Increase Oil Recovery Research Articles

Heavy oil recovery using gas injection methods and its challenges and opportunities

The relevance of enhanced oil recovery (EOR) and its development are always important considerations when it comes to the approaches used to improve heavy crude oil recovery. As a direct consequence of this, there is a growing demand for the discovery of unconventional resources such as bitumen, shale, and heavy oil. With the diminishing availability of conventional crude oil stocks, it is necessary to make efficient and fruitful use of heavy oil resources. Heavy oil recovery poses challenges due to the high viscosity and low mobility of the oil, making traditional recovery methods less effective. Gas injection has emerged as a promising technique to enhance heavy oil recovery, where different gas injection methods are evaluated to improve the oil displacement efficiency. Several gas injection methods have been employed in heavy oil recovery, including natural gas injection, carbon dioxide (CO2) injection, and steam-assisted gravity drainage (SAGD). Each method has its benefits and difficulties. Natural gas injection is relatively simple and cost-effective, but it may face limitations in terms of the amount of gas available and the gas-oil miscibility. CO2 injection has shown promising results due to its miscibility with heavy oil, which leads to improved oil recovery through swelling and viscosity reduction. The benefits of gas injection methods include increased oil recovery, reduced environmental impact, and potentially lower operational costs. These methods can also enhance the recovery of stranded heavy oil reserves, thereby contributing to global energy security. However, challenges associated with gas injection methods include high viscosity and low mobility, reservoir heterogeneity, the potential for gas channeling, and high capital and operational costs. Despite the challenges, gas injection methods offer significant opportunities for heavy oil recovery. Overcoming these challenges requires advanced reservoir characterization, optimized well design, efficient gas injection strategies. Technological advancements, such as advanced reservoir characterization techniques, improved well design, and optimized gas injection strategies, can help overcome these challenges and enhance heavy oil recovery using gas injection methods. The gas injection methods that are used to recover heavy crude oil have been evaluated in the research along with their benefits and the difficulties that can arise while employing the gas injection methods. This paper focuses on the challenges and opportunities of gas injection methods for heavy oil recovery.

CO2 Viscosification for Mobility Alteration in Improved Oil Recovery and CO2 Sequestration

Recently there have been significant advances in the viscosification of CO2 using a low concentration of oligomers. The new engineered molecules do not adsorb onto rock. This paper studies the effects of different CO2-enhanced viscosity levels in subsurface aquifers and reservoirs. The study was conducted using numerical modeling and simulation tools in homogeneous, heterogenous, fractured, and unfractured media. The viscosity enhancement of CO2 varied from 2- to 20-fold. The simulations included homogeneous, layered, and fractured domains in 2D and in 3D for improved oil recovery. The results showed that in unfractured, homogenous, and layered media, a 10-fold viscosity increase leads to significant increases in oil recovery. In a fractured medium with a highly connected fracture network, a 20-fold viscosity enhancement may have a considerable effect in delaying breakthrough and improving oil recovery. Simulations were performed in a compositional three-phase flow based on higher-order discretization. The algorithm included Fickian diffusion, which may add to oil recovery performance when there is a sufficient surface area between the CO2-rich phase and the oil phase. In CO2 sequestration, an increase in the viscosity of CO2 and consequent mobility control promotes CO2 dissolution in the aqueous phase. Due to the increase in the density of the aqueous phase from CO2 dissolution, the CO2 is carried away from the cap rock to the bottom of the formation. This work is of particular importance in improved oil recovery and in safe CO2 sequestration due to solubility trapping and mitigation of pressure increase. The higher-order numerical scheme used in this simulation guarantees a level of accuracy not obtained in traditional simulators.

Optimization of Polymer Flooding Using Genetic Algorithm

One of the methods to achieve optimal conditions in increasing oil recovery through injecting polymers is by optimizing the parameters that influence the success of injecting polymers to provide information and be considered when determining new schemes for implementation in the future. Optimization to obtain the optimum value of the recovery factor and the best value of the parameters PV, injection rate, injection time, injection pressure, adsorption, residual resistance factor (RRF), and inaccessible pore volume (IPV) using a genetic algorithm with three training ratios and testing 70: 30, 80: 20 and 90: 10 using 1000 datasets. The best value obtained for each parameter is at a ratio of 90: 10, which is the best model with the lowest reference error value with RSME of 0.241104 and MAPE value of 19.1964 classified as good prediction with the value of each adsorption parameter 0.1737 (g/l), injection rate 703 (bpd), injection pressure 1816, IPV 0.2524, RRF 4.8319 and finally the optimum value for recovery factor is 53.9557.

Actor-critic reinforcement learning leads decision-making in energy systems optimization—steam injection optimization

Steam injection is a popular technique to enhance oil recovery in mature oil fields. However, the conventional approach of using a constant steam rate over an extended period can lead to sub-optimal performance due to the complex nature of the problem and reservoir heterogeneity. To address this issue, the Markov decision process can be employed to formulate the problem for reinforcement learning (RL) applications. The RL agent is trained to optimize the steam injection rate by interacting with a reservoir simulation model and receives rewards for each action. The agent’s policy and value functions are updated through continuous interaction with the environment until convergence is achieved, leading to a more efficient steam injection strategy for enhancing oil recovery. In this study, an actor-critic RL architecture was employed to train the agent to find the optimal strategy (i.e., policy). The environment was represented by a reservoir simulation model, and the agent’s actions were based on the observed state. The policy function gave a probability distribution of the actions that the agent could take, while the value function determined the expected yield for an agent starting from a given state. The agent interacted with the environment for several episodes until convergence was achieved. The improvement in net present value (NPV) achieved by the agent was a significant indication of the effectiveness of the RL-based approach. The NPV reflects the economic benefits of the optimized steam injection strategy. The agent was able to achieve this improvement by finding the optimal policies. One of the key advantages of the optimal policy was the decrease in total field heat losses. This is a critical factor in the efficiency of the steam injection process. Heat loss can reduce the efficiency of the process and lead to lower oil recovery rates. By minimizing heat loss, the agent was able to optimize the steam injection process and increase oil recovery rates. The optimal policy had four regions characterized by slight changes in a stable injection rate to increase the average reservoir pressure, increasing the injection rate to a maximum value, steeply decreasing the injection rate, and slightly changing the injection rate to maintain the average reservoir temperature. These regions reflect the different phases of the steam injection process and demonstrate the complexity of the problem. Overall, the results of this study demonstrate the effectiveness of RL in optimizing steam injection in mature oil fields. The use of RL can help address the complexity of the problem and improve the efficiency of the oil recovery process. This study provides a framework for future research in this area and highlights the potential of RL for addressing other complex problems in the energy industry.

Dynamic Sweep Experiments on a Heterogeneous Phase Composite System Based on Branched-Preformed Particle Gel in High Water-Cut Reservoirs after Polymer Flooding

Heterogeneous phase composite (HPC) flooding technology that is based on branched-preformed particle gel (B-PPG) is an important technology for enhancing oil recovery in high water-cut reservoirs. In this paper, we conducted a series of visualization experiments under the condition of developed high-permeability channels after polymer flooding, with respect to well pattern densification and adjustment, and HPC flooding and its synergistic regulation. The experiments show that for polymer-flooded reservoirs, HPC flooding can significantly reduce the water cut and increase oil recovery, but that the injected HPC system mainly advances along the high-permeability channel with limited sweep expansion. Furthermore, well pattern densification and adjustment can divert the original mainstream direction, which has a positive effect on HPC flooding, and can effectively expand the sweeping range under the synergistic effect of residual polymers. Due to the synergistic effect of multiple chemical agents in the HPC system, after well pattern densification and adjustment, the production time for HPC flooding with the water cut lower than 95% was significantly prolonged. In addition, conversion schemes, in which the original production well is converted into the injection well, are better than non-conversion schemes in terms of expanding sweep efficiency and enhancing oil recovery. Therefore, for well groups with obvious high-water-consuming channels after polymer flooding, the implementation of HPC flooding can be combined with well pattern conversion and intensification in order to further improve oil displacement.

Temperature effects on alkaline flooding for heavy oil recovery in heterogeneous and homogeneous porous media: Pore scale evaluation

ABSTRACT Among the various methods of chemical enhanced oil recovery, alkaline flooding has a better potential to increase oil recovery in reservoirs containing acidic crude oil. This research investigated the effect of temperature on alkaline flooding (sodium hydroxide and sodium carbonate) on the enhanced oil recovery in two homogeneous and heterogeneous micromodels at temperatures of 25, 50, 75 and 90°C. Evaluation of the effect of temperature on oil recovery in micromodel experiments showed that sodium hydroxide increased the pH of the environment at low temperatures (25 and 50°C) due to its higher alkalinity and, this issue shows greater ability to emulsification and reduce interfacial tension, which ultimately increases oil recovery. In contrast, high temperatures (75 and 90°C) have a negative effect on oil recovery, so that oil recovery is greatly reduced. The high temperature causes the increased rate of the reaction between the crude oil sample and alkaline solutions, which in turn reduces the effect of IFT and, weakening the uniform enrichment of in situ surfactants cause problem for making water droplets within the oil phase. Finally, the increase in temperature to 90°C showed that the oil recovery rate was reduced to about 42% in the homogeneous model and 51% in the heterogeneous model. The achievements of this research lead to a better understanding of the effect of temperature parameter on various mechanisms of increasing heavy oil recovery such as reducing the IFT of oil/injectable solutions and producing W/O emulsion during alkaline flooding under different wetting conditions. Studies show that injecting alkaline by creating a W/O emulsion prolongs the breakthrough time and changes the finger pattern created during water flooding in a way that reduces the amount of oil bypassed, so that a significant increase is observed in the oil recovery factor.

Optimization of operational strategies for rich gas enhanced oil recovery based on a pilot test in the Bakken tight oil reservoir

Horizontal well drilling and multistage hydraulic fracturing have been demonstrated as effective approaches for stimulating oil production in the Bakken tight oil reservoir. However, after multiple years of production, primary oil recovery in the Bakken is generally less than 10% of the estimated original oil in place. Gas huff ‘n’ puff (HnP) has been tested in the Bakken Formation as an enhanced oil recovery (EOR) method; however, most field pilot test results showed no significant incremental oil production. One of the factors affecting HnP EOR performance is premature gas breakthrough, which is one of the most critical issues observed in the field because of the presence of interwell fractures. Consequently, injected gas rapidly reaches adjacent production wells without contacting reservoir rock and increasing oil recovery. Proper conformance control is therefore needed to avoid early gas breakthrough and improve EOR performance. In this study, a rich gas EOR pilot in the Bakken was carefully analyzed to collect the essential reservoir and operational data. A simulation model with 16 wells was then developed to reproduce the production history and predict the EOR performance with and without conformance control. EOR operational strategies, including single- and multiple-well HnP, with different gas injection constraints were investigated. The simulation results of single-well HnP without conformance control showed that a rich gas injection rate of at least 10 MMscfd was needed to yield meaningful incremental oil production. The strategy of conformance control via water injection could significantly improve oil production in the HnP well, but injecting an excessive amount of water also leads to water breakthrough and loss of oil production in the offset wells. By analyzing the production performance of the wells individually, the arrangement of wells was optimized for multiple-well HnP EOR. The multiwell results showed that rich gas EOR could improve oil production up to 7.4% by employing conformance control strategies. Furthermore, replacing rich gas with propane as the injection gas could result in 14% of incremental oil production.

ABOUT THE POSSIBILITY OF IMPLEMENTING WATER-ALTERNATING-GAS INJECTION USING PUMP-JET SYSTEMS AT THE ARYSTAN FIELD

At the moment, in the Caspian oil and gas region, many fields are in the final stage of development according to the basic version (flooding). According to it, the final oil recovery coefficient often does not reach the design values. Therefore, for such fields, it is necessary to consider the possibility of using various tertiary methods to increase oil recovery.

A new technique to increase enhanced oil recovery rate in low-temperature layers

The paper introduces experimental research results, on the basis of which a method for enhancing oil recovery of low-temperature formations was developed, including thermal gas and chemical effects. The initiation of the oxidation process by injection of chemical agents contributes to its uniform distribution in the bottomhole zone, the increase in the initiation zone and the leveling of the front of the advancement of the exothermic reaction zone. The thermal and oil-displacing rims formed as a result of the oxidation process contribute to a significant increase in oil recovery. When applying the proposed method of developing an oil deposit, corrosion of equipment decreases, the amount of carbon dioxide formed increases, produced water becomes alkaline, and the oil displacement coefficient increases significantly. The prospect of the proposed method is associated with the use of in-situ energy potential, low-value chemical reagents, as well as the high availability of the main agent - air. The technology is easy in implementation, cost-effective and does not require special well design. Keywords: pyrite; exothermic reaction; sodium hydroxide solution; ammonium carbonate solution; oxidation; enhanced oil recovery; stimulation methods; oil displacement bank.

Different Development Scenarios to Increase the Production Rates for Fauqi Oil Field Southeastern Iraq

The Fauqi field is located about 50Km North-East Amara town in Missan providence in Iraq. Fauqi field has 1,640 MMbbl STOIIP, which lies partly in Iran. Oil is produced from both Mishrif and Asmari zones. Geologically, the Fauqi anticline straddles the Iraqi/Iranian border and is most probably segmented by several faults. There are several reasons leading to drilling horizontal wells rather than vertical wells. The most important parameter is increasing oil recovery, particularly from thin or tight reservoir permeability. The Fauqi oil field is regarded as a giant field with approximately more than 1 billion barrels of proven reserves, but it has recently experienced low production rate problems in many of its existing wells. This study will concentrate on analyzing the Asmari reservoir as the main production reservoir in this field for an oil gravity of 18 API. While, well (FQ-8) has been selected as a pilot well to verify different development scenarios that could be taken to increase the reservoir production rate. The results show that both drilling lateral sections and performing the stimulation process in some reservoir intervals yield positive results to increase good productivity with different percentages. The lateral sections occasionally gave higher productivity than the stimulation process by (2-3) times.

A mechanistic study of low salinity water-based nanoparticle-polymer complex fluid for improved oil recovery in sandstone reservoirs

Low salinity water flooding has gained tremendous attention in these days due to its cost-effectiveness and environment-friendly nature. Fine tuning of physico-chemical properties of low saline water by addition of suitable chemicals and nanoparticle (NP) can increase the oil recovery significantly because of synergistic effects. In this study, an attempt has been made to explore the benefit of adding nanoparticle and polymer into low salinity water (LSW) for increased oil recovery. Two complex chemical slugs were prepared with formation water (FW) and LSW as base fluids consisting of different concentrations of polymer and NP. The target viscosity for maximum sweep efficiency was estimated through the total minimum relative mobility concept. The rheological studies of the complex chemical slugs revealed that the addition of NP into polymer solution increased the viscosity significantly because of formation of macromolecular structure. It has been observed that a lower concentration of polymer is required to reach the target viscosity in LSW than FW. The benefits of low salinity effects over high saline formation water are evidenced by the reduction of interfacial tension (IFT), which is further reduced by addition of NP. A low IFT is always desirable for enhanced oil recovery. Contact angle showed a decreasing trend with FW, LSW and Nano fluid solutions respectively but presence of polymer in the slugs shows reverse effect on contact angle. LSW showed higher recovery as compared to FW in secondary recovery stage due to different reported mechanisms. Injection of LSW based complex fluid showed incremental recovery of 13.3 % of OOIP as compared to LSW and 22.0 % of OOIP as compared to conventional FW flooding in secondary stage. Synergistic effect of NP and polymer to form a complex macromolecular structure through hydrogen bonding and low salinity effect led to the improved oil recovery.”

Impact of surface-modified silica nanoparticle and surfactant on the stability and rheology of oil-in-water Pickering and surfactant-stabilized emulsions under high-pressure and high-temperature

Emulsions have a wide range of applications, and with the advancement in the use of nanoparticles to form stable Pickering emulsions, it is important to understand their rheological properties to infer their stability under high-pressure and high-temperature (HPHT) compared to the emulsion formed using conventional surfactants. In oil and gas production strategies, oil often forms an emulsion with brine either within reservoirs or at surface facilities in the presence of natural or artificial surfactants. Nanoparticles are also being explored to increase oil recovery from matured reservoirs. In various instances, stable emulsions are either formed in-situ (within the reservoir) or at surface facilities or injected into the reservoir to mobilize the trapped oil. It is also essential to understand their rheology for efficient oilfield application. This study investigates the impact of surface-modified silica nanoparticles (Ludox CL), NaCl salt, and surfactant on the stability of oil-in-water Pickering and surfactant-stabilized emulsions under high-pressure (0.1–10) MPa and high-temperature (303–363) K conditions. The viscosity of emulsion samples was measured at varying shear rates (0.1–1000) s−1. The viscoelastic behavior (G′, G″, η*, and δ) of the Pickering emulsion and surfactant-stabilized emulsion were also measured. The stability of the emulsions was measured in terms of changes in emulsion viscosity and droplet diameter. Both emulsions showed non-Newtonian shear thinning behavior and an increase in droplet diameter under HPHT conditions. However, the surfactant-stabilized emulsion exhibits a greater degree of change in emulsion viscosity and droplet diameter than the Pickering emulsion. It indicates that the Pickering emulsion showed better stability than the surfactant-stabilized emulsion under HPHT conditions. Hence, Pickering emulsions are an incredibly promising tool that might be employed in HPHT applications, especially for enhanced oil recovery applications, due to their better rheological stability.

Nuclear magnetic resonance study of CO2 flooding in tight oil reservoirs: Effects of matrix permeability and fracture

The implementation of CO2 enhanced oil recovery (EOR) projects for tight reservoir development has the dual effects of economic benefits and carbon storage. Matrix permeability and fractures in tight reservoirs have a significant impact on the performance of CO2 flooding. In this study, CO2 flooding experiments were carried out using natural tight cores with different matrix permeabilities and artificial fracture conditions. The pore size range variation of oil-producing pores and the distribution of residual oil were explored by using nuclear magnetic resonance (NMR) technique. The results indicated that the increase of matrix permeability was beneficial to increase oil recovery, but it also reduced the displacement pressure and thus weaken the ability of CO2 diffusion into small pores. Specifically, with the matrix permeability increased from 0.1 to 0.2 mD to 0.4–0.5 mD and 0.8–0.9 mD, the oil recovery of fracture-free tight cores increased from 15.59% to 19.78% and 24.73%, and the pore size range of oil-producing pores decreased obviously. Conversely, the fractures aggravate the channeling flow of CO2 and reduce the swept area but facilitates the recovery of crude oil from smaller pores. In tight cores of 0.8–0.9 mD with single fracture and multiple fractures, the oil recovery decreased to 21.3% and 20.12%, but the oil-producing pore size range expands from 0.2-6 μm to 0.05–6 μm and 0.04–6 μm. The NMR imaging results showed that the residual oil content gradually increased from the injection end to the production end, and the distribution of the residual oil in the core with high permeability and non-fracture was more even.

Salt Transport in Crosslinked Hydrogel Membranes Containing Zwitterionic Sulfobetaine Methacrylate and Hydrophobic Phenyl Acrylate.

Produced water is a by-product of industrial operations, such as hydraulic fracturing for increased oil recovery, that causes environmental issues since it includes different metal ions (e.g., Li+, K+, Ni2+, Mg2+, etc.) that need to be extracted or collected before disposal. To remove these substances using either selective transport behavior or absorption-swing processes employing membrane-bound ligands, membrane separation procedures are promising unit operations. This study investigates the transport of a series of salts in crosslinked polymer membranes synthesized using a hydrophobic monomer (phenyl acrylate, PA), a zwitterionic hydrophilic monomer (sulfobetaine methacrylate, SBMA), and a crosslinker (methylenebisacrylamide, MBAA). Membranes are characterized according to their thermomechanical properties, where an increased SBMA content leads to decreased water uptake due to structural differences within the films and to more ionic interactions between the ammonium and sulfonate moieties, resulting in a decreased water volume fraction, and Young's modulus increases with increasing MBAA or PA content. Permeabilities, solubilities, and diffusivities of membranes to LiCl, NaCl, KCl, CaCl2, MgCl2, and NiCl2 are determined by diffusion cell experiments, sorption-desorption experiments, and the solution-diffusion relationship, respectively. Permeability to these metal ions generally decreases with an increasing SBMA content or MBAA content due to the corresponding decreasing water volume fraction, and the permeabilities are in the order of K+ > Na+ > Li+ > Ni2+ > Ca2+ > Mg2+ presumably due to the differences in the hydration diameter.

Performance of bleaching clays in dechlorophyllisation of microalgal oil: A comparative study

While clay has been extensively studied for its ability to remove chlorophyll from vegetable oil, its effects and suitability on microalgae oil have received far less attention. In this study, three different clay types are evaluated and compared for their ability to dechlorophyllise microalgae oil. The clays involved are kaolinite, Fuller’s earth and bentonite clay which are activated by acid treatment. Bentonite clay is found to remove chlorophyll effectively (76.04%) than kaolinite and Fuller’s earth due to the presence of porous materials that facilitate adsorption. Additionally, the conditions of high temperature (79.69%) and ultrasound treatment (84.24%) demonstrate satisfactory chlorophyll removal efficiency. Another promising finding is that chlorophyll can be adsorbed on the clays without affecting the lipid composition in the microalgae extract significantly. Spent bleaching clay disposal is a growing issue that poses an environmental burden. Reusing bleaching clay can lower expenses and increase oil recovery. In a single sequential run, using spent bentonite clay yields the outcomes comparable to those of virgin bentonite clay. This finding offers a useful green and environmentally friendly approach to remove chlorophyll from microalgae oil feedstock.

Natural gas flaring status in the Bakken shale play and potential remedial solutions

The flaring of associated gas from oil wells and the excess gas from gas-processing units and oil refineries is one of the most prominent producers of greenhouse gas emissions and is an extraordinary waste of economic value given the huge volumes of flared gas. In light of the increasing awareness of its negative impact, the industry is investigating economical means to reduce the anthropogenic release of greenhouse gases into the atmosphere. Oil production from the Bakken and Three Forks formations has significantly increased over the last ten years without commensurate augmentation of gas capture infrastructure, which consequently resulted in increased flaring of the associated gas. The North Dakota Industrial Commission (NDIC) has set rigorous regulations to reduce flaring. However, operating companies are experiencing challenges to meet NDIC gas capturing limit of 95%, which leads to oil production being curtailed.The project’s main objectives are to evaluate technically and economically the feasibility of deploying gas re-injection in the Bakken Formation as a means to increase oil recovery, reduce flaring and meet North Dakota Industrial Commission requirements. The techno-economic assessment utilizes reservoir simulation inputs and outputs such as production rate, fluid composition, injection fluid rate and composition, and bottom hole flowing pressure to provide a detailed costs and revenue estimation of injection and production. Different gas injection schemes are investigated, surface equipment and gas injection network are modeled and optimized. It is substantiated that gas re-injection can increase oil recovery by 34%. The results of this effort suggest that gas re-injection to mitigate flaring in the Bakken can be economically achievable.

Study on gas injection development effect of tight reservoir based on fluid occurrence state

Based on the tight oil reservoir conditions of Lucaogou Formation in Jimusar Sag, Xinjiang, this paper conducts a full-scale characterization experiment of pore structure and designs the optimization numerical simulation of the development scheme based on the geological model combination with the fluid occurrence state. A comparative study on the development methods of tight reservoirs shows that the enhanced oil recovery effect of CO2 flooding is obviously better than that of CH4 flooding and water flooding. When the production bottom hole pressure is lower than the formation fluid saturation pressure, changing the production bottom hole pressure has little impact on the productivity of CO2 flooding in tight reservoirs. The recovery factor increases with the increase of injection rate, but when the injection rate is higher than 15,000 m³/d, the increase of oil recovery and the oil change rate decrease obviously; The complex fractures near the well can help to increase the swept volume of CO2 flooding, while the complex fractures far away from the well will cause channeling, which is not conducive to production. Combined with the occurrence state of the fluid, it is obtained that in the process of CO2 displacement, when the adsorption is considered, when the adsorption components are the same, with the increase of the adsorption capacity, the recovery factor decreases; When the adsorption capacity is constant, the higher the proportion of heavy components is, the lower the recovery factor is; With the increase of adsorption capacity, the permeability decreases more. The fluid occurrence state in tight oil reservoirs is very different from that in conventional reservoirs, and the adsorption phase accounts for a larger proportion, which seriously affects the flow capacity of the fluid during the development process. However, conventional numerical simulation rarely considers the influence of fluid occurrence state.

Effect of UiO-66-NH2/TiO2 nano-fluids on the IFT reduction and their use for wettability alteration of carbonate rocks

One new technique to change the wettability of rocks (carbonate) is sea water (SW) flooding and nano-composite flooding. In this regard, this study investigated the performance of a new synthetic nano-composite called UiO-66-NH2/TiO2 (UT). In this study, this nano-composite is used next to SW. Generally, scanning electron microscopy (SEM), X-ray Powder Diffraction (XRD), Energy Dispersive X-ray Spectroscopy (EDS), and Brunauer-Emmett-Teller (BET) analyses investigated synthetic nano-composite physical and chemical properties. A comparative study of the effect of the synthesized Nano-fluids was performed using interfacial tension (IFT), contact angle (CA), and core flooding experiments. In this experimental study, SW contains Ca2+ and SO42− ions. Generally, nano-composite samples with differents concentrations (0.03 wt% and 0.3 wt%) dispersed in a base-fluid (BF) with varied salinities were prepared. Results showed that this sea-water (SW) + 0.3 wt%UT could reduce interfacial tension from 22 (mN/m) to 3.3 (mN/m) and CA from 118° to 37°. Generally, the interfacial tension between nano-fluids and crude oil is also a function of nano-fluid concentration and BF salinities. On the other hand, oil recovery results using the core flooding test show that SW and 0.3 wt% UT are high efficient than other concentrations. Thus, by injecting this nano-fluid (SW + 0.3 wt% UT), the ratios of oil recovery through the flooding process in the first and second core plugs to the total oil recovery increased by 24.8% and 26%, respectively. In the end, SW + 0.3 wt% UT showed the best performance in relation to increased oil recovery. This study offers new findings that can help oil recovery by understanding SW technology with nano-composite in carbonate reservoirs.

Relative permeability hysteresis analysis in a reservoir with characteristics of the Brazilian pre-salt

The hysteresis of relative permeability and capillary pressure need to be more widespread in academic studies, in order to understand how they can influence reservoirs with light oil and high pressure. These phenomena become extremely important to have a good prediction of oil production, considering that in many cases, the use of hysteresis in calculations can lead to a better prediction of oil recovery, allowing the exploration of certain fields. Thus, this study had as main objective the analysis of two hysteresis models (Killough and Larsen and Skauge) widely used in commercial software, in order to investigate the behavior of a light oil reservoir using a miscible WAG-CO2 process. Thus, to achieve this goal, a semi-synthetic reservoir, with characteristics similar to those found in the Brazilian pre-salt, was considered and was modeled using commercial software from CMG. Hysteresis reduces fluid permeability, which can generate two effects: increased local sweep efficiency of the oil and loss of injectivity. The former effect contributes to increased oil recovery, while injectivity loss can decrease oil sweep, reducing oil recovery. Furthermore, this work found that hysteresis can cause loss of gas and water injectivity, however this did not prevent hysteresis from increasing oil recovery compared to the case without hysteresis.

Increase Oil Recovery in Different Surfactant Concentrations on the Basis of Increasing Well Drainage Area

Increase Oil Recovery in Different Surfactant Concentrations on the Basis of Increasing Well Drainage Area