Enhanced Oil Recovery Studies Research Articles

Evaluation of CO2 utilization and storage potential in the Jimsar shale play from an optimization study

CO2-based enhanced oil recovery (EOR) methods have been widely used in conventional reservoirs, which is also attractive to sequestrating CO2 underground. However, the existing studies on EOR and CO2 sequestration are separate, and there is still a lack of integrated assessment of the carbon capture, utilization, and storage (CCUS) potential of shale reservoirs. In this paper, huff-n-puff (HNP) is considered to be a suitable method for introducing CO2 into the shale formation, and a co-optimization study of EOR and carbon storage is carried out. A fluid model was first developed to simulate the physical change of CO2 and shale oil under reservoir conditions. After that, a numerical simulation model of the injection well is established and calibrated based on the field production history. Finally, a novel optimization method of huff-n-puff with stimulated reservoir volume (SRV) pressure as the criterion is proposed, and the CCUS potential was further investigated. The simulation results show that the optimal recovery can be increased by 10% after 1560 days of huff-n-puff compared to primary depletion. Due to the unique recovery method, 27%–70% of the injected CO2 was trapped during the HNP process, and the proportion of free gas increased with the reservoir pressure, while most of the trapped CO2 was dissolved in the shale oil. Furthermore, an economic analysis with consideration of oil price and the carbon tax was also performed. The oil price directly determines whether CO2 HNP injection is feasible while the carbon tax influences the choice of development scenarios. If the carbon tax is higher than 40$/t, a scenario with more CO2 sequestered is preferred. The investigation performed in this study provides theoretical support for CO2 sequestration in shale reservoirs and a reference for carbon tax policy formulation.

Low-field NMR investigation on interaction of ZnO nanoparticles with reservoir fluids and sandstone rocks for enhanced oil recovery

The use of nanoparticles (NPs) can considerably benefit enhanced oil recovery (EOR) by changing the wettability of the rock, improving the mobility of the oil drop, and decreasing the interfacial tension (IFT) between oil and water. Prior to the application of nanoparticles in oil fields, it is essential to conduct measurements at the laboratory scale. However, the estimation of reservoir wettability is difficult in most laboratory experiments. Practicably, ZnO NPs were used to modify the rock surface wettability, lower the IFT at the oil/water interface, and reduce the interaction of chemical adsorption, such as (surfactant) onto reservoir rock surface to solve various challenges in oil production and EOR operations. Upon confining both ZnO-based nanofluid and the crude oil into sandstone, deviations from the corresponding pure bulk dynamical behaviors were observed with low-field nuclear magnetic resonance (LF-NMR) relaxometry. The expected deviations from the pure bulk behaviors were attributed to the well-known confinement effect. The wettability test results before and after surface variations of formation water (FW) with the addition of three different NP concentrations (0.05, 0.075, and 0.1) wt% ZnO reflected significant changes to its wettability. Among the treatments of Berea sandstone cores with ZnO NPs, the percentage of clay-bound H2O/free fluid index was maximum in 1.0 pore volume (PV) NP treatment. The ratio of NMR relaxations, which determines the affinity of fluids toward solids, by the 1.0 PV NP treatment is reported to have the most potential with higher affinity for FW and less affinity for crude oil toward the pore walls. Hence, LF-NMR allows monitoring of nanofluid and crude oil characteristics in the pores of rock samples and may potentially be applied in further EOR studies.

Numerical simulation and field application of biological nano-technology in the low- and medium-permeability reservoirs of an offshore oilfield

As a result of deep burial depth, small pore throat, poor connectivity between pores, different clay mineral contents in reservoirs, and strong reservoir sensitivity, injection wells often have problems such as rapidly increasing water-injection pressure and insufficient water-injection quantity in the process of water-injection development. The main measures used to solve the difficulties of water injection in low-permeability reservoirs include fracturing, acidizing, and surfactant depressurization and injection increase, all of which have some disadvantages of high cost and environmental damage. In recent years, depressurization and injection-increase environment-safe bio-nano-materials have been introduced into low-permeability reservoirs and have achieved good application results in China. On the other hand, although there have been many researches on EOR (enhanced oil recovery) of nano-materials, the numerical simulation field of nano-depressurization and injection-augmenting technology is still a blank that the wettability mechanism of nano-materials and EOR nano-materials used in bio-nano-depressurization and injection-augmenting technology are almost completely opposite, and the influence of adsorption on formation is almost completely opposite. The adsorption of nanoparticles in other EOR studies will reduce the porosity and make the reservoir more hydrophilic. Nanoparticles used in biological nano-technology will produce hydrophobic film near the well, which will reduce the seepage resistance through the slip of water phase. In this study, a set of water flooding model of numerical simulation technology for depressurization and injection-augmenting of biological nano-materials considering adsorption characteristics and reservoir physical properties was established, the sensitivity analysis of key injection parameters was carried out, and the application effect prediction chart of biological nano-technology was drawn, and the model and prediction chart were verified by real oilfield data. As far as we know, this is the first numerical simulation study on biological nano-technology that has been applied in oil fields.

Effect of pH on interfacial tension reduction of oil (Heavy acidic crude oil, resinous and asphaltenic synthetic oil)/low salinity solution prepared by chloride-based salts

Chloride salts of NaCl, KCl, CaCl 2 , and MgCl 2 are among the essential salts examined for enhanced oil recovery (EOR) purposes through chemical injection, low salinity injection, smart water injection, etc. These salts are crucial for EOR studies since they exist in the reservoir with undeniable effects on interfacial tension (IFT), wettability alteration, etc. The alkaline injection that can produce in-situ soap leading to lower IFT values can be combined with low salinity injection method to form the hybrid EOR method. Among the different parameters in alkaline flooding, the aqueous solution pH is essential, since there is a strong relationship between the pH of the solution and crude oil type for ionization and generating in-situ soap. Whit this parameter, the current investigation concentrated on the effect of chloride-based salt (with a concentration of 5000 ppm to mimic the low salinity condition) at different pH values of 3.5, 7, and 11 in contact with heavy acidic crude oil (HACO). Since resin and asphaltene have a surfactant nature, resinous synthetic oil (8 % wt/wt) (RSO) and asphaltenic synthetic oil (8 % wt/wt) (ASO) were prepared by dissolving isolated resin and asphaltene using IP/140 procedure and examined. The results show that IFT can reduce to a value of 0.4 and 2.5 mN.m-1 for pH of 11 and DW solution if RSO and HACO utilize. The results also reveal that among the examined salts, NaCl and KCl introduce the highest impact for all types of model oils at pH values of 11, while no significant effect for pH values of 3.5 and 7 was obtained. According to these findings, it seems that injecting alkaline chemicals such as NaOH (which enhances aqueous solution pH) is an effective way to reduce the IFT values due to the in-situ surfactant generation and saponification of organic acids exited in model oils. Additionally, the IFT values show that although salts can retard the IFT reduction to some extent, no significant negative influence on the IFT reduction trends exist for the case of NaCl and KCl. • Increasing pH from 3.5 to 11 significantly reduces the IFT values for Heavy acidic crude oil. • Increasing pH from 3.5 to 11 significantly reduce the IFT value especially for resinous synthetic oil. • Chloride salts except CaCl2 introduce positive effects on IFT for pH values of 3.5 and 7. • Chloride salts introduce negative effects on the IFT for pH value of 11. • Increasing pH can generate in-situ surfactants by saponification.

Low‐cost pyrophyllite‐based microfluidic device for the study of enhanced oil recovery

This work proposed a novel method for the fabrication of pyrophyllite-based microfluidic devices for enhanced oil recovery (EOR). Pyrophyllite has good heat resistance, corrosion resistance and similar molecular structure to quartz sandstone, and is suitable for EOR research. A rectangular matrix of the pore structure is designed, representing an idealised porous medium and then fabricated on the surface of pyrophyllite substrate by using the micro-milling method. Finally, a layer of sealing film was applied on the surface of substrate to finish the bonding process. A droplet generator was also fabricated for the demonstration of the proposed technology. A series of displacement experiments with water flooding and surfactant flooding were conducted and the result was carefully analysed and discussed. Compared with the previous study using polymer-based or glass-based microfluidic devices as micromodels for the displacement study in oil recovery process, the surface properties of pyrophyllite are more close to real reservoirs and have compelling advantages as bulk material for microfluidic devices for the EOR study. This work has wide potential applications as the micromodels in EOR research, the proposed fabrication protocols of the pyrophyllite-based microfluidic device are rapid and low-cost, the on-site field test could also be conducted with the proposed technology.

Most common surfactants employed in chemical enhanced oil recovery

Abstract Chemical enhanced oil recovery (EOR) and particularly surfactant injection has recently received a great deal of attention. The suggested recovery mechanisms after injecting surfactants include wettability alteration and IFT reduction. If a surfactant is properly selected according to the environmental variables-such as pressure, temperature, salinity, it can lead to more efficient enhanced recovery from an oil reservoir. On the other hand, poor selection of the surfactant can result in a low recovery and can even become detrimental to the reservoir due to undesirable wettability alteration and possible rock dissolution resulting in a chemical reaction with displacing fluid and blockage of the pore space. Also, choosing the wrong surfactant without considering the rock mineralogy may result in high adsorption on the pore surface of the rock and unnecessary waste of resources. It is also worthy to note that surfactants are some of the most expensive chemicals used during EOR. Extensive literature review suggests that anionic surfactant are the preferred surfactant category for EOR especially when it comes to sandstone reservoirs. Occasionally, in specific situations a better performance have been reported after injecting cationic, non-ionic or mixtures of both surfactants, particularly when dealing with carbonate reservoirs. This paper presents in detail a review of the most commonly applied surfactants in EOR studies and the optimum application criteria for of each type. To the best of the authors' knowledge, such detailed and comprehensive review is not available in the literature, presently.

Novel investigation based on cationic modified starch with residual anionic polymer for enhanced oil recovery

ABSTRACTCationic modified starch polymer (CMSP) is a newly developed green chemical agent designed to reutilize the residual anionic polymer found in reservoirs for enhanced oil recovery (EOR). In this study, a series of experiments were conducted to investigate the phase behavior of the residual anionic polymer, CMSP solution, and the flocculation generated from the mixture in plugging capacity and capability of enhancing oil recovery in heterogeneous reservoirs. The experiment results show that the phase behavior of the residual anionic polymer and CMSP solution could be divided into two parts: rapid flocculation reaction and dispersion reaction. The main mechanisms of the rapid flocculation reaction were charge neutralization and bridging. Based on the above results, an optimal amount of CMSP was chosen for plugging capacity, stability, and EOR study. Plugging tests in both parallel cores and EOR in three-layer heterogeneous square cores illustrate that the injected CMSP slug after polymer flooding can effectively block the high-permeability zone and initiate the remaining oil in middle- to low-permeability zones. The investigation results prove that the CMSP solution, injected after polymer flooding, reduces the pollution of produced fluid and further improves oil recovery.

Sequential Coupling of Geochemical Reactions With Reservoir Simulations for Waterflood and EOR Studies

Summary Many waterflood projects now experience significant amounts of water cut, with more water than hydrocarbon flowing between the injectors and producers. In addition to the impact on water viscosity and density that results from using different injection-water sources during a field's life, water chemistry itself may impact oil recovery, as demonstrated by recent research on low-salinity water-injection schemes. It is also known that water chemistry has a profound impact on various chemical enhanced-oil-recovery (EOR) processes. Moreover, the effectiveness and viability of such EOR schemes is strongly dependent on reservoir-brine and injection-water compositions. In particular, the presence of divalent cations such as Ca+2 and Mg+2 has a significantly adverse effect for chemical EORs. Using new developments in reservoir simulation, this paper outlines a method to couple geochemical reactions in a reservoir simulator in black-oil and compositional modes suitable for large-scale reservoir models for waterflood and EOR studies. The new multicomponent reactive-transport modeling capability considers chemical reactions triggered by injection water and/or injected reactive gases such as CO2 and H2S, including mineral dissolution and precipitation, cation exchange, and surface complexation. For waterflood-performance assessment, the new modeling capability makes possible a more-optimum evaluation of petrophysical logs for well intervals where injection-water invasion is suspected. By modeling transport of individual species in the aqueous phase from injectors to producers, reservoir characterization can also be improved through the use of these natural tracers, provided that the compositions of the actual produced water are used in the history matching. The simulated water compositions in producers can also be used by production chemists to assess scaling and corrosion risks. For CO2 EOR studies, we illustrate chemical changes inside a reservoir and in the produced water before and after CO2 breakthrough, and discuss geochemical monitoring as a potential surveillance tool. Alkaline-flood-induced water chemical changes and calcite precipitation are also presented to illustrate applicability for chemical EOR with the new simulation capability.

Enhanced Oil Recovery (EOR) by Miscible CO2 and Water Flooding of Asphaltenic and Non-Asphaltenic Oils

An EOR study has been performed applying miscible CO2 flooding and compared with that for water flooding. Three different oils are used, reference oil (n-decane), model oil (n-C10, SA, toluene and 0.35 wt % asphaltene) and crude oil (10 wt % asphaltene) obtained from the Middle East. Stearic acid (SA) is added representing a natural surfactant in oil. For the non-asphaltenic oil, miscible CO2 flooding is shown to be more favourable than that by water. However, it is interesting to see that for first years after the start of the injection (< 3 years) it is shown that there is almost no difference between the recovered oils by water and CO2, after which (> 3 years) oil recovery by gas injection showed a significant increase. This may be due to the enhanced performance at the increased reservoir pressure during the first period. Maximum oil recovery is shown by miscible CO2 flooding of asphaltenic oil at combined temperatures and pressures of 50 °C/90 bar and 70 °C/120 bar (no significant difference between the two cases, about 1%) compared to 80 °C/140 bar. This may support the positive influence of the high combined temperatures and pressures for the miscible CO2 flooding; however beyond a certain limit the oil recovery declined due to increased asphaltene deposition. Another interesting finding in this work is that for single phase oil, an almost linear relationship is observed between the pressure drop and the asphaltene deposition regardless of the flowing fluid pressure.