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.
Estimation of reservoir wettability and its effect on reservoir fluid flow, hydrocarbon recovery and fluid distribution has been the subject of many researches in recent years and remains one of the major challenges in reservoir characterization. This study examines the reservoir wettability in heterogeneous karstified carbonate rocks from comparison of special core analysis (SCAL) and resistivity index measurements on the core plugs, together with study of nuclear magnetic resonance (NMR) log, and formation pressure obtained by modular dynamic tool (MDT) measurements in the reservoir.
The SCAL test results present moderately water-wet reservoir conditions at the cored intervals of the reservoir. Surveys from resistivity index measurements are in general agreement with the SCAL results. Due to lack of core data in the lower/main part of the reservoir, analysis of the NMR T2 distribution are combined with MDT data to describe the reservoir wettability. The pressure data suggests a water gradient through the reservoir column except for anomalous high pressure values in which corresponds to zones with high resistivity and oil saturations. High oil saturation is not expected in zones where the reservoir has been water flooded (water level rise in the reservoir) after hydrocarbon accumulation. The study of the T2 distribution of these intervals helps to identify the oil wet nature of the larger pores in the reservoir. The surface relaxivity of oil when it wets the pore surface cause a shift in the T2 distribution towards shorter T2sC". The water volume, then, in oil wet pores relaxes as bulk relaxation with longer T2 compared to the water wet case. This study suggest that a combination of the NMR log with MDT data and resistivity logs provides a method to identify wettability characteristics of complex rocks when core plugs are missing.
Jahanbani Ghahfarokhi, Ashkan (Norwegian U. of Science & Tech) | Jelmert, Tom Aage (Norwegian U. of Science & Tech) | Kleppe, Jon (Norwegian U. of Science & Tech) | Ashrafi, Mohammad (Norwegian U. of Science & Tech) | Souraki, Yaser (Norwegian U. of Science & Tech) | Torsaeter, Ole (Norwegian U. of Science & Tech)
Thermal well testing of steam injection wells offers an inexpensive quick method to estimate flow capacity and swept volume in thermal recovery processes. Pressure falloff tests are commonly used for this purpose. Estimation of steam zone properties and swept volume from falloff test data in this study is based on the theory assuming a composite reservoir with two regions of highly contrasting fluid mobilities and the interface as an impermeable boundary. Consequently, the swept zone acts as a bounded reservoir for a short duration, during which the pressure response is characterized by pseudo steady state behavior.
The purpose of this study is to evaluate the applicability and accuracy of thermal well test analysis method and effects of different parameters on results. Pressure falloff testing is simulated using a numerical thermal simulator. The generated pressure falloff data are then analyzed to calculate swept volume and reservoir parameters. Different gridblock models are considered.
Viscosity of Athabasca heavy crude sample was measured in the lab using a rotational viscometer up to 300°C. Bitumen sample molar mass was measured by cryoscopy. Density at standard conditions was measured by a density measuring cell. These data were used as input for numerical simulation purposes.
Results of this work show that the swept volume, swept zone permeability and skin factor can reasonably be estimated from pressure falloff tests. The effects of gravity, dip, permeability anisotropy and irregular shapes of swept zones are studied. It can be seen that these factors do not greatly affect the estimated results. Results of 3D models show that the estimation of permeability and steam swept volume depends on the vertical positions where pressure data are measured. It is also found that real gas analysis does not substantially improve the calculation accuracy and the pressure analysis technique suffices for all practical purposes.
Soroush, Mansour (Norwegian U. of Science & Tech) | Wessel-Berg, Dag (SINTEF Petroleum Research) | Torsaeter, Ole (Norwegian U. of Science & Tech) | Taheri, Amir (Norwegian U. of Science & Tech) | Kleppe, Jon (Norwegian U. of Science & Tech)
After injecting CO2 into subsurface brine for storage, it will be trapped in the reservoir through various mechanisms. In the beginning, the geological trapping mechanism dominates and the CO2 plume is moving upward below a cap rock. Then brine will imbibe the formation and some parts of the CO2 will be trapped in the pore paces. Later on injected CO2 will dissolve in the brine and increases its density. As a result, the heavier brine will move into deeper parts of the reservoir and density driven convection mixing will occur. This is known as the solubility trapping mechanism.
Here in this study, density driven phenomena in CO2 storage in brine and the influencing parameters are the prime targets. We find particularly interesting results for this through Hele-Shaw cell experiments and numerical simulations. Hele-Shaw flow is defined to occur between two parallel flat plates separated by a small gap. In each experiment the cell is filled with fresh water and a shim prevents it to leak. Then liquid with higher density is placed on top. Several tests including water of varying salinity at the top of the cell have been conducted, and the results are interpreted separately and compared with the base experiment.
More extensive studies and sensitivity analysis is done based on a simulation model constructed on the reservoir properties of a brine formation, with wide range of affecting parameters, including density differences, permeability variations and the effect of diffusion coefficients. It has been also attempted to investigate the effect of anisotropy and heterogeneity on the CO2 state after injection.
Seismic history matching (HM) has attracted increasing attention the last few years. As more repeated seismic surveys are acquired, the more apparent the shortcomings in modern HM tools and algorithms become. A common conception seems to be that the amount of data represented by geophysical observations and the complexity of working with 3D fields make the updating procedure hard. We investigate the nature of geophysical observations from a HM point of view by testing several data reduction techniques such as Principal Component Analysis (PCA), regression techniques such as forward stepwise, as well as state-of-the-art techniques based on neural networks. We argue that simulated geophysical fields from the prior models are prone with spatial correlations and that their information content and effective dimensionality is much smaller than the dimensionality of the observed field. The techniques are tested on a reservoir model of an anonymous North Sea oil field, using the seismic time shift, i.e. the difference travel time integrated over the reservoir between two surveys. We find that PCA is particularly promising, resulting from the versatility and robustness of the method. In practice this means that high dimensional geophysical data, e.g. 2-D seismic images or 3-D seismic cubes, can often be described using only a handful of scalars. We show how to assess the information content in the data, compress the data, and use this compressed data in a reservoir conditioning setting. The methods we present are generic; they apply equally well to all geophysical attributes regardless of representation and can be applied with any history matching algorithm, although they are mainly designed for ensemble based techniques.
CO2 sequestration in deep formations is being actively considered for the reduction of greenhouse gas emissions. Saline aquifers are considered as one of the most favorable options for this purpose. It has been observed that dissolution of CO2 into brine causes increased density of the mixture. If the corresponding Rayleigh number of the porous medium is high enough to initiate convection flows, density-driven-convection happens and the rate of dissolution increases. Early time dissolution of CO2 in brine is mainly dominated by molecular diffusion while it will be accelerated by density-driven-convection. More contribution of dissolution mechanism for trapping of CO2 decreases the risk of leakage.
Density-driven-convection mechanism was investigated in a Hele-Shaw cell with colored-brine and fresh-water instead of CO2-diffusive layer and brine. A convective instability is created by colored-brine diffusing onto the surface of a fresh-water layer. For this configuration, density-driven-convection flow enhances the mass transfer rate of high density fluid into the low density one. The analysis is also done numerically with Eclipse reservoir simulation software. With this analysis, the effects of density-driven-convection on accelerating the rate of dissolution are investigated. Although the horizontal wavelength of the initial instability is small, an increase in the horizontal wavelength of the convective flow with time and depth is observed as the resulting two-dimensional convection develops. Effects of density of fluids and also dip of the systems on convection flows are studied here. Also the changes in geometry of the convection streams with depth and time are investigated. The results have important implications in dissolution trapping of CO2 in brine aquifers.
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.
In this study, different scenarios of CO2 injection in dipping gas condensate and oil reservoirs are investigated through reservoir simulations. Both miscible and immiscible flooding conditions were investigated for a range of different injection gas mixtures, and geological realizations.
We find particularly interesting results for miscible flooding of gas condensate systems below dewpoint pressure. Here, dropped out condensate is the prime target for enhanced recovery projects and multi-contact miscibility could develop through the combined condensing/vaporizing mechanism.
Different patterns of permeability variation with depth in layering scenarios with dip angle showed distinct different responses on produced condensate. CO2 WAG in partially depleted gas condensate reservoirs seems to have the same value of oil recovery in early times, but ultimate recovery is different according to layering heterogeneity. In the case of pure CO2 injection, both up-dip and down-dip, it was found that homogeneous layering showed highest recovery. Here developed multicontact miscible oil-bank is able to move and sweep condensate above it easier. Applying various gas injection mixtures of CO2 and C1 combinations, the effect on ultimate recovery were studied. In this case CO2 injection is above minimum miscibility pressure (MMP) resulting in high recoveries.
CO2 WAG in dipping oil reservoir was also studied extensively, based on injection pattern, MMP values and various layering systems. CO2 WAG in scenarios with increasingly trend of permeability with depth had the highest value of recovery. This is because of prevention from early gas breakthrough in upper layers and good sweep efficiency in lower layers. Pure CO2 injection with total same injection volume showed lower recovery. This may verify that gravity in WAG water injection period is the most effective parameter in the case of down-dip WAG.
This paper presents a method to eliminate production loss due to liquid-loading in tight gas wells. Cyclic shut-in control is a simple production strategy that particularly benefits lower-permeability stimulated wells, including but not limited to shale gas wells.
Comparison is made between a gas well producing (1) in a "ideal?? situation where 100% of liquids entering from the reservoir or condensing in the tubing are continuously removed (without shut-ins), (2) in a meta-stable liquid-loading condition with low gas rate, typical of most wells today, and (3) by the proposed strategy of cyclic shut-in control. We show that cyclic shutin control of stimulated low-permeability vertical wells to ultra-low-permeability horizontal multi-fraced wells can produce without ever experiencing liquid loading, and with little-to-no delay of ultimate recovery.
Cyclic shut-in control can be applied to all stimulated, lower-permeability gas wells, from the onset of gas rates that result in liquid-loading. The strategy can also be used for wells which already have experienced a period of liquid-loading , but the expected performance improvement may be less because of near-well formation damage caused by historic liquid-loading - e.g. fresh-water backflow and liquid-bank accumulation. In historically liquid-loading wells, an initial period of liquid removal and/or light stimulation may be needed prior to initiating cyclic shut-in control.
We show that the shut-in period should optimally be as short as operationally possible.
Cyclic shut-in control is shown to work equally well for layered no-crossflow systems with significant differential depletion at the onset of liquid loading.
Minimizing rate and recovery loss of liquid-loading gas wells is of international interest. We believe that cyclic shut-in control will become an industry standard practice for shale gas wells, and should lead to a significant ultimate increase in worldwide gas reserves. The method is extremely simple and requires only a rate-controlled wellhead shut-in device.
Every gas well will, at some point in its life, reach a condition where the gas rate is insufficient to carry co-produced liquids to the surface. These liquids may flow from the reservoir, or condense out of the produced gas on the way from bottomhole to surface. The liquids may be condensed water, free water, condensate or oil. After this condition is reached, some fraction of the produced liquids will flow counter-current to the gas, and accumulate in the bottom of the well. As liquids accumulate, the backpressure on the formation increases. This results in a sharp reduction in the gas production rate, and in the worst case the well might die completely. A more common result of liquid-loading is that the well stabilizes at a lower production rate, called the "meta-stable rate??, a term introduced by van Gool and Currie (2007). Fig. 1 shows a gas well that illustrates the impact of liquid-loading. A sharp drop in production is seen when the well reaches a gas rate of about 200 Mcf/D (typical for 2-3/8?? tubing), eventually stabilizing at a meta-stable rate of about 20 Mcf/D for some 20 years.