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IOR 2013 - 17th European Symposium on Improved Oil Recovery
- Conference date: 16 Apr 2013 - 18 Apr 2013
- Location: Saint Petersburg, Russia
- ISBN: 978-90-73834-45-3
- Published: 16 April 2013
1 - 20 of 73 results
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Compositional Simulation of a Chemically Unconventional Oil Flooded by CO2
More LessCO2 flooding is considered as one of the most effective EOR processes when the miscibility can be achieved under reservoir conditions. The key point in this connection is the understanding and reproducing of the phase interactions between CO2 and reservoir oil. A challenging compositional simulation was performed to investigate the feasibility of CO2 flooding in a field in northern Germany having chemically unconventional oil. The usual steps of PVT simulation were applied. The grouping of the components was performed based on the chemical structure as well as on the distribution of K-values from CO2-oil flash experiments. Good agreements with the experiments were obtained at the end of the regression of the selected EOS parameters. The calibrated PVT set was further used to simulate the core flood experiments. Good matches with measured oil-water production were obtained after the fine tuning by parachor values of the pesudo components. A fully miscible process could not be achieved. On the other hand, the simulation using separator oil composition (lower C1 content) indicated the miscible/partially miscible displacement process with recoveries up to 70% of the remaining oil in place which fits well with observed results.
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Effect of Connate Water Vaporization on Well Injectivity During Acid Gas Injection into an Oil Producing Reservoir
More LessEffect of connate water vaporization on well injectivity during acid gas injection into an oil producing reservoir Paola Ceragioli. Ivan Maffeis, Alice Tegami Having H2S high EOR capabilities like those more widely known of CO2, acid gas reinjection in sour reservoirs, is an attractive option for sour oil fields developments, able to combine environmental preservation requirements with higher oil recoveries. Moreover, even though Sulphur market has been recently forecasted in growing trend, nevertheless overall sulphur production increase suggests to consider also sour reservoir scenarios alternative or even parallel to the production of high quantities of elemental solid sulphur. However, because of the high risk and the severe difficulties in H2S transportation, any environmentally friendly solution for acid gas injection has to be realized in place. However a careful design of such development scenarios involves the inclusion of additional complex phenomena. In fact, unlike what is usually accepted for non-acid fluids, full immiscibility between water and gas may not be valid anymore. In fact when a sour/acid gas stream contacts the connate brine, significant amounts of H2O gradually transfer to the acid phase, possibly leading to following halite precipitation from the more salty concentrated brine. At the same time, acid components dissolving into the connate brine from the contacted acid gas, may give rise to geochemical reactions, possibly able to alter rock properties. Here the dynamic study has been first focused around the variations on the injection/production throughout a sour reservoir sector, by taking into account injection gases with different acid components concentrations. In fact, at least as far as no water mobilization is expected within a carbonatic sour reservoir, porosity and permeability variations due to salts precipitation or calcite dissolution, in a previous work were estimated not too relevant, while connate water vaporization had been highlighted as the additional phenomenon presenting the major impact on the reservoir development description. The study will focus also on the needed preliminary modelling extensions, both with regards to thermodynamics and relative permeabilities, to be adequately set in order to make it possible the execution of these extended simulations.
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Effects of Oil on Foam Generation and Propagation in Sandstone Porous Media
More LessFoaming of nitrogen stabilized by C14-16 alpha olefin sulfonate in natural sandstone porous media, previously subject to water flooding, was studied experimentally. Foam was generated in-situ by co-injecting gas and surfactant solution at fixed foam quality. Effect of surfactant concentration on the foam strength and foam propagation was examined. X-ray CT scans were obtained to visualize the foam displacement process and to determine fluid saturation at different times. The experiments revealed that stable foam could be obtained in the presence of water-flood residual oil. CT scan images, fluid saturation profiles and mobility reduction factors demonstrated that foam exhibited a good mobility control in the presence of water-flood residual oil. This was further confirmed by a delay in the gas breakthrough. The experiments also proved that immiscible foam displaced additional oil from water-flooded sandstone cores, supporting the idea that foam is potentially an effective EOR method. Foam flooding provided an incremental oil recovery ranging from 13±0.5% of the oil initially in place for 0.1 wt% foam to 29±2% for 1.0 wt% foam. Incremental oil due to foam flow was obtained first by a formation of an oil bank and then by a long tail production due to transport of dispersed oil within the flowing foam. The oil bank size increased with surfactant concentration, but the dispersed oil regime was less sensitive to the surfactant concentration.
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New Reduced Parameters for Flash Calculations Based on Two-parameter BIP Formula
Authors S.E.G. Gorucu and R.T.J. JohnsPhase equilibrium calculations constitute a significant percentage of computational time in compositional simulation, especially as the number of components and phases increase. Reduced methods address this problem by carrying out phase equilibrium calculations using a reduced number of independent parameters. These methods have shown to speed up flash calculations, decrease simulation times, and also improve convergence behavior. In this paper, we present new reduced parameters using the two-parameter binary interaction parameter formula originally proposed by Li and Johns [1]. The new reduced parameters are applied to solve two-phase flash calculations for five different fluid descriptions. The results show a significant reduction in the number of iterations required to achieve convergence compared to the Li and Johns original approach. The improved method is also more robust than all previous reduced methods. We also compare computational times with the new reduced approach to conventional flash calculations based on the minimization of Gibbs energy using optimized software.
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Accelerated Deployment of Low Salinity Waterflooding in Shell
Authors T.G. Sorop, B.M.J.M. Suijkerbuijk, S.K. Masalmeh, M.T. Looijer, A.R. Parker, D. Dindoruk and S. GoodyearAccelerated Deployment of Low Salinity Waterflooding in Shell Low Salinity Waterflooding (LSF) is an emerging IOR/EOR technology that improves microscopic sweep efficiency by optimizing the injection water salinity. Although the exact microscopic mechanism is not yet fully understood, there is increasing evidence that in sandstones LSF improves the oil recovery by wettability alteration of the reservoir rock towards a more water-wet state. Typical field scale incremental oil recoveries are estimated to be up to 6% STOIIP. Despite these beneficial factors, LSF deployment can be a slow process. This paper discusses the key factors that help accelerate LSF deployment in Shell. A key enabler for technology deployment acceleration is Shell’s decision-driven opportunity realization process (ORP). Within this framework, the deployment starts with a portfolio screening using a consistent set of surface and subsurface screening criteria, to rank and prioritize the opportunities (according to probability of success). For each identified opportunity, a key next step is to perform reservoir condition SCAL tests, for which Shell has developed a comprehensive protocol to assess and quantify the LSF effect, while de-risking the potential for injectivity loss through clay swelling. These protocols have been standardized and incorporated into the general WF guidelines, so that any suitable new WF project conducts LSF SCAL. For mature waterfloods, this SCAL program also provides the operating units with reservoir condition relperm data, which helps to refine history matching and forecasting, enabling an optimal management of their waterfloods. While SCAL is started as early as possible in the ORP, it is accompanied, in parallel, by facilities design, production forecasting and project economics. In particular, the standardization of the facilities design, including cost models, for various offshore and onshore options, plays a key role in accelerating the deployment effort. In Shell, LSF is currently at different stages of deployment around the world and across the whole spectrum of WF projects, from the rejuvenation of brown fields to green field developments, both offshore and onshore assets. Integrated surface and subsurface technology teams are currently taking the lead, working in close cooperation with R&D and individual asset teams. While LSF is a natural extension of WF, this deployment effort is combined with screening for other EOR technologies, to identify where LSF may be able to unlock additional value by creating the appropriate conditions for subsequent chemical flooding.
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Polymer Flooding with the Polysaccharide Schizophyllan - First Field Trial Results
Authors B. Leonhardt, M. Santa, A. Steigerwald and T. Kaeppler. For the first field trial an existing fermentation plant at BASF’s industrial compound at Ludwigshafen, Germany, has being expanded to include a pilot plant for the production of a sufficient amount of Schizophyllan. In this field trial Schizophyllan is being injected for the first time into a mature oil field in Northern Germany. New wells were drilled in the selected project area and surface facilities for polymer storage and mixing and oil transportation were constructed. One of the new wells was drilled as an observation well fairly close to the injection well, to provide quick information on the project progress. Microbiological surveillance, pressure monitoring using permanent down-hole gauges and frequent production tests are performed to monitor the progress of the polymer trial. The paper summarizes learnings from the implementation phase and provides first results of the biopolymer injection. The surveillance plan will be discussed, and the challenges posed by planning and executing a new technology trial in a mature oil field are highlighted.
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Low Salinity Flooding - A Critical Review
By A. SkaugeLow Salinity flooding is an emerging technology to improve waterflood oil recovery for both sandstone and carbonate reservoirs. Extensive laboratory experiments investigating the effect of low salinity are available in the literature. To quantify the low salinity effect, either spontaneous imbibition and/or tertiary waterflooding experiments have been performed. In few cases, the experimental flooding data was interpreted using numerical simulation to derive relative permeability curves for both low and high salinity water to be used in field simulation. The field experience using change in brine salinity to improve oil recovery is yet very limited. The mechanisms suggested explaining low salinity effect (LSE) is very diverse. This paper will evaluate the different proposed mechanisms with focus on wettability alteration as the main mechanism. The paper will discuss 1- whether spontaneous imbibition experiments, which are often performed to demonstrate the change of wettability, are sufficient to demonstrate the potential of low salinity effect and 2- whether changing the rock to more water-wet will lead to reduction in residual oil saturation (Sorw) in light of the well-established fact that Sorw is higher for water-wet rock. Core flood results as a tertiary low salinity process is mostly reported in the literature, and these experiments often give a low increase in oil recovery smeared over a long production period. The question arise that possible a lot of the literature data is influenced by capillary end-effects. Some solid low salinity response is documented with stepping up the flow rate at the end of the primary waterflood, and still shows added recovery after change in injected brine salinity. An alternative approach to control capillary end-effects would be to use monitoring of in-situ saturation. Unfortunately, the low salinity literature lacks information about local saturation and thereby also on how additional oil is mobilized. The paper conclude on what we in our opinion find is the proven main low salinity mechanisms, best approach for core flooding studies of low salinity, and modeling approach for matching core floods and also estimate field response.
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The Critical Parameter for Low Salinity Flooding - The Relative Importance of Crude Oil, Brine and Rock
Improved oil recovery by low salinity flooding (LSF) in sandstone reservoirs is hypothesized to be the result of a wettability change of the crude oil, brine, rock (COBR) system to a more water-wet state. The exact mechanism behind the wettability change upon lowering the ionic strength of the brine is, however, not yet fully understood. It is generally accepted that a strong low salinity effect requires the presence of clay minerals in the reservoir rock and preferably a high salinity of the formation water containing divalent cations. Still, COBR systems that obey these minimum requirements may give a highly variable response to low salinity flooding. To create enhanced understanding of the critical parameter(s) controlling the low salinity effect, crude oil, rock and brine from three different reservoir systems were varied in all possible combinations in a series of spontaneous imbibition tests. These tests show that, for the COBR systems analyzed here, the rock is the most critical parameter for a strong low salinity effect. Cross-correlation of the change in water saturation upon exposure to low salinity, ΔSw LS, with various rock parameters indicated the strongest correlation with rock zeta potentials.
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Maximizing Oil Recovery - Developing and Piloting Offshore Facilities to Customize Water for CEOR and Low Salinity Injection
Authors L. Henthorne, C. Martin and F. Azhar Abd SatarThe growing popularity of water-based enhanced oil recovery (EOR) technologies, such as low salinity injection (LSI), chemical EOR (CEOR), and steam-flooding, has created new opportunities for the water treatment industry as a function of the unique requirements of equipment and systems in EOR projects. In some cases, the needed technologies have little to no history of application in the upstream oil and gas industry, therefore impacting EOR project budgets and schedules. These issues become particularly acute in offshore applications that are generally limited by footprint and weight, thereby further reducing suitable water treatment options. Two offshore projects in Southeast Asia are pioneering the use of customized water to maximize oil recovery in CEOR applications. In one project, two vastly different water qualities are being developed which correlate to two CEOR cocktails under consideration. The water treatment infrastructure must be capable of providing either water quality and be responsive to water quality impacts associated with produced water injection facilities such that the blended injection water quality maintains consistency. In the other project, an ultra-low hardness level is desired in the injection water, to prevent potential precipitation in the reservoir. This paper describes the results of pilot testing of reverse osmosis and unique nanofiltration membranes to produce a variety of water chemistries for CEOR and LSI applications, including ultra-low hardness, high salinity; and low hardness, low salinity injection water. The testing confirms the ability of new water treatment technologies to solve challenging issues that arise in EOR applications, particularly those in offshore applications that must respond to varying needs of reservoirs and footprint/weight limitations.
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Low Salinity Polymer Flooding
Authors A. Skauge and B.S. ShiranLow salinity waterflooding has received increasing attention. However, the increased oil recovery by low salinity is in most cases very limited. Combining low salinity with other EOR methods has been our focus in recent years. The combined effect of brine chemistry and added surfactant on oil recovery was addressed by Alagic and Skauge in recent publications. Their results show incremental recoveries of 20-30% OOIP from low salinity surfactant (LS-S) injection. The low salinity surfactant solutions used showed type II- phase behaviour with the crude oil used in the tests. We have in this study made core flood experiments to study the combined effect of low salinity and polymer injection. The polymer used is HPAM and the concentration of polymer has been very low. The change in injection brine viscosity is therefore very small, but the impact on oil recovery is significant. The results also show the benefit of secondary low salinity flooding in combination with polymer injection compared to tertiary injection.
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Fitting Foam Simulation Model Parameters to Data
Authors C.S. Boeije and W.R. RossenCheng et al. (2000) present a simple method to fit foam simulation parameters without oil to data for pressure gradient as a function of superficial velocities of gas and liquid. The key in this process is the identification of "high-quality" (high gas fraction) and "low-quality" foam regimes. The method is essentially the same for the foam model parameters in foam models in STARS, UTCHEM or ECLIPSE. Often, however, available data are more limited - pressure gradient for one scan of foam quality at fixed total superficial velocity. We show how to extend this method to the more limited data set. The transition in regimes occurs at the foam quality with the maximum pressure gradient. We illustrate the method by fitting parameters to several published data sets. Our approach is simple and direct. The model fit would be appropriate for an EOR process involving foam injection at finite water fraction, but not a SAG foam process involving large slugs of gas and liquid. For the latter process, model parameters should be fit to data relevant to that process, i.e. at extremely high foam quality. The approach assumes an abrupt transition between high- and low-quality foam regimes, i.e. a large value of epdry in the STARS foam model. If a smaller value is chosen for faster execution of the simulator this approach could underestimate pressure gradient near its maximum value at the transition between regimes. In that case the parameter values quickly obtained by this method could provide the initial guess for a computer-based least-squares fit of all parameters, including a smaller value of epdry, and a check on the parameters so obtained.
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Multi-scale Pore-network Modelling of WAG in Carbonates
Authors C. Maier, Z. Jiang, A. Al-Dhahli, M.I.J. van Dijke, S. Geiger, G.D. Couples and J. MaCarbonate reservoirs have textural heterogeneities at all length-scales (triple porosity: pore-vug-fracture) and tend to be mixed- to oil-wet. The choice of an enhanced oil recovery process and the prediction of oil recovery require a sound understanding of the fundamental controls on fluid flow in mixed- to oil-wet carbonate rocks, as well as physically robust flow functions, i.e. relative permeability and capillary pressure functions. Obtaining these flow functions is a challenging task, especially when three fluid phases coexist, such as during water-alternating-gas injection (WAG). We have recently developed a method for integration of pore-networks derived from micro CT images at different length-scales, thus capturing pore structures from different types of porosity. The network integration method honours the connectivity between different pore types, including micro-fractures, and their spatial distribution. In this work, we use these multi-scale networks as input for our three-phase flow pore-network model, which comprises a novel thermodynamic criterion for formation and collapse of oil layers that strongly depends on the fluid spreading behaviour and the rock wettability. The criterion affects in particular the oil relative permeability at low oil saturations and the accurate prediction of residual oil saturations. We generate three-phase flow functions for gas injection and WAG from networks with carbonate pore geometries and connectivities and we demonstrate the impact on residual saturations of the different types of porosity and the interaction with different realistic wettability scenarios. We also show that the network generated three-phase flow relative permeabilities are distinctly different from traditional models, such as Stone’s. The flow functions will be used in a heterogeneous carbonate reservoir model and to demonstrate their impact on the sweep efficiency.
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Modeling of Foam Flow Using Stochastic Bubble Population Model and Experimental Validation
More LessThe transient foam flow, forward movement of foam front until breakthrough in a one dimensional flow, in an oil-free porous medium was studied using the stochastic bubble population (SBP) model. The premise of this model is that foam flow in porous media is a complex fluid and bubble generation is a stochastic process. The SBP foam model describes the net bubble generation using three parameters: maximum bubble density and bubble generation and destruction coefficients. The corresponding governing equations, a system of non-linear partial differential equations in the saturation, pressure and bubble density, were solved using the IMPES method. The sensitivity to the main physical parameters was also analyzed. It was found that increase of the maximum bubble density leads to generation of stronger foam, characterized by a slower foam propagation rate and a larger foam mobility reduction. The bubble generation coefficient Kg mainly controlled the foam generation rate such that a higher Kg led to a more rapidly increasing bubble density. We also provided a comparison between the numerically obtained saturation and pressure data with those obtained from the experiments at which foam was generated by co-injecting nitrogen and C14-16 alpha olefin sulfonate surfactant in Bentheimer sandstone. X-ray CT scans were also obtained to visualize the foam displacement process and to determine fluid saturation at different times. A good match was obtained between the numerical and the experimental data which confirms that the SBP foam model is robust and reproduces the main features of the transient behavior of foam flow in a homogeneous porous media.
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Pore Scale Modelling of Polymer Flow
Authors N. Zamani, R. Kaufmann, T. Skauge and A. SkaugePolymer flooding as an EOR method that has boomed in the last decade as oil prices have been rising, and new and larger polymer flood projects are being realized. Some milestones and examples are the large-scale viscoelastic polymer flood implementation at the Daqing field in China, polymer injection in Marmul field, Oman, and the Dalia offshore polymer project. Polymer flood is a mature EOR technology, but as the reservoir targets get more diverse and the field conditions harsher, the current understanding of polymer flood is stretched to its limits. In order to explain viscous fingering in inter-mediate to heavy oil reservoirs and viscoelastic mobilization of residual oil there is a need for a better understanding of polymer flow mechanisms on the pore scale. Pore scale polymer flow characterization is very complex and involves several flow phenomena like; adsorption, viscous fingering, depleted layers, hydrodynamic retention, bridging/flow-induced adsorption, viscoelastic effects, in-accessible pore volume and more. In this study we have developed a Navier-Stokes model to analyse polymer flow and to compare against Newtonian fluids. The aim has been to identify the key parameters for polymer displacement. Examples of obtained results are that the depletion layer plays a major role in study of rheological properties. Increased depleted layer thickness lead to lower velocity at the centre of the pore and more slip effect near the pore wall. When a higher degree of shear thickening is included a larger drag on fluids in side channels will occur, this is consistent with oil mobilisation and lowering of residual oil saturation.
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Osmosis During Low Salinity Water Flooding
Authors K. Sandengen and O.J. ArntzenSeveral research groups have shown that injection of low saline water may yield an Enhanced Oil Recovery (EOR). The mechanisms underlying this “low salinity effect” are, however, still unclear. We believe that osmosis has been overlooked as a possible mechanism for the observed EOR effect. Osmosis is bound to occur in an oil/water/rock system when injecting low salinity water as the system is full of an excellent semi-permeable membrane, namely the oil itself. Hence we believe that this topic deserves more attention. In the present work oil droplets were observed to move under the influence of an osmotic gradient in a simple visualization experiment. The experimental setup consisted of two oil droplets in a ~1 mm diameter glass tube with salt water between them and distilled water on the outside. For a porous rock medium it is proposed that such osmotic gradients relocate oil by expanding an otherwise inaccessible aqueous phase.
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The Impact of Common Reservoir Minerals and Temperature on the Low Salinity EOR-effect in Sandstone
Authors S. Strand, T. Austad, T. Puntervold, H. Aksulu, B. Haaland, K. Navratil, S. Storås and D. HåmsøThe mechanism of the low salinity EOR process in Sandstone reservoirs has been debated in the literature for more than a decade. We recently proposed a chemical wettability alteration mechanism for the process, well founded in experimental observations. Even though this main chemical understanding is quite well described, there are parameters/factors that could disturb the main process. Combinations of certain minerals, temperature, and salinity/composition of formation water could have impact on the low salinity EOR process. Plagioclase, a polysilicate mineral, is often present in sandstone reservoir rocks, and could have a significant effect on the initial pH of the formation water, which will influence the initial wetting conditions. In this experimental work it is shown that Plagioclase in reservoir rock and outcrop material responded differently on the low salinity effect. It is also verified that enhanced dissolution of anhydrite, CaSO4, in the low saline fluid suppressed the increase in pH, which is an important parameter for observing tertiary low salinity effects. A combination of high reservoir temperature, Tres>100 oC and very high salinity of the formation water, >200 000 ppm, resulted in too water wet conditions for observing tertiary low salinity EOR effects, even though the clay content was high, ≈20 wt%. The experimental results are in line and discussed in relation to the previously published chemical mechanism for the low salinity EOR process.
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The Use of Polymer Injectivity Data for the Estimation of Porous Media Longitudinal Dispersion
By A.M. AlSofiCurrent dispersion estimation techniques rely on the measurement of a tracer concentration smearing either in-situ or at the outlet. We propose a much easier technique that does not require measuring concentrations. The technique involves the injection of a pure phase followed by the same phase saturated with a non-linear viscosifying agent (or vice versa). This transition in the viscosity of the injected phase will result in a pressure transition. Theoretically, without dispersion, the pressure transition is directly linear with respect to time. However, with dispersion and due to the non-linearity of the viscosity-concentration dependence this transition will further spread. Analyzing this additional smearing and delay of the pressure response would give a direct measure of dispersion. Adsorption of the viscosifying agent also can cause a similar effect where the pressure propagation is delayed. Nevertheless, we could decouple those effects. The proposed procedure of measuring pressures during a viscosity switch is already done in the industry. In the context of polymer flooding, injectivity tests are used to give indication of potential injectivity issues and, explicitly, provide estimates of the polymer solution resistance and residual resistance. Therefore, we can further use injectivity data to estimate water dispersion and polymer adsorption. Injectivity data measured for a polyacrylamide polymer in a limestone core was used to test the method. Our pressure analysis suggest the aqueous phase exhibits a longitudinal dispersivity of 0.02 ft while, at 0.2 wt. %, 10% of the polymer concentration is adsorbed. Both results fall within the ranges reported in the literature. Additional simulation sensitivity results were performed using UT-Chem. The results support the presented theory. The proposed method is simple and could prove helpful in eliminating experimental redundancy and in simplifying dispersion estimation.
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Low Salinity Water Flooding: Retention of Polar Oil Components in Sandstone Reservoirs
Authors I.F. Fjelde, A.P. Polanska, F.T. Taghiyev and S.M.A. AsenInjection of low salinity water has been reported in the literature to improve oil recovery in some sandstone reservoirs, but some disappointing results have also been reported for other reservoirs. Different low salinity water flooding (LSWF) mechanisms have been proposed, but no mechanism has been widely accepted. These mechanisms are therefore still discussed. Understanding how the brine and oil components interact with the minerals in the reservoir rocks is necessary to establish more knowledge about the LSWF mechanisms. In the presented study the objective has been to investigate the retention of polar crude oil components onto minerals and reservoir rock (with high clay content) in equilibrium with brines of different salinities/compositions. The interactions between minerals/reservoir rock, oil and brine were then studied in both static and dynamic experiments. These results have been compared with results from core flooding studies carried out to study the effect of different brine compositions on the oil recovery in the same reservoir rock. The experiments have demonstrated that change of injection brine from high to low salinity/composition can significantly change the retention of polar oil components onto minerals and reservoir rocks. When the injection brine is changed, the amounts of divalent cations onto clay surfaces can depending on the compositions of these brines either increase or decrease. The wettability conditions of the rock can therefore either be altered to less water-wet or more water-wet. The results from the study of retention of polar crude oil components were in accordance with flow characteristics in the core flooding studies carried out in the same reservoir rock. It is concluded that the first evaluation of the potential for low salinity water flooding for improving oil recovery can be carried out by measuring the difference in retention of polar crude oil components for the high and low salinity brine compositions. The potential for different possible low salinity water compositions can also be evaluated by measuring the retention of oil components in the presence of these brines.
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Foam for Mobility Control in EOR - a Microfluidic Approach
Authors N. Pannacci, M. Ryba, Y. Peysson, B. Herzhaft and J.F. ArgillierFoam injection is one of the processes that may be used for enhanced oil recovery, in particular for gas mobility control. The work we present is focussed on understanding foam formation and foam flow at small scale in very simple model geometries. To this purpose, a microfluidic device is used to accurately control diphasic flows confined at 10 to 100 micrometer scale. The microfluidic device is made of polydimethylsiloxane (PDMS), a transparent elastomer allowing simple and fast prototyping and easy observation of flows with optical microscopy. The experimental method is based on a microsystem that first permits formation of a dispersion of very monodisperse gas bubbles in water and surfactant at a flow-focusing geometry. The flow and the behaviour of the bubbles downstream is as well observed and measured in the model geometries including chamber, channels, etc. Complete phase diagram of the foam formed is shown, from very wet to very dry (small or high gas volume fraction) and with small or large bubbles according to pressures applied of both the gas and the aqueous phase. Image analysis is used to characterize the foam structure (quality, bubble size, bubble monodispersity). A simple analysis is done to give a criterion for the foam to be formed according to geometry, surface tension and pressures applied to the fluids. First results show that in a geometry modelling two permeabilities with simple large and small channels, fluid flow may be redirected from high permeabilities areas to small permeabilities ones. Even if obtained without any oil, this observation may be compared to what happen to foam flows in fractured rocks and may explain part of the complex phenomena involved for increase oil recovery. To conclude, microfluidic tool appears as an interesting technique to characterize the behaviour of foam at the micrometric scale.
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Interfacial Tension and Contact Angle Determination in Water-sandstone Systems with Injection of Flue Gas and CO2
Authors N. Shojai Kaveh, E.S.J. Rudolph, W.R. Rossen, P. van Hemert and K.H. WolfCarbon capture and storage (CCS) has the potential for reducing CO2 emissions to the atmosphere. This option includes storage strategies such as CO2 injection into deep saline aquifers, depleted oil and gas reservoirs, and unmineable coal seams. This process is largely controlled by the interactions between CO2, the reservoir fluid and reservoir rock. In particular, the wettability of the rock matrix has a strong effect on the distribution of the injected CO2 into geological formations. In this study, the wetting behavior of Bentheimer sandstone slabs and CO2 and/or flue gas is investigated by means of contact-angle measurements. In addition, the interfacial tension between CO2 and/or flue gas and connate water was determined. The experiments were conducted in a pendant-drop cell, adapted to allow captive-bubble contact-angle measurements and performed at a constant temperature of 318 K and pressures varying between 0.2 and 15 MPa, typical in-situ conditions. The experimental contact angle measurements show that the Bentheimer sandstone/water system is (and remains) water-wet even at high pressures with CO2 and/or flue gas injection. The determined data of the contact angle of the water–sandstone system demonstrate a strong dependence on the bubble size and surface roughness with CO2 and flue gas injection.
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