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The complete paper presents the results of evaluation of laboratory and demonstration trials of HDPE liner to mitigate premature failures and prolong the run life of production tubing. Calgary-based Colombia producers Canacol Energy and Parex Resources led all firms by gaining three blocks each, with one more counteroffer from Parex pending review. India’s ONGC reported an oil find in Colombia’s Llanos Basin as well as a gas and oil discovery in Brazil’s deepwater Sergipe Alagoas Basin. Colombia’s New Ambitions Include Caribbean and Shale Development, But Are They Achievable? Colombia is walking a thin line between becoming another fading petroleum province and Latin America’s next big success story.
Calgary-based Colombia producers Canacol Energy and Parex Resources led all firms by gaining three blocks each, with one more counteroffer from Parex pending review. India’s ONGC reported an oil find in Colombia’s Llanos Basin as well as a gas and oil discovery in Brazil’s deepwater Sergipe Alagoas Basin. Colombia’s New Ambitions Include Caribbean and Shale Development, But Are They Achievable? Colombia is walking a thin line between becoming another fading petroleum province and Latin America’s next big success story. Its aces in the hole: unleashing its nascent offshore and unconventional sectors.
Nanotechnology is one of the modern techniques that can be used for enhancing the oil recovery. Enhanced oil recovery (EOR) is mainly used after oil production declination by chemically altering the injection water. However, it is very important to have an environmentally friendly method to enhance oil recovery. A possible method is to use nanofluids that include nanosilica-polymer (NFs) which contain mainly sandstone ingredients.
This research is mainly an experimental investigation of the usage of several nanofluids with silica particles for enhanced oil recovery. Nanofluid injection is performed in core plugs and the oil recovery is compared with the oil recovery obtained with synthetic sea water (SSW) injection. Both nanofluid and SSW are injected in secondary mode. Five cleaned and dried Berea sandstone cores were used in the core flooding experiments. First, secondary recovery was applied on all cores by SSW injection. Then the cores were re-cleaned and re-dryed to be prepared for the secondary recovery by using 4 different types of nanofluids with the same concentration of 0.1 wt% as NFs.
In this research, it was important to use exactly the same rock in both the SSW and nanofluid flooding to avoid any effect of pore structure on the oil recovery. The research showed that the best nanofluid contained nanoparticles of silica-alumina. This nanofluid gave the highest oil recovery and altered the wettability from water wet to strongly water wet due to the ionic interactions. The ultimate oil recovery was increased to 10.4% of OOIP (original oil in place) compared to SSW injection. In addition to investigating the quantitative effect of the use of several nanofluids with different nanoparticles sizes and surface modifications on oil recovery we also applied Scanning Electron Microscopy (SEM) to study pore blockage, log jamming, and emulsions between NFs and crude oil.
Neubauer, Elisabeth (OMV Exploration & Production GmbH) | Hincapie, Rafael E. (OMV Exploration & Production GmbH) | Borovina, Ante (OMV Exploration & Production GmbH) | Biernat, Magdalena (OMV Exploration & Production GmbH) | Clemens, Torsten (OMV Exploration & Production GmbH) | Ahmad, Yusra Khan (Nissan Chemical America Corporation)
This work examines the potential use of two different nanoparticle solutions for EOR applications. Combining the evaluation of fluid-fluid interactions and spontaneous imbibition experiments, we present a systematic workflow. The goal of the study was to enable the generation of predictive scenarios regarding the application of Nano-EOR in OMV's assets. Therefore, influence of high and low TAN crude oil, core mineralogy, composition of the nanofluid on wettability alteration and recovery were studied. Nanomaterials used in this work employ inorganic nano-sized particles in a colloidal particle dispersion. We evaluated two types; one utilizes surface-modified silicon dioxide nanoparticles, while the other employs a synergistic blend of solvent, surfactants and surface-modified silicon-dioxide nanoparticles. IFT experiments were performed using a spinning-drop tensiometer and results were compared at ~180 min of observation. Amott-Harvey experiments enabled investigating wettability alteration considering effects of crude-oil composition and core mineralogy (~5 and ~10% clay content).
Interfacial tension reduction was observed for both nanofluids. The blend yielded slightly lower values (~0.5- 0.6 mN/m) compared to the nanoparticles-only fluid (~0.8 mN/m), which is most likely related to the surfactant contained in the formulation. Amott-Harvey spontaneous imbibition experiments depicted clear wettability alterations for both nanofluids. Cores with ~5% clay content exhibited a water-wettish behavior, and additional recoveries using the nanofluids were up to 10%. In the cores containing ~10% clay, the nanoparticle-only fluid spontaneously imbibes to the rock matrix and quickly displaces large amounts of oil (~70% independently of the oil type that was used). Contrary, the blend yields higher recovery from the 10% clay cores, with the high TAN oil than with low TAN oil (57 ± 3 vs. 45 ± 1%). However, in 5% clay cores, faster imbibition was observed when the blend was used, which can be explained by a higher capillary pressure. A special case was observed in cores with 10% clay content (Keuper), where the baseline experiments using brine exhibited a high standard deviation. We attribute this behavior to the large mineralogical heterogeneity of the Keuper cores and the heterogeneous distribution of clays and mineralogical impurities. Both the blend and the surface-modified nanoparticles managed to restore a water-wet state, and additional promising recoveries were up to 65% in the case of strong oil-wetness.
Nano-EOR is an embryonic technology; hence, literature data is scarce on how oil composition and reservoir mineralogy could influence its use to obtain additional recovery and maximize benefits. Our systematic workflow, helps understanding the parameters that require detailed evaluation in order to forecast recoveries for field tests. The experimental synergies provide a good approach to evaluate fluid-fluid and rock-fluid interaction.
Rognmo, Arthur U. (University of Bergen) | Al-Khayyat, Noor (University of Bergen) | Heldal, Sandra (University of Bergen) | Vikingstad, Ida (University of Bergen) | Eide, Øyvind (University of Bergen) | Fredriksen, Sunniva B. (University of Bergen) | Alcorn, Zachary P. (University of Bergen) | Graue, Arne (University of Bergen) | Bryant, Steven L. (University of Calgary) | Kovscek, Anthony R. (Stanford University) | Fernø, Martin A. (University of Bergen)
Summary The use of nanoparticles for CO 2 -foam mobility is an upcoming technology for carbon capture, utilization, and storage (CCUS) in mature fields. Silane-modified hydrophilic silica nanoparticles enhance the thermodynamic stability of CO 2 foam at elevated temperatures and salinities and in the presence of oil. The aqueous nanofluid mixes with CO 2 in the porous media to generate CO 2 foam for enhanced oil recovery (EOR) by improving sweep efficiency, resulting in reduced carbon footprint from oil production by the geological storage of anthropogenic CO 2 . Our objective was to investigate the stability of commercially available silica nanoparticles for a range of temperatures and brine salinities to determine if nanoparticles can be used in CO 2 -foam injections for EOR and underground CO 2 storage in high-temperature reservoirs with high brine salinities. The experimental results demonstrated that surface-modified nanoparticles are stable and able to generate CO 2 foam at elevated temperatures (60 to 120 C) and extreme brine salinities (20 wt% NaCl). We find that (1) nanofluids remain stable at extreme salinities (up to 25 wt% total dissolved solids) with the presence of both monovalent (NaCl) and divalent (CaCl 2) ions; (2) both pressure gradient and incremental oil recovery during tertiary CO 2 -foam injections were 2 to 4 times higher with nanoparticles compared with no-foaming agent; and (3) CO 2 stored during CCUS with nanoparticlestabilized CO 2 foam increased by more than 300% compared with coinjections without nanoparticles. Introduction The energy trilemma faced by the global community includes energy security (plentiful and reliable), energy affordability, and environmental sustainability. In this regard, the intergovernmental panel on climate change points to carbon capture and storage as one contributing technology to mitigate the CO 2 -emission challenge (IPCC 2014). For profit-maximizing corporations, the economic incentives for storing CO 2 in a pure carbon capture and storage case are limited and new technologies to increase profitability are desirable.
Nanofluid, an emerging heat transfer fluid, is nowadays considered a new field of scientific research that could strengthen the thermal and mechanical properties of the base fluid. Nanosized particles of metal, alloy, and other high conductive material are mixed with engine lubricants to alleviate friction and wear. The purpose of the project is to experimentally assess the feasibility of using Nano-fluid lubricant in IC engine. Nano-sized Copper particles are mixed with the oil engine to enhance the performance of the heat transfer. The present study postulated that adding a nano-additive to the oil is a key factor for enhancing the thermal performance of the internal combustion engine. In particular, the experiments implemented in the study concentrate on the engine oil temperature, the gases exhaust temperature, and the performance of the cooling system. It has been shown that adding nanoparticles at 3 % VOF inside the oil engine, has reduced the temperature up to 26% of engine surface and 16% of the oil engine. The performance of the cooling system, presented by demonstrating the exit temperature of the radiator coolant, has shown to be slightly enhanced due to the augment in the thermal conductivity of the mixture. Heat losses for lubricant to the environment has dropped by 17% while the engine break thermal efficiency enhances by a factor of 1.5.
The ongoing demand of hydrocarbon triggered the decline of oil reserves globally and turned into a major challenge for the producers concerned with the recovery of remaining (residual) crude oil from reservoirs. Thus, improving oil production from current reservoirs holds the key to meet the current and near future challenges of global energy demands. Nano-assisted enhanced oil recovery (N-EOR) is one of the techniques which can considerably improve the oil recovery factor of the trapped oil. Nanofluid, a colloidal suspension of nanoparticles (NPs) (size ~ 10-9 m) in polyacrylamide solution (base fluid) may enhance the oil production by governing the matter of facts at nano scale level. However, complex reservoir fluids are highly saline; which greatly affects the physical-stability of nanofluid and limits their efficacy for subsurface applications resulting in premature settlement and possibly may block the reservoir pores during flow through reservoir pores, turns into reduction on N-EOR application, not yet reported, nevertheless, a key parameter for high saline reservoirs. Therefore, a novel synthesis of nanofluid consisting SiO2 in the base solution of polyacrylamide is proposed. Anionic surfactant (SDS) in varying concentrations are used to curtail the effect of reservoir salinity. The physical stability for the formulated nanofluids is discussed using dynamic light scattering (DLS) and sedimentation height of NPs. Moreover, the formulated nanofluids are then investigated using sandpack experiments for N-EOR. The surface-coated NPs in nanofluid attended maximum recovery of 65% in the saline environment (5 wt% NaCl) while it was 70% for without NaCl. Therefore, this study showed the novel fabrication methodology of a stable nanofluid in a saline environment and their application using N-EOR techniques with where reservoir salinity became a major challenge.
Li, Shidong (Institute of Chemical and Engineering Sciences, Agency for Science, Technology and Research A*STAR) | Dan, Daniel (Institute of Materials Research and Engineering, Agency for Science, Technology and Research A*STAR) | Lau, Hon Chung (Department of Civil and Environmental Engineering, National University of Singapore, Singapore, Singapore. Institute of Chemical and Engineering Sciences, Agency for Science, Technology and Research A*STAR) | Hadia, Nanji J (Institute of Chemical and Engineering Sciences, Agency for Science, Technology and Research A*STAR) | Torsæter, Ole (PoreLab, Norwegian Center of Excellence. Department of Geoscience and Petroleum, Norwegian University of Science and Technology NTNU) | Stubbs, Ludger P. (Institute of Chemical and Engineering Sciences, Agency for Science, Technology and Research A*STAR)
Altering the wetting state of a rock surface to more water-wet has been proposed as an enhanced oil recovery (EOR) mechanism for nanoparticles. However, how nanoparticles achieve this is not well understood. The objective of this study is to fill this knowledge gap by using advanced 2D and 3D visualization techniques.
In this study, advanced visualization techniques were used to study how hydrophilic silica nanoparticles change the wettability of a glass surface. First, we used interferograms of an oil drop resting on a nanoparticle-treated glass surface to analyze the effect of nanoparticles on wettability. Second, we used Atomic Force Microscopy (AFM) to characterize the structure of nanoparticles covering a glass surface. Third, we used a 2D microfluidic apparatus to visualize wettability alteration caused by the nanoparticle injection. Fourth, we used a fluoresence imaging method with confocal microscopy to find out the reason for this change.
Interferograms of a nanoparticle-treated glass surface showed bright and dark fringes, indicating the presence of a thin water film covering the glass surface caused by nanoparticle adsorption. Furthermore, the higher the nanoparticle concentration, the thicker was the nanoparticle adsorption layer. A low pH environment can reduce nanoparticle adsorption on the glass surface. AFM results showed that the topography of the glass surface changed from smooth to rough after nanoparticle treatment. Microfluidic experiments showed that nanoparticle injection changed the wettability of the grain surface to more water wet. By using a confocal microscopy, we observed a thin water film covering the surface of glass grains suggesting that nanoparticle adsorption is the main mechanism of wettability alteration by nanoparticles.
This paper presents findings of new techniques to study wettability alteration by nanoparticles, including thin-film interferometry, surface characterization by AFM, and fluoresence imaging with confocal microscopy. Observations showed that nanoparticles adsorption on a glass surface results in a thin water film that prevents the oil from contacting the surface. This is the main mechanism of wettability alteration by nanoparticles. This is the first time use of these advanced visualization techniques to study wettability alteration by nanoparticles is reported.
Omotosho, Yetunde A. (Department of Petroleum Engineering, University of Ibadan) | Falode, Olugbenga A. (Department of Petroleum Engineering, University of Ibadan) | Ojo, Temilola I. (Covenant University, Canaanland, Otta)
Enhanced Oil Recovery (EOR) methods continue to be dominant in improving world’s oil reserves as producing fields mature. Global growth of 18% was recorded in proved reserves between 2007 and 2017 (BP Statistical Review, 2018), with North America, which has invested in several EOR techniques, contributing about 14% to this growth. This proves that EOR stands as a long-term solution to the menace of dwindling reserves. Recently, nanotechnology has been gaining attention for application in the petroleum industry. It has been established that nanoparticles dispersed in base fluids such as water, brine or certain organic solvents (nanofluid) exhibit some special properties proved to be advantageous for EOR purposes. Additional recovery of about 30% has been recorded. However, permeability damage, which has been widely reported, is yet to be critically studied and analysed.
The objective of this research was to investigate how two important properties; concentration and injection rate of the nanofluid, affect oil recovery, and as well establish the thresholds of conditions which lead to permeability impairment and injection fluid loss during nanoflooding with silica nanoparticles. The permeability impairment layer which is gradually formed at the rock pore surface is termed nanoskin (a concept introduced by the author).
Four core samples were flooded with brine followed by silica nanofluid of four different concentrations viz; 0.01, 0.5, 2.0 amd 3.0% wt/wt respectively. The flooding process was accompanied with changing injection rates viz; 0.5, 1.0, 2.0, 3.0 cm3/min.
The result indicated that concentration of 2.0% wt/wt and injection rate of 2.0 cm3/min were threshold levels that guaranteed optimal oil recovery from the Niger Delta core samples. The overall result demonstrates that nanoflooding is a viable EOR technique and establishes a combination of parameters that will minimize nanoskin formation during nano-EOR process.
Miller, Quin R. S. (Pacific Northwest National Laboratory) | Schaef, H. Todd (Pacific Northwest National Laboratory) | Nune, Satish K. (Pacific Northwest National Laboratory) | Jung, Ki Won (Pacific Northwest National Laboratory) | Burghardt, Jeffrey A. (Pacific Northwest National Laboratory) | Martin, Paul F. (Pacific Northwest National Laboratory) | Prowant, Matthew S. (Pacific Northwest National Laboratory) | Denslow, Kayte M. (Pacific Northwest National Laboratory) | Strickland, Chris E. (Pacific Northwest National Laboratory) | Prasad, Manika (Colorado School of Mines) | Pohl, Mathias (Colorado School of Mines) | Jaysaval, Piyoosh (Pacific Northwest National Laboratory) | McGrail, B. Peter (Pacific Northwest National Laboratory)
Acoustic impedance tube and forced-oscillation seismic core test measurements were conducted to examine the low-frequency properties of acoustic metamaterial contrast agents. Water-stable suspensions of metal-organic framework (MOF) nanoparticles increased sound transmission loss (100-1250 Hz) and seismic attenuation (10-70 Hz), and reduced Young's modulus of nanofluid-saturated Berea Sandstone cores. Preliminary measurements were used to parameterize a seismic wave velocity model. These results indicate that injectable MOF nanofluid contrast agents have potential to enhance seismic delineation of subsurface fluids and structures.
Subsurface monitoring of injected fluids and fracture networks is a critical component of geologic carbon storage and enhanced hydrocarbon recovery operations. Detection sensitivity, volumetric distribution, and migration paths of injectates are commonly difficult to obtain with geophysical techniques, especially in reservoirs containing complex secondary fracture networks (Figure 1) and/or extensive layering. Our goal is to develop a new class of seismic contrast agents to enable monitoring of injected fluids and gas-brine-hydrocarbon interfaces via conventional seismic imaging methods. We recently demonstrated that microporous metal-organic frameworks (MOF) are low-frequency (100-1250 Hz) absorptive acoustic metamaterials, exhibiting anomalous sound transmission loss and tunable resonance (Miller et al., 2018). Herein, we describe a novel class of injectable MOF nanofluid seismic contrast agents for enhanced mapping and monitoring of subsurface fluids and structures. We report increased low-frequency sound transmission loss due to water-stable MIL-101(Cr) (MIL: Materials Institute Lavoisier) nanoparticle suspensions and demonstrate that MIL-100(Fe) nanofluids influence the 10-70 Hz anelastic and elastic properties of saturated Berea Sandstone cores. These MOF nanofluid-based injectable contrast agents have the potential to comprise a disruptive high-performance geophysical technology for monitoring geologic CO2 storage, oil and gas extraction, enhanced geothermal systems, and hydraulic fracturing.
Materials and Methods
Two MOF-based nanofluids were evaluated in this study. The two types of MOFs used in this study were chosen due to their similarity with previously-studied MOFs (Miller et al., 2018; Schaef et al., 2017) that exhibited notable low-frequency acoustic properties. The ~0.5 wt% nanofluids used in this study were prepared by synthesizing MIL-101(Cr) (Férey et al., 2005) nanoparticles [nanoMIL-101(Cr)] following previously-reported procedures (Schaef et al., 2017). NanoMIL-101(Cr) was selected for its very high specific surface area (SSA) of 2917 m2/g and its potential to form water-stable nanofluids (Nandasiri et al., 2016). MIL-100(Fe) (Horcajada et al., 2007) nanoparticles [nanoMIL-100(Fe)] were also synthesized for low-frequency property testing. MIL-100(Fe) nanoparticles were prepared using a similar method to that used for nanoMIL-101(Cr). Iron nitrate nonahydrate (0.5g, 1.23 mmol), 1,3,5-benzene tricarboxylic acid (0.174g, 0.83 mmol), and modulator 4-methoxy benzoic acid (9.4 mg, 0.62 mmol) were added to 40 mL of water. The heterogeneous suspension was mixed thoroughly followed by sonication for five minutes at room temperature. The mixture was then heated to 160 °C for 12 hours in a Teflon-lined autoclave. The reaction mixture was cooled to room temperature, isolated via centrifugation, and washed with deionized water and ethanol twice to produce a ~0.5 wt% nanofluid.