CO2 into a sandstone core

Water-saturated CO2 (wsCO2) injection can improve CO2 sweep efficiency during CO2 enhanced oil recovery (CO2-EOR). Previous studies investigated wsCO2 injection only as a secondary oil recovery method, CO2 injection begins at connate water saturation - the rest bring oil. However, CO2 injection usually follows water injection, in which case the injection is referred to as a tertiary recovery method.In this study, we inject pure CO2 and wsCO2 into a heterogeneous, Hutton Sandstone core that is subjected to 116 °C, 15.5 MPa, represents immiscible conditions. The core is saturated with brine followed by injecting 40 pore volumes (PVs) of oil, reaching the irreducible water saturation (Swi) – a state analogous to connate water. Afterwards, 40 PVs of brine are injected into the core, analogous to secondary oil recovery, thereby reaching residual oil saturation after water injection (Sorw). Subsequently, 40 PVs of pure CO2 or wsCO2 are injected, analogous to tertiary oil recovery.The oil and water are injected with the core horizontal (that is, with its ends facing sideways). However, to receive the CO2 or wsCO2, a given core is held in one of two orientations: vertical with CO2 or wsCO2 injected at the top, or horizontal. Pressure difference across the core, oil produced, and CO2 stored are recorded. For both vertical and horizontal orientation, pressure difference during wsCO2 injection is found to exhibit local maxima 2.2 to 4.3 times the normal level, indicating a reduction in wsCO2 mobility and therefor reduced relative permeability to CO2. Vertical orientation is found to yield similar oil production and CO2 storage for pure CO2 and wsCO2 injection, which is consistent with the expectation of 100% sweep efficiency. However, for horizontal orientation, the ultimate oil recovery where wsCO2 is injected is found to be 3.2% PVs higher than that where pure CO2 is injected, and CO2 storage where wsCO2 is injected is found to be 10% PVs higher than that where pure CO2 is injected. These results for horizontal orientation are attributed to low CO2 sweep efficiency, which is due to the gravity effect (which causes the CO2 to congregate at the top of the rock, thereby bypassing a large quantity of oil at the bottom of the rock). WsCO2 injection is superior to pure CO2 injection in terms of oil recovery and CO2 storage. However, wsCO2 has more profound effect on CO2 storage compared to oil recovery because the injected wsCO2 enhances the production of both water and oil, leaving more pore space for CO2 storage.

Application of thermotolerant petroleum microbes at reservoir conditions for enhanced oil recovery

Primary oil recovery is the first stage of hydrocarbon production in which a reservoir uses its natural energy to force hydrocarbon to its wellbore. Secondary oil recovery comes to play when hydrocarbons can no longer be further produced by natural means. The purpose of secondary recovery is to maintain reservoir pressure so as to displace hydrocarbons toward the wellbore. Both primary and secondary recovery processes cannot displace more than 50% of the available hydrocarbons in a reservoir. The remaining hydrocarbons are further recovered through Tertiary/Enhanced Oil Recovery techniques. According to literature, microbial enhanced oil recovery has been identified as a tertiary method used to improve the efficiency of hydrocarbon production from reservoirs. Microbial enhanced oil recovery is a feasible reservoir technology, which has not been widely used in the oil and gas industry owing to the attainment of the requisite reservoir conditions such as temperature within which microbes can thrive. Literature has shown that thermotolerant microbes can withstand optimum temperatures of 50–90°C, while deep and ultra-deep hydrocarbon reservoir temperatures are often above 100°C. This study identifies some isolated thermotolerant microbes from a sandstone reservoir that can withstand temperatures as high as 110°C via conventional methods and molecular analysis. The identified thermotolerant petroleum microbes: Bacillus amyloliquefaciens ( A) and Bacillus nealsonii (B) were used to enhance oil recovery from a reservoir. The results showed that the microbial species A and B at a confined pressure of 3.0 MPa and temperature of 27°C, gave 46.4% and 48.6% oil recoveries, respectively, which is comparably higher than the value (26.9%) obtained for the water flooded samples. At temperatures of 80, 90, 100, 110 and 120°C, the oil recovery results show that the recovery factor (55.2–64.1%) of species B were higher compared to the range (46.7–57.5%) recorded for species A. At the onset of the core flooding experiments, there was an initial increment in oil recovery factor as the temperature increased from 80 to 110°C, whereas, it remained constant within 110–120°C. This trend coincides with the drop in the thermal resistance exhibited by the microbes when exposed to such conditions. The cumulative oil production from the commercial Eclipse simulation closely matched those of the experiment results, whereas, the slight difference can be attributed to the adjustment of the simulation input parameters. The experimental results show that species B can be used to enhance oil recovery at reservoir temperature conditions above 100°C.

Predictive modeling of oil and water saturation during secondary recovery with supervised learning

In the petroleum reservoir, the secondary oil recovery (SOR) process is employed by injecting water into wells to enhance the moment of oil toward the production wells. The SOR process gives rise to the instability (fingering) phenomena due to the injecting force and the difference in the wettability and viscosity of the oil and water at the common interface. Since the late 1800s, mathematical models of petroleum reservoirs have been extensively used in the oil and gas industry. In this paper, we investigated the saturation of two immiscible fluid (oil and water) flows through homogeneous porous media during the SOR process by solving the modeled partial differential equation using the supervised machine learning algorithm based on feedforward back-propagated neural networks (FFBNNs) and Levenberg–Marquardt (LM) optimization algorithm. The designed scientific computing technique (FFBNN-LMA) is further employed to study the detailed sensitivity analysis of the approximate solutions. Performance measures like average absolute deviations, Theils' inequality measure, regression, and Nash–Sutcliffe model efficiency coefficient.