Hendraningrat, Luky (Norwegian University of Science and Technology (NTNU)) | Souraki, Yaser (Norwegian University of Science and Technology (NTNU)) | Torsater, Ole (Norwegian University of Science and Technology (NTNU))
Most of current total world oil resources are coming from unconventional oil such as heavy oil, extra heavy oil and bitumen. Since conventional light crude oil production is declining and its resources has short fall, those unconventional oil are increasingly interesting in recent years. However the most difficulty to handle those oils is their high viscosity. Thermal application methods constitute great importance for heavy oil production. The development of current technology has enabled manufacturer to create various types of nanoparticles, including metal nanoparticles, for multi-purposes in various sectors including the oil and gas industry.
The metal nanoparticles-assisted heavy oil production seems potentially interesting as catalyst to increase efficiency of heat transfer mechanism. The purpose of study is to investigate the effect of using metal nanoparticles for viscosity reduction of heavy oil. In-situ thermal induction and aquathermolysis methods are conducted.
In this study, various metal nanoparticles compound with different thermal conductivity: Cu, Zn, Ni and Fe, are employed and Athabasca bitumen was used. Those nanoparticles are characterized under scanning electron microscope and their compounds are identified by energy-dispersive X-ray spectroscopy (EDX) analysis. The Athabasca bitumen is blended with metal-nanoparticles using sonicator at given concentration. Water is used for aquathermolysis method. Both methods are conducted in various temperatures. Those methods are then compared to identify their efficiency. Metal nanoparticles type and size are also involved in this study. There are momentous changes in heavy oil viscosities by using those catalysts.
The detailed process and results are outlined in the paper to reveal the possible application of metal nanoparticles to assist heavy oil recovery.
Align with current dynamic technology development, waterflooding techniques have been improved and optimized to have better oil recovery performance. In addition the latest worldwide industries innovation trends are miniaturization and nanotechnology materials such as nanoparticles. Hence one of the ideas is using nanoparticles to assist waterflood performance. However it is crucial to have a clear depiction of some parameters that may influences displacement process.
The focus of this study is to investigate the effects of some parameters influencing oil recovery process due to nanoparticles such as particle size, rock permeability, initial rock wettability, injection rate and temperature. This study is part of our ongoing research in developing nanofluids for future or alternative enhanced oil recovery (Nano-EOR) method.
Three different sizes of hydrophilic silica nanoparticles with single particle diameter range from 7 to 40 nm were employed and have been characterized under scanning electron microscope (SEM). Nanofluids were synthesized using 0.05 wt.% nanoparticles that dispersed into synthetic brine (NaCl 3 wt.% ~ 30,000 ppm). The contact angle variation due to nanoparticles size was also measured at room condition. Coreflood experiment has been conducted using 26 Berea sandstone cores to evaluate the effect of those parameters above on oil recovery due to Nano-EOR. The cores permeability was in range from 5 to 450 mD. To study the effect of initial rock wettability on oil recovery due to Nano-EOR, original core wettability has been changed with aging process from water-wet to intermediate and oil-wet respectively. Temperature was also studied in range 25-80 oC to fulfill the possibility of applying Nano-EOR at reservoir temperature.
The coreflood testing was repeated for each case to have consistency result. The processes and results are outlined and also further detailed in the paper to bring knowledge about nanoparticles flooding as a future promising EOR method.
Souraki, Yaser (Norwegian University of Science and Technology - NTNU) | Torsater, Ole (Norwegian University of Science and Technology - NTNU) | Jahanbani Ghahfarokhi, Ashkan (Norwegian University of Science and Technology - NTNU) | Ashrafi, Mohammad (Norwegian University of Science and Technology - NTNU)
Canada, Venezuela and United States contain the largest portions of heavy oil and bitumen resources throughout the world. The problem associated with this type of resource is very viscous fluid flow. The EOR methods applied to heavy oil reservoirs are mainly based on viscosity reduction processes such as heating the reservoir and solvent injection. Heating, in the form of hot water flooding, steam injection and in-situ combustion dramatically reduces the viscosity of heavy oil and bitumen, but it has green house gas (GHG) emission problems. Diffusion of solvents in heavy oil makes it lighter and therefore mobile and producible via production well. Diffusion of solvent is a very tardy process while time is very important in oil industry and any delay results in extra costs. Recently, hybrid methods like solvent and steam co-injection, steam alternating solvent injection (SAS) have been introduced to solve the mentioned problems, while benefiting from the advantages of heat and solvent.
Several simulation studies were performed to evaluate and compare the performance of steam assisted gravity drainage (SAGD) and steam alternating solvent (SAS) processes. Athabasca bitumen reservoir properties were used. Effects of some reservoir and fluid parameters such as thickness, porosity, vertical to horizontal permeability ratio and viscosity were assessed and compared for both processes. Experimental viscosity data of Athabasca and Cold lake bitumen were applied to evaluate the viscosity effect. In addition, sensitivity analysis was carried out on injection time intervals of solvent, solvent type and concentration.
Results revealed high recovery of bitumen and appropriate steam-oil ratio (SOR) for both processes. However, SAS showed better performance using hexane as a solvent. Lower porosity, vertical to horizontal permeability ratio and thickness resulted in higher SOR for SAGD process while they had no major effect on SAS. Higher concentration of injected solvent resulted in faster recovery performance and lower SOR. Pentane and heptane were used as alternatives for hexane to investigate the impact of the selected solvent. They divulged almost the same results as hexane. Different injection intervals of 3, 6, 9 months and a year were also studied and the analogous results were obtained.
Nanoparticles have become an attractive agent for improved and enhanced oil recovery (IOR & EOR) at laboratory scale recently. Most researchers have observed promising result and increased ultimate oil recovery by injecting nanofluids in laboratory experiments. In previous study, we observed that interfacial tensions (IFT) decreased when hydrophilic nanoparticles were introduced to brine. The IFT decreases as nanofluids concentration increase and this indicates a potential for EOR. We have also investigated nanofluid flow in glass micromodel and high permeability Berea sandstone (ss) cores, and we observed that the higher concentration of nanofluids; the more impairment of porosity and permeability. Since low permeability oil reservoirs have still huge volume of oil reserves, this study aims to reveal nanofluids possibility for EOR in low-medium permeability reservoir rocks and investigate its suitable concentration.
In this paper, laboratory coreflood experiments were performed in water-wet Berea ss core plugs with permeability in range 9- 35 mD using different concentrations of nanofluids. Three nanofluids concentrations were synthesized with synthetic brine; 0.01, 0.05 and 0.1 wt.%. To investigate disjoining pressure as displacement mechanism due to nanoparticles, contact angle between crude oil from a field in the North Sea and brine/nanofluids have been measured. Increasing hydrophilic nanoparticles will decrease contact angle of aqueous phase and increase water-wetness.
Despite increasing nanofluid concentration shows decreasing IFT and altering wettability, our results indicate that additional recovery is not guaranteed. The processes and results are outlined and also further detailed in the paper to reveal the possible application of nanofluid EOR in lower-medium permeability oil reservoir.
In a past decade, various nanoparticle experiments have been initiated for improved/enhanced oil recovery (IOR/EOR) project by worldwide petroleum researchers and it has been recognized as a promising agent for IOR/EOR at laboratory scale. A hydrophilic silica nanoparticle with average primary particle size of 7 nm was chosen for this study. Nanofluid was synthesized using synthetic reservoir brine. In this paper, experimental study has been performed to evaluate oil recovery using nanofluid injection onto several water-wet Berea sandstone core plugs.
Three injection schemes associated with nanofluid were performed: 1) nanofluid flooding as secondary recovery process, 2) brine flooding as tertiary recovery processs (following after nanofluid flooding at residual oil saturation), and 3) nanofluid flooding as tertiary recovery process. Interfacial tension (IFT) has been measured using spinning drop method between synthetic oil and brine/nanofluid. It observed that IFT decreased when nanoparticles were introduced to brine.
Compare with brine flooding as secondary recovery, nanofluid flooding almost reach 8% higher oil recovery (% of original oil in place/OOIP) onto Berea cores. The nanofluid also reduced residual oil saturation in the range of 2-13% of pore volume (PV) at core scale. In injection scheme 2, additional oil recovery from brine flooding only reached less than 1% of OOIP. As tertiary recovery, nanofluid flooding reached additional oil recovery of almost 2% of OOIP. The IFT reduction may become a part of recovery mechanism in our studies. The essential results from our experiments showed that nanofluid flooding have more potential in improving oil recovery as secondary recovery compared to tertiary recovery.
The oil and gas industry must face the challenges to unlock the resources that are becoming increasingly difficult to reach with conventional technology. Most oil fields around the world have achieved the stage where the total production rate is nearing the decline phase. Hence, the current major challenge is how to delay the abandonment by extracting more oil economically. The latest worldwide industries innovation trends in miniaturization and nanotechnology material. A nanoparticle, as a part of nanotechnology, has size typically less than 100 nm. Its size is much smaller than rock pore throat in micron size. A nanoparticle fluid suspension, so called nanofluid, is synthesized from nano-sized particles and dispersed in liquids such as water, oil or ethylene glycol.
Through continuously increasing of publication addressed on the topic, nanofluid has showed its potential as IOR/EOR in the past decade. It has motivated us to perform research study to reveal the recovery mechanism and performance of nanofluid in porous medium. We focus on liphopobic and hydrophilic silica nanoparticles (LHP). Miranda et al. (2012) has mentioned the benefit of using silica nanoparticles. It is inorganic material that easier produced with a good degree of control/modify of physical chemistry properties. It can also be easily surface functionalized from hydrophobic to hydrophilic by silanization with hydroxyl group or sulfonic acid. Ju et al. (2006) has initially observed LHP with size range 10-500 nm could improve oil recovery with around 9% (with LHP concentration 0.02 vol. %) compared with pure water. They explained that the recovery mechanism involves wettability alteration of reservoir rock due to adsorbed LHP. Besides, they also reported the porosity and permeability impairment of sandpacks during nanofluid flooding.
Nanotechnology has contributed to the technological advances in various industries, such as medicine, electronics, biomaterials and renewable energy production over the last decade. Recently, a renewed interest arises in the application of nanotechnology for the upstream petroleum industry; such as exploration, drilling, production and distribution. In particular, adding nanoparticles to fluids may drastically benefit enhanced oil recovery and improve well drilling, such as changing the properties of the fluid, wettability alternation of rocks, advanced drag reduction, strengthening sand consolidation, reducing the interfacial tension and increasing the mobility of the capillary-trapped oil. In this study, we focus on the fundamental understanding of the role of nanoparticles on the oil-water binary mixture in a confined nanochannel. A series of computational experiments of oil-water-nanoparticle flow behaviour in confined clay nanochannels are carried out by molecular dynamics simulations. Three sizes of nanochannels and different numbers of nanoparticles are considered. The results show that the pressure to drive the oil-water binary mixture through a periodic confined channel increases dramatically with the reduction of the channel size. In the absence of nanoparticles the pressure increases with the propelled displacement. Interestingly, an opposite behavior is observed in the oil-water system mixed with a small amount of nanoparticles: the pressure decreases with the increase of the displacement. The findings from molecular dynamics simulations may elucidate the role of nanoparticles on the transport of oil in nanoscale porous media, although the exact mechanisms remain to be further explored.
Shabani Afrapoli, Mehdi (Norwegian U. of Science & Tech) | Crescente, Christian M. (Statoil Research Centre) | Li, Shidong (Norwegian U. of Science & Tech) | Alipour, Samaneh (Norwegian U. of Science & Tech) | Torsater, Ole (Norwegian U. of Science & Tech)
Microbial Improved Oil Recovery (MIOR) processes use bacteria or their bioproducts to help mobilizing additional oil from the reservoir. The chemical and physical properties of the reservoir fluids and rock are changed during the MIOR process. An extensive investigation has been carried out at laboratory temperature with dodecane and an alkane oxidizing bacterium, Rhodococcus sp 094, suspended in brine to study potential recovery mechanisms involved in the MIOR process. Flooding experiments on Berea sandstone cores and flow visualization experiments within glass micromodels have shown the effects of bacteria on remaining oil saturation. The interfacial tension reduction, wettability alteration and selective plugging are recognized as important displacement mechanisms during the MIOR process. The objectives of this paper are to present the experimental results and to evaluate the driving mechanisms of MIOR by using two simulators. ECLIPSE is used to build a model based on core parameters for simulating the core flooding process. While, COMSOL Multiphysics models the two phases flow obtained experimentally at the pore scale within the micromodels. Simulation results are consistant with the experimental results and indicate that both tools are useful to solve the simulation problems of MIOR process. The obtained results address capability and inability of simulators to model the MIOR displacement mechanisms.
Keywords: Reservoir engineering, MIOR process, Glass micromodel, Interfacial tension (IFT), Wettability, Biomass, Pore scale model, Bacteria.
Hadia, Nanji (Norwegian University of Science and Technology) | Lehne, Havard Heldal (Norwegian University of Science and Technology) | Kumar, Kanwar G. (Norske Shell E&P A/S) | Selboe, Kristoffer Andr (Baker Hughes Inc) | Stensen, Feb Åge (Norwegian University of Science and Technology) | Torsater, Ole (NTNU)
Farokhpoor, Raheleh (Norwegian University of Science and Technology) | Lindeberg, Erik G.B. (SINTEF Petroleum Research) | Torsater, Ole (NTNU) | Baghbanbashi, Tooraj (Norwegian University of Science and Technology) | Mork, Atle (SINTEF)
Sequestration of carbon dioxide in a saline aquifer into shallow marine formation of Jurassic sandstones in Svalbard has been studied on unfractured cores and by using a simplified set of geological boundary conditions. In this paper, the feasibility of storing CO2 in a fracture and matrix system in a low permeable formation is studied by performing a series of laboratory experiments under different stress conditions. Laboratory core flooding experiments were conducted on two alternative fractured and unfractured cores. Water and nitrogen were injected into brine saturated cores at the reservoir conditions. The result shows that core
plugs are very tight and the liquid permeability even for fractured core is less than 1 millidarcy. Under increased acting stress from 10 to 180 bar, the effective permeability of fractured core is reduced by 73 percent and fluid flow occurs through both fracture and matrix.
A conceptual, generic and simple 3D numerical model using commercial reservoir simulation software and available petrophysical data was used to study the CO2 injection through fracture at different overburden pressure. The effect of different overburden pressures were applied by using respective permeabilities in simulation model. Mean pressure along the cores was used to match simulation predictions with experiments results. The result shows that even though the system is water-wet, and matrix has a very high capillary pressure, CO2 flows through both fracture and matrix. The amount of CO2 that flows through the fracture is high and is reduced by increasing overburden pressure. The quantity of dissolved CO2 in brine phase reduces by decreasing overburden pressure and increasing permeability.
The faster the CO2 is flowing through the fracture less time is available for CO2 to trap as residual phase and dissolve in brine. In dipping fractured saline aquifer, CO2 plume movement in updip direction is accelerated by decreased overburden pressure and increased permeability.
Shabani Afrapoli, Mehdi (Norwegian University of Science and Technology) | Nikooee, Ehsan (Shiraz University) | Alipour, Samaneh (Norwegian University of Science and Technology) | Torsater, Ole (Norwegian University of Science and Technology)
Pore network models are powerful tools for modeling processes and phenomena occurring in porous media. These models take the advantage of capturing a realistic representation of phenomena leading to a better understanding of pore scale processes. For processes like Microbial Improved Oil Recovery (MIOR) that incorporate numerous interconnected physical and biochemical factors, a prior knowledge of the underlying mechanisms is required. A pore network model, though small, can be implemented as a platform to understand the interactions between these acting mechanisms. In the present study, a pore network is constructed based on images of small regions of a glass micromodel. The model attempts to account for microbial growth and bio-surfactant production and their effect on flow characterization within the network. The authors have previously carried out a number of visualization experiments in a transparent pore network model to study the pore scale behavior of an alkane oxidizing bacterium, Rhodococcous sp 094, suspended in brine. Dodecane and an oxidizing bacterium were examined for evaluating the performance of microbial flooding in glass micromodels.
Observations showed the effects of bacteria on remaining oil saturation, allowing us to propose the active mechanisms and also to address the problem of network morphology alteration due to microbial growth. The present work studies displacement mechanisms of an oil phase displaced by a water phase containing bacteria from the pore network modeling viewpoint. It is focused on the characterization of post MIOR morphology change for two phase flow. Consequently a methodology for incorporating major aspects of MIOR, including interfacial tension reduction, wettability alteration and profile modification into a pore network framework is introduced and developed with experimentally obtained mechanisms.