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IOR 2017 - 19th European Symposium on Improved Oil Recovery
- Conference date: April 24-27, 2017
- Location: Stavanger, Norway
- Published: 24 April 2017
61 - 80 of 139 results
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Experimental Investigation of Inorganic Scale Deposition during Smart Water Injection - A Formation Damage Point of View
Authors J. Ghasemian, R. Mokhtari, S. Ayatollahi, S. Riahi and E. MalekzadeSummarySmart water injection is determined as an effective EOR process to change the wettability and interfacial tension for better micro/macro sweep efficiencies. This water contains reactive ions such as Mg ^(2+), Ca ^(2+) and SO _4 ^(2-)which can act as potential determining ions and change the surface charge of calcite rocks. One of the major concerns in the execution of an effective waterflood, especially in tight carbonate reservoirs, is the incompatibility between the formation brine and the injecting water. This research work aims to investigate the most important challenge of waterflooding process related to the possible formation damage because of inorganic scale deposition during experimental smart water injection. At the first stage, sea water as the basis for smart water were prepared to examine the impact of determining ion such as Mg ^(2+), Ca ^(2+), and SO _4 ^(2-)and the salinity of the injected brine on total amount of CaSO _4 precipitation. The tests were performed to find the effects of each ion at static and dynamic conditions. According to the obtained results, as the concentration of SO _4 ^(2-) in the injecting water increases from 1/4 to 1 times of its concentration in ordinary sea water, the CaSO _4 deposition increases smoothly, which was accelerated beyond that. Hence, as the increasing of the sulfate concentration improved the wettability alteration ability of the smart water, however calcium sulfate deposition was noticed which make permanent formation damage. Besides, the test results showed that CaSO _4 deposition increases smoothly as the concentration of Ca ^(2+) in the sea water increases. On the contrary, the presence of Mg ^(2+) ion in the sea water, increases the solubility of CaSO _4 and subsequently, lower scale formation was noticed by increasing the concentration of magnesium. This study also showed that, there is an optimum salinity (5 times dilution in sea water salinity) in which the minimum amount of CaSO _4 is deposited. The findings would enable us to optimize the ion contents of smart water for both, better oil sweep efficiency and lower risk of formation damage.
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A New Frontier Technique for Nano-analysis on Flooded Chalk - TERS (Tip Enhanced Raman Spectroscopy)
Authors L. Borromeo, M. Minde, C. Toccafondi, U. Zimmermann, S. Andò and R. OssikovskiSummaryUnderstanding the chalk-fluid interactions at the sub-micron scale is one of the most challenging goals in Enhanced Oil Recovery. The grain size of newly grown minerals far below 1 micron asks for a high performing imaging: we present a new methodology using the TERS (Tip Enhanced Raman Spectroscopy), a new frontier technique that combines Raman Spectroscopy with Atomic Force Microscopy, allowing impressively high-resolution chemical analyses down to an outstanding spatial resolution (~ 20 nm). TERS permits the recognition of minerals thanks to the vibrational mode peaks that are diagnostic of composition and structure. Carbonate-group minerals are easily identified by Raman spectroscopy. First analyses allow us to state that magnesite and calcite could be identified in, respectively, ultra-long-term flooding experiments of chalk at reservoir conditions and in unflooded samples; no dolomite or high Mg-calcite have been found. Few microns squared areas have been imaged by AFM using ultra polished thin sections with a 50 nanometers step.
Transmission electron microscopy has been employed to confirm the results of TERS and add dark and bright field grain-imaging to the investigations.
This confirms the need for high-resolution methodology such as TERS and TEM to fully understand EOR effects at sub-micron scale.
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Water-blocking Solution Based on Emulsion with SiO2 Nanoparticles Content for Reservoir Stimulation Technologies
Authors V.V. Sergeev, Y.V. Zeigman and F.S. KinzyabaevSummaryA significant part of existing oilfields are in late stage of development,it’s leading to problems with high water cut and reduction in hydrocarbon production. One of the main reason is water break-through from high permeability reservoir intervals. In this regard,one of the most important object of IOR methods is to enhance efficiency of water-blocking solutions. Into the object the main task is developing high effective solutions for selective blocking high-permeability water-bearing intervals and involvement low permeability oil-saturated intervals into production.
Results of wells operation monitoring are presented in article. The technology based on application of emulsion for selective blocking water-bearing intervals into reservoir. On the results of 6 months wells monitoring data analysis,treated due oilfield tests were determined that the technology allowed to decrease water-cut on 10% and increase oil production twice.
On the results of carried out by lab research it was proposed to improve provided technology by applying emulsion with SiO2 nanoparticles content. Physicochemical properties of new emulsion solution better in rheology and stability in compare with standard emulsions and its might increment the time of technological efficiency. The lab research showed that the addition of SiO2 nanoparticles allows reach better physicochemical properties both hydrophilic and hydrophobic type of emulsions.
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Gravity Override and Vertical Sweep Efficiency in Dipping Reservoirs
Authors G.Y. Yu, M.N. Namani, J.K. Kleppe and W.R. RossenSummaryThe model of Stone (1982) and Jenkins (1984) predicts the extent of gravity override at steady state during gas-liquid co-injection in an enhanced oil recovery (EOR) process. The model is accurate for WAG injection if the slug sizes are sufficiently small. The model is exact for homogeneous reservoirs if the standard assumptions of fractional-flow theory apply ( Rossen and Van Duijn, 2004 ). Stone and Jenkins relate the distance to complete gravity segregation to total mobility in the mixed zone and the thickness of the override zone beyond this point to mobilities in the override and underride zones.
Namani et al. (2012) and Jamshidnezhad (2009) have proposed extensions to Stone and Jenkins’ model for dipping reservoirs. The accuracy of these correlations were tested in this study for a wide range of conditions and angle of reservoir dip using 2D computer simulations. Both correlations are approximately correct, but deviate from observed behaviour at large dip angle. Specifically, gravity override occurs at shorter distances than predicted by Namani et al. for up-dip injection, but longer distances for down-dip injection at moderate dip angles. Jamshidnezhad’s correlation works reasonably well for down-dip injection except at large dip angles, for which segregation occurs at much shorter distances than predicted. Much of the sweep of gas occurs not at steady-state, however, but during the transient period before steady state is attained. During the period of three-phase flow, mobilities are lower; as suggested by Stone’s approach, this temporarily extends the mixed zone beyond that at steady state. In up-dip injection, the override zone is extended much deeper into the reservoir during the period when gas first enters than at steady state. The oil swept during this period can greatly exceed that represented in the mixed zone in any of these models: even though the mixed zone is reduced, overall sweep can be greatly increased by this effect. This extension of the override zone during transient flow follows the logic of Jenkins’ derivation of the thickness of the override zone based on mobilities.
Unfortunately, there is no single exact equation for gravity segregation in dipping reservoirs as for horizontal reservoirs, even at steady state. Therefore behaviour varies somewhat from case to case.
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Uncertainties - Extension of Smart Waterflooding from Core to Field Scale
Authors T. Kadeethum, H.K. Sarma, B.B. Maini and C. JaruwattanasakulSummarySmart waterflooding has emerged as an EOR process of much interest in recent years. Much research is being reported, along with a few successful field applications, notably clastics. In most cases, there are undeniable inconsistencies in results between lab and field cases. This leads to unpredictable outcomes and misleading profit prediction of smart waterflooding projects. The objective of this work is to evaluate uncertainties in smart waterflooding from core- to field-scale.
Kozaki (2012) experiment is mimicked by 1-D numerical model that couples with geochemical reactions. Validation results show that there are many combinations of matching parameters that can describe coreflooding results. Each realization may lead to different results when extended to 3-D heterogeneity model. Hence, to cover ranges of uncertainties, many realizations should be tested before summarizing smart waterflooding performance.
Full-field heterogeneity model also shows that smart waterflooding is sensitive to grid size and heterogeneity. With different grid volume settings, results vary dramatically. This may contribute towards smart waterflooding misinterpretation. Furthermore, heterogeneity alters smart waterflooding within a particular range by affecting cation exchange capacity, and subsequently interpolant value, which is used to represent system wettability. Therefore, these parameters should be accounted in field-scale simulation to obtain smart waterflooding true potential.
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Water Ion Interactions at Crude Oil-water Interface - Is there a Correlation between IFT and Interfacial Rheology?
Authors S.C. Ayirala, S.H. Saleh, A.A. Yousef, Z. Li and Z. XuSummarySmartWater flooding (SWF) through the injection of optimized chemistry waters is getting good attention in recent years for improved oil recovery (IOR) and enhanced oil recovery (EOR) in carbonate reservoirs. Consequently, much of the research conducted so far in this emerging area has been limited to studying salinity and water ion interactions at carbonate rock-crude oil-water interfaces. Favorable wettability alteration has been seen to play a major role on oil recovery based on measurements such as contact angle and zeta potential; however, the other important aspect of characterizing water ion interactions at crude oil-water interface has received little attention. In this study we performed interfacial shear rheology measurements to study water ion interactions at crude oil-water interface and compared these results with the previously reported IFT data. The major objectives are to determine the impact of different water ions on the viscoelastic properties of crude oil-water interface as well as to explore the correlation between IFT and interfacial rheology. Several low salinity SmartWater recipes with varying individual ion compositions were used in these experiments.
The data indicated noticeably higher IFT values for SmartWater recipes containing sulfate ions, while IFT was the lowest for SmartWater composed of magnesium ions. In contrast, SmartWater with only sodium or calcium ions displayed almost similar IFT values. Interfacial shear rheology results showed significantly higher viscous and elastic modulus for SmartWater recipes comprising of sulfate ions. The SmartWater recipes with sodium-only, calcium-only or magnesium-only ions showed comparable interfacial rheology. The transition times for the interface to become elastic-dominant from a viscous-dominant regime are found to be the lowest for sulfates-only brine followed by the sodium-only and calcium-only brines, and the highest being with magnesium-only brine. The much quicker transition times to elastic regime observed with sulfates-only brine indicates rigid skin at the interface that could potentially delay the destabilization of the interfacial film and hinder the coalescence between oil droplets. The longer transition times to elastic regime observed with magnesium-only brine shows the presence of less rigid films at the interface to promote the coalescence between oil droplets. A good correlation between IFT and the interfacial film transition times from viscous to elastic-dominant region was observed for all the brines, which confirms that similar sensitivity of water ions is reflected in both the parameters. These novel findings on the microscopic scale interactions of different water ions at crude oil-water interface pointed out the importance of magnesium and calcium ions in the SmartWater to enhance the coalescence between released oil droplets to quickly form oil bank in the reservoir for faster recovery.
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Produced Water Treatment with Membranes for Enhanced Oil Recovery in Carbonate and Sandstone Reservoirs
Authors R. Nair, E. Protasova, S. Strand and T. BilstadSummaryThe research is focused on determining the technical performance of membranes for treating and reinjecting produced water (PW). Ionic composition of pre-treated PW containing 90,000 ppm total dissolved solids (TDS) is manipulated by membrane separation and reinjected as smart water in carbonate and sandstone reservoirs. Nanofiltration (NF) membranes coupled with reverse osmosis (RO) membranes are tested in this research. TDS of less than 5,000 ppm with negligible divalent ions is defined as Smart Water for sandstone reservoirs. High divalent ion concentrations with TDS typically above 10,000 ppm compose Smart Water for carbonate reservoirs.
The performance of NF membranes at different pH of PW is evaluated at various pressures. An economic analysis is performed for different combinations of membranes with TDS of 90,000 ppm as reference. A combination of two NF membranes are used to produce Smart Water for carbonate reservoirs. The power consumption is calculated at 0.37 kWh/m3. PW reinjection in sandstones with TDS of 5,000 ppm require either the use of permeate from RO or supplying fresh water by other means for diluting permeate from NF. A power consumption of 14.8 kWh/m3 is calculated for the combination of two NF membranes and RO for Smart Water production for sandstones.
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Effects of Potassium Ion on Low Salinity Waterflooding in Sandstone Formation
Authors F. Srisuriyachai, S. Meekangwal, C. Charoentanaworakun and Y. VathanapanichSummaryMulti-Component Ion Exchange (MIE) is a mechanism that has been proven to take place during low salinity waterflooding. In sandstone surface, oil containing organic acid may be attached onto rock surface through an aid of divalent ion binding. Substitution of monovalent ion onto the linking divalent ion site results in liberation of oil. Minimum quantity of divalent ion such as Calcium ion and Magnesium ion together with presence of monovalent ion in injected brine would be therefore favorable conditions for the MIE mechanism.
In this study, spontaneous imbibition test is performed to observe ability in replacement of monovalent ion by excluding effect from injection rate. Formation brine is prepared to have total salinity of 100,000 ppm, using an average ion proportion from sandstone oilfields around the globe. Effects of Potassium ion which is much smaller in quantity in brine and seawater compared to Sodium ion, is investigated. From the experiment, Potassium Chloride solution at 35,000 ppm can imbibe into rock sample with total increment of water saturation of 0.42, whereas Sodium Chloride solution at the same salinity can only increase water saturation of about 0.27. Potassium ion is usually accompanied by 1–4 molecules of water, whereas Sodium ion is surrounded by 5–11 molecules. This causes hydrated Potassium to be smaller in size and more active in replacing divalent ion compared to hydrated Sodium. Lowering concentration of Potassium Chloride to 5,000 ppm shows an adverse effect on imbibition ability. As number of active monovalent ion is reduced, replacement of divalent ion occurs slowly. As a result, only 0.24 of water saturation is increased from initial water saturation. Comparing to seawater at the same total salinity which contains Potassium ion only 369 ppm, seawater imbibes at higher degree compared to solely Potassium Chloride which is about 0.47 of water saturation. This can be explained that, adequate total salinity could favor Potassium ion to approach the surface. Moreover, presence of Calcium ion would help induce liberation of oil through formation of Calcium Carboxylate complex. Last, seawater without Potassium ion is prepared to confirm effect of Potassium ion and it is observed that 0.40 of water saturation is increased during the test.
In summary, Potassium ion is more potential in replacing divalent ion compared to Sodium ion. A presence of only small quantity of Potassium ion is adequate for spontaneous imbibition as this can be offset by presence of other potential ions.
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Effect of Mud Invasion on the Determined Low Salinity Water Flooding Potential
By I. FjeldeSummaryLaboratory experiments with reservoir rock samples should give input to estimation of the potentials of recovery methods. The potential for low salinity water flooding (LSWF) of sandstone oil reservoirs has been reported to depend on the amount of clay and their surface properties. The objective for the reported study was to investigate the effect of KCl water-based mud invasion on the determined LSWF-potential. The wettability of minerals and a sandstone reservoir rock was characterized by flotation tests using two brines (formation water (FW) and mud brine) and two stock tank oils (STOs). During preparation of sandstone reservoir core plugs, effluent samples were analyzed for element compositions to determine whether they were contaminated with KCl mud. Unsteady-state flooding experiments with sea water (SW) and low salinity water (LSW) were carried out in these core plugs. Core plugs were analyzed by scanning electron microscopy (SEM) both after cleaning with solvents and after water flooding experiments. Bentonite consists mainly of montmorillonite clay and is added to water-based muds for rheology and filtration control. In the flotation tests, this clay was found to be less water-wet than the dominating minerals in the original reservoir rock. Rock samples with bentonite invasion can therefore become more oil-wet than the original rock. The mud brine was also in the flotation tests found to give more water-wet reservoir rock than the FW. High permeable sandstone reservoir core plugs were during preparation found to be contaminated by the KCl mud brine. Chemical analyses confirmed that this brine was removed during cleaning of the core plugs. In some cases, production of emulsions was observed during LSWF. These emulsions may have been stabilized by bentonite contamination. The water flooded core plugs were by SEM-analysis found to contain clusters of barite and clay and also polymer. This means that all mud components were not removed by using the standard core cleaning procedure. It was not possible to conclude anything about the LSWF-potential for the studied reservoir rock, because the core plugs were contaminated by mud components that may have affected the determined LSWF-potential.
Mud contamination of the reservoir rock can affect the permeability and the established wettability conditions. Invasion of bentonite clay will increase the cation exchange capacity, and this can affect the determined LSWF-potential. It should therefore be confirmed that mud components that can affect the established flow conditions, are removed during core preparation.
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A Novel Characterization of Effective Permeability of Tight Reservoir - Based on the Flow Experiments in Microtubes
More LessSummaryIn tight reservoirs, as throat radius decreases to micro-nano scale, pore structure becomes more complex. The effect of interaction between seepage fluids and rocks increases, which changes flow characteristics in micro scale. In order to realize efficient development of tight reservoirs, the throat distribution and permeability needs new understanding.
In this paper, a device was established to measure water flow rate in microtubes, under different pressure gradient. The water was de-ionized and tubes were made of fused silica with radius of 1, 2.5, 5, 7.5, 10 and 15μm. The pressure gradient was set mainly 0.02~0.6MPa/m, close to that in oilfield, while previous published experiments focused on 1~80MPa/m. The results showed that experimental flow rate was lower than theoretical value calculated by Poiseuille equation. A stable boundary layer was formed near the solid wall, blocking the flow. Its thickness was calculated, ranging 29.6nm~ 1.08μm. As pressure gradient increased, the boundary layer declined and its effect vanished. This change led to nonlinear flow characteristics in micro scale. The thickness increased with throat radius increasing and reached a constant value when tube radius were larger than 15μm.
Based on experimental results, a boundary layer thickness function was regressed. The independent variables were pressure gradient, throat radius and viscosity. Considering boundary layer, the effective throat radius distribution was characterized, taking normal distribution as the original distribution. The results showed that the range of effective throat distribution was narrower than the original one and the peak value was higher. The sensitivity of the function was analyzed.
Based on the characterization of effective throat distribution, the formulas of Klinkenberg permeability and effective permeability were derived. The effective permeability formula was validated using data from Shiwu and Bohai oil reservoir. The deviation is lower than 6%.
The effective permeability of tight reservoir under different conditions was calculated and investigated. The larger the median radius and the range of the throat distribution, the higher the effective permeability. The effective permeability of a core is not determined only by its pore structure. It is also effected by pressure gradient and the properties of the fluids. When the pressure gradient increases, the effective permeability increases as the boundary layer declines. When the fluid viscosity increases, the effective permeability decreases.
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Petrological, Mineralogical and Geochemical Constraints on Hydrocarbon Bearing North Sea Reservoir Chalk
Authors E.I. Kallesten, U. Zimmermann, M.V. Madland and M.W. MindeSummaryA study of the geochemistry and petrology characterizing the North Sea reservoir chalk is central in the efforts of refining or developing new Increased Oil Recovery (IOR) methods, as it provides an insight in the chemical composition, mineral structures and textures of the reservoir rock and the grounds for a pilot test within the National IOR Centre of Norway. The study is based on cores collected over a decimeter-scale, under different flooding status, from unflooded to waterflooded at lower or higher temperatures, swept and unswept regions from the Tor and Ekofisk formations directly sampled from the Ekofisk field. Optical petrography shows a very fine, micritic carbonate matrix, with various microfossils such as calcispheres, foraminifers, or sponge spicules. SEM micrographs reveal post-depositional calcite precipitation inside the calcispheres, sometimes entirely cementing their cavities. The amount of clay minerals observed with SEM varies and there is a clear decrease in porosity stratigraphically downwards, along with more cementation and compaction. X-ray diffraction confirms calcite as most abundant in the whole-rock composition, with quartz and few other non-carbonate minerals like smectite, illite and kaolinite present. The silica content varies highly from <2 wt% in the shallower cores to 6 – 8 wt% in areas close to tight zones and up to 11 wt% in the deeper cores. δ13C and δ18O are lower than the secular global isotopic values for this period. Since similar disturbed stable isotope values are seen in other hydrocarbon-rich samples unexposed to any fluid for IOR purposes, the disturbance is assigned to a post-depositional diagenetic overprint, or to the influence of a secondary fluid of unknown origin, rather than the effect of the cores’ flooding status.
Given the compositional variety of the Ekofisk reservoir rocks, selecting a single on-shore exposure as a standard equivalent for the Ekofisk chalk would be problematic. The complexity of the reservoir chalk and consideration of many other IOR influencing parameters, compel caution when transferring results from the onshore chalk modeling to the reservoir chalk (e.g. Hjuler and Fabricius, 2009 ). Beside the mineralogical composition of chalk strongly influencing compaction, the palaeo-environmental conditions at the time of deposition, the diagenetic history, calcite recrystallization and fossil preservation may affect the strength of the rock. Hence, a further thorough geological study on the reservoir chalk is necessary to verify the prospect of comparisons based on geological grounds.
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Physical Modeling of Rheological Properties of Polymer Solutions for Enhanced Oil Recovery
Authors D. Shogin, P.A. Amundsen, A. Hiorth and M.V. MadlandSummaryWe review the FENE-P dumbbell model of diluted polymer solutions, based on molecular dynamics. Although simplified, this model has proven to be a useful tool for qualitative and quantitative studies of non-Newtonian fluids.
It is demonstrated that under reasonable assumptions, the equations of fluid dynamics with the FENE-P constitutive equations can be solved analytically for some simple flows. In this report, we obtain and investigate the analytical solutions for laminar flows of FENE-P fluids in straight circular tubes and slits of constant width. This includes the expressions for the velocity and shear rate profiles, volume flow rates, pressure gradients, stress tensor components, and viscometric functions. The results are formulated in a manner allowing their direct practical use. A connection to several relations utilized by petroleum engineers is established.
The solutions are generalized to describe the flow through capillary bundles and grids consisting of multiple slits --- these can be thought as a simplified model of porous media. We explain why the behaviour of polymeric fluids in such media is essentially different from that in a single tube or slit, and demonstrate how this difference can be accounted for, if the pore size distribution is known.
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Scale Risk Management during CO2 WAG in Carbonate Formations
Authors A.S. Ribeiro, E.J. Mackay, L.J.N. Guimarães, M. Jordan and S. FellowsSummaryIn this work we have used commercial software to perform reactive transport simulations of CO2 WAG injection in an oil reservoir, with the objective of assessing the scaling risk associated with CO2 EOR in carbonate formations. Higher WAG ratio promotes faster mineral reactions and severe scale deposition at earlier times. Injection of cooler fluids also enhances calcite and CO2 dissolution in water near the injector wellbore. Finally, the mass of calcite around the producer wellbore changes due to three different mechanisms: (a) brief dissolution caused by arrival of the CO2-rich front, (b) re-precipitation caused by mixing between high HCO3 injected water with high Ca formation water and (c) continuous precipitation caused by evolution of CO2 along the flow path, which occurs continuously after CO2 breakthrough. The results of these calculations allow the critical location where scale damage could occur within a production system to be identified, and a mitigation strategy developed to control its formation, for example via continual injection of scale inhibitor down to the production packer in early field life, reducing the need for batch inhibitor (squeeze) treatments into the reservoir in later field life, thereby significantly reducing OPEX.
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Improved Modeling of Gravity-Aided Spontaneous Imbibition Using Momentum-Equation-Based Relative Permeabilities
Authors P.Ø. Andersen, Y. Qiao, S. Evje and D.C. StandnesSummaryIt is well known that relative permeabilities (RPs) can vary depending on the flow configuration and are lower during counter-current flow as compared to co-current flow.
In this paper we use a novel two-phase momentum-equation approach to generate effective RPs where this dependence (and others) is well captured whereby the fluids transfer momentum due to fluid-rock interaction and fluid-fluid interaction.
During co-current flow the faster moving fluid accelerates the slow fluid, but is itself decelerated, while for counter-current flow they are both decelerated.
We investigate recovery of oil from a matrix block surrounded by water due to a combination of gravity drainage (GD) and spontaneous imbibition (SI), relevant for fractured reservoirs.
In capillary-dominated systems the flow is counter-current and viscous coupling can result in increased time scale of the recovery process.
During gravity-dominated flow it is more co-current and applying co-currently measured relative permeabilities from the lab becomes a better assumption.
Using one set of parameters the momentum-equation approach is thus able to model the behavior of blocks of different operating at different Bond numbers in the reservoir.
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An Analytical Model for Analysis of Centrifuge Capillary Pressure Experiments
Authors P.∅. Andersen, S.M. Skjæveland and D.C. StandnesSummaryPrimary drainage with centrifuge is considered where a core fully saturated with a dense wetting phase is rotated at a given rotational speed and a less dense, non-wetting phase enters. The displacement is hindered by a positive drainage capillary pressure and equilibrium is approached with time. We present general partial differential equations describing the setup and consider a multi-speed drainage sequence from one equilibrium state (at a given rotational speed) to the next.
By appropriate simplifications we derive that the process is driven by the distance from equilibrium state as described by the capillary pressure at the inner radius and position of the threshold pressure (transition from two to one-phase) from their equilibrium values.
Further, an exponential solution can describe the transient production phase.
Using representative input saturation functions and system parameters we solve the general equations using a commercial software (Sendra v2016.1) and compare with the predicted exponential solutions. It is seen that the match is excellent and that variations in time scale are well captured.
The rate is slightly underestimated at early times and overestimated at late times, which can be related to changes in total mobility during the cycles for the given input.
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Reflection of Processes of Non-equilibrium Plastic or Two-phase Filtration in Oil-saturated Hierarchic Medium
Authors O.A. Hachay, O.Y. Khachay and A.Y. KhachaySummaryA comparison is provided of non-equilibrium effects of the influence of independent hydrodynamic and electromagnetic induction on an oil layer and the medium which it surrounds. Using the earlier developed 3-D method of induction electromagnetic frequency geometric monitoring, we showed the possibility of defining the physical and structural features of a hierarchic oil layer structure. For description of these effects it is needed to consider the wave process in the hierarchic blocked medium. Some algorithms were constructed for 2-D modeling of sound diffraction on a porous fluid-saturated intrusion of a hierarchic structure located in the layer number J of an N-layered elastic medium, for 2-D modeling of sound diffraction and propagations of transversal wave in the layer number J of an N-layered elastic medium with plastic inclusion. These algorithms present the strong mathematical theory for modeling and interpretation of acoustic wave propagation using a model more adequate to the real medium with oil and gas. It can be used as a base for constructing new methods of seismic monitoring for receiving results of choosing better places for oil recovering. Some analogues ideas are fulfilled in the electromagnetic case by recovering rocks in the rock shock mines.
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Induced Shear Failure by Temperature Reduction at Uni-axial Strain Conditions
Authors T. Voake, A. Nermoen, R.I. Korsnes and I.L. FabriciusSummaryThis study improvises uniaxial strain condition during cooling by keeping constant overburden, and adjusting radial stress at cooler temperatures in order to re-establish the same radial dimensions prior to cooling. The amount of radial stress reduction by thermal contraction could be sufficient to trigger shear failure. Experiments are performed on Mons chalk and Kansas chalk so the role of induration can be assessed. Calcite thermal expansion is highly anisotropic. Weakening caused by temperature fluctuation could give insight to what gives chalk its strength, cementation, or repulsive electrostatic forces. For each chalk type, shear failure line is determined. The samples are heated to 90oC and loaded to 70% of the axial stress required to induce shear failure. Then the temperature is reduced by 60°C. The change in confining pressure necessary to restore zero radial strain is estimated. The two chalks show different behaviour. Mons demonstrates this cooling would induce shear failure, but has no significant effect on its strength. Kansas, is able to restore uniaxial strain conditions without shear failure. The strength of the Kansas sample was unaffected, however the change in confining pressure needed to restore the uniaxial strain condition decreased with each additional cycle, indicating changing elastic properties.
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Elastic and Plastic Behavior of Chalks at Deviatoric Stress Condition: Experiments Performed with Four Different Brines
Authors J.S. Sachdeva, A. Nermoen, M.V. Madland and R.I. KorsnesSummaryThis paper deals with exploring elastic (bulk modulus and Young’s modulus) and plastic parameters (yield stress, creep and rebound) during deviatoric loading and time-dependent deformation. A series of experiments were carried out at Ekofisk reservoir temperature (130°C) to study the effect of four different fluids, viz., distilled water (DW), NaCl-brine, MgCl2-brine and seawater (SSW), on Mons outcrop chalk. The cores were deviatorically loaded and left to creep at a constant value of 69–73% of the axial yield stress obtained from reference tests with the same brine. Variations in the bulk modulus and Young’s modulus were observed as function of saturation fluid, although the significance of these observations require more data. SSW had the lowest yield stress followed by NaCl and MgCl2, and highest for DW, which conforms the results from earlier studies. The final creep strain was highest for SSW and was 1.3–1.5 times higher than for other brines. The core initially saturated by SSW showed the highest plastic component of the total strain inferring that the ions in SSW does play an important role in inducing permanent damage.
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Comparative Studies of Mineralogical Alterations of Three Ultra-long-term Tests of Onshore Chalk at Reservoir Conditions
Authors M.W. Minde, S. Haser, R.I. Korsnes, U. Zimmermann and M.V. MadlandSummaryTo understand the alterations in geomechanical and mineralogical properties of reservoir chalk injected with seawater, countless experiments have been carried out through decades of research at UiS. Several parameters are varied to understand how these parameters impact fluid-flow, rock-fluid interaction and compaction, which is an important drive mechanism for Enhanced Oil Recovery (EOR). Identification of mineralogical alterations is crucial input to modelling and simulation of EOR methods.
We present the results from flow through experiments on Liège chalk from three ultra-long-term tests. The core were flooded with MgCl2 at reservoir temperature (130°C) and hydrostatic stresses above yield (9.5, 10.4 and 12.6 MPa), with one core was flooded for a short period with a mixture of MgCl2 and CaCl2, and with MgCl2 brines at different pH, ~2.7, ~5.7 and ~9.
The studies based on Mineral Liberation Analyzer and Transmission Electron Microscopy show two fronts moving through the cores at different velocities. The first alterations are partial dissolution of calcite with precipitation of secondary minerals like high-magnesium carbonate and clays, followed by fronts of complete transformation to the Mg-rich mineral. Random calcium impurities (<4wt%) are present in all analysed magnesite crystals. In addition, precipitation of Si-Mg-bearing clays is observed throughout all flooded cores.
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Wettability Characterization Using the Flotation Technique Coupled with Geochemical Simulation
Authors S. Erzuah, I. Fjelde and A.V. OmekehSummaryWettability controls the distribution of fluid phases and flow properties in oil reservoirs. Wettability characterization can be accomplished using standard techniques such as Amott-Harvey and USBM. Nevertheless, these experiments are time consuming and limited numbers are carried out for each oil reservoir. The objective is to evaluate the possibility to use the flotation technique combined with geochemical simulations for fast wettability characterization.
The flotation technique relies on the affinity of the minerals to either the brine or the oil, and was used to characterize the wettability of minerals. The amounts of oil-wet particles is determined for the mineral-brine-oil mixtures after aging the mineral in brine and oil respectively. Two formation water compositions and two stock tank oils were selected for the flotation experiments. As an introduction to this study, the wettability of six (6) minerals found in sandstone reservoir rocks were investigated by flotation test. The mineral-brine interactions such as solubility and surface complexation of minerals were modelled with the geochemical simulator PHREEQ-C, and the results were compared with their experimental counterpart. The flotation tests showed that the crude oils altered the wettability of some of the water-wet minerals to oil-wet. It was inferred that the clay minerals were less water-wet. Calcite with cationic surfaces, became more oil-wet by aging with crude oil, and this indicated direct adsorption of carboxylic acids.
Surface Complexation Modelling (SCM) results reveal that the surface charges of both quartz-brines and STOs-brine are mostly negatively charged and hence electrostatic repulsion exist between the two interfaces leading to lack of oil adhesion. Unlike quartz, the calcite-brine and the STOs-brine interfaces were positively and negatively charged respectively. Hence, direct adhesion of the polar oil components onto the calcite surface is the reason for the high oil-wet nature of calcite. This was also consistent with the total bond product which expresses the tendency of oil adhesion onto minerals surfaces. The total bond product for calcite (0.95 – 1.06) was greater than quartz (0.01 – 0.07) and hence confirming that more oil was adsorbed on the calcite surface unlike quartz. Both the SCM and the flotation test results reaveal that the calcite is strongly oil-wet while quartz is strongly water-wet.
The flotation technique combined with geochemical simulation is a promising and cheap approach of characterizing the wettability. In the flotation tests only small rock samples are required. This approach has the potential to provide fast estimation of the wettability of reservoir rocks.
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