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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
121 - 139 of 139 results
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New Potential Tracer Compounds for Inter-well SOR Determination - Stability at Reservoir Conditions
Authors M. Silva, H. Stray and T. BjørnstadSummaryThe number of mature oil fields increases worldwide with recovery factors of 20% – 40%. Further exploration of the known oil resources requires thorough understanding of the reservoir. Partitioning inter-well tracer test (PITT) is a promising method to determine residual oil saturation in the reservoir’s swept volumes, thus contributing for its understanding.
PITTs identify EOR targets, evaluate EOR operations and the efficiency of volumetric sweep between wells. PITTs are rare in the oil industry, partly due to the scarce number of compounds qualified for such application. A PITT tracer must be thermally, chemically, and biologically stable, have constant and reversible phase partitioning and be unique at reservoir conditions. It should also be analyzable in ppb/ppt concentrations, and available in considerable quantities at acceptable cost.
In this paper, the stability studies conducted with 15 PITT tracer candidates are presented. They were tested for thermal, chemical and biological stability under temperatures of 25 °C – 150 °C and pH 5.5 – 8.0. Their interaction with sandstone, limestone and kaolinite was also investigated. Six compounds were found to possess suitable characteristics for this application and another five compounds show interesting properties to retrieve other information from the reservoir, such as temperature or geochemical data.
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Characteristic Fracture Spacing in Primary and Secondary Recovery for Naturally Fractured Reservoirs
Authors J. Gong and W.R. RossenSummaryIf the aperture distribution is broad enough in a naturally fractured reservoir, even one where the fracture network is highly inter-connected, most fractures can be eliminated without significantly affecting the flow through the fracture network (Gong and Rossen, 2016). During a waterflood or enhanced-oil-recovery (EOR) process, the production of oil depends on the supply of injected water or EOR agent. This suggests that the characteristic fracture spacing for the dual-porosity/dual-permeability simulation of waterflood or EOR in a naturally fractured reservoir should account not for all fractures but only the relatively small number of fractures carrying almost all the injected water or EOR agent (“primary,” as opposed to “secondary,” fractures). In contrast, in primary production even a relatively small fracture represents an effective path for oil to flow to a production well. This distinction means that the “shape factor” in dual-permeability reservoir simulators and the repeating unit in homogenization should depend on the process involved: specifically, it should be different for primary and secondary or tertiary recovery. We test this hypothesis in a simple representation of a fractured region with a non-uniform distribution of fracture flow conductivities. We compare oil production, flow patterns in the matrix, and the pattern of oil recovery with and without the “secondary” fractures that carry only a small portion of injected fluid.
The role of secondary fractures depends on a dimensionless ratio of characteristic times for matrix and fracture flow (Peclet number), and the ratio of flow carried by the different fractures. In primary production, for a large Peclet number, treating all fractures equally is a better approximation than excluding secondary fractures; the shape factor should reflect both primary and secondary fractures. For a sufficiently small Peclet number, it is more accurate to exclude the secondary fractures. For waterflood or EOR, in most cases examined, the appropriate shape factor or repeating-unit size should reflect both primary and secondary fractures. If secondary fractures are much narrower than primary fractures, then it is more accurate to exclude them. Yet-narrower “tertiary fractures” are not always helpful for oil production, even if they are more permeable than matrix. They can behave as capillary barriers to imbibition, reducing oil recovery.
We present a new definition of Peclet number for primary and secondary production in fractured reservoirs that provides a more accurate predictor of dominant recovery mechanism in fractured reservoirs than the previously published definition.
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Estimation of Pressure-Saturation and Porosity Fields from Seismic AVA Data Using an Ensemble Based Method
More LessSummaryWe propose an ensemble based seismic inversion framework to estimate static and dynamic reservoir parameters such as saturation, pressure and porosity fields using seismic data. The proposed method has certain novelties, in terms of the choice of seismic data, as well as uncertainty quantification of the estimates. Further, the method uses reservoir-engineering data as the prior information (such as pressure-saturation data) from reservoir simulation model to constrain the inversion process.
Many conventional seismic inversion algorithms are deterministic in nature, and thus they pay less attention to uncertainty quantification. To quantify the uncertainties in the estimates, we adopt an iterative ensemble smoother as the inversion algorithm. Compared to the conventional deterministic inversion algorithms, this ensemble-based method is a derivative-free and non-intrusive approach, and has better capacity of uncertainty quantification. On the other hand, inverted seismic parameters, such as acoustic impedance, are often adopted as the data in inversion. In doing so, extra uncertainties may arise during the inversion processes. Here, we avoid such intermediate inversion processes by adopting amplitude versus angle (AVA) data.
To handle the big-data problem in the AVA inversion process, we adopt a wavelet based sparse representation procedure ( Luo et al., 2016 ). Precisely, we apply a discrete wavelet transform to the AVA data, and estimate noise in the resulting wavelet coefficients. We then use the leading wavelet coefficients above a certain threshold value as the data in inversion.
We apply the proposed framework to a 2D synthetic model for a proof-of-concept study. This reservoir model consists of three phases (water, oil and gas), and is a vertical section of a 3D Norne field model. We also test the performance of the framework in the 3D Brugge benchmark case that consists of two phases (water and oil). The numerical results from both cases indicate that the proposed framework can integrate the reservoir-engineering data as prior knowledge with seismic data, while achieving reasonably good estimates of both static and dynamic reservoir variables.
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Optimization of Recovery under Injection of Biopolymer, Synthetic Polymer and Gels in a Heterogeneous Reservoir
SummaryFor polymer injection, a comparison of xanthan polymer and synthetic polymer mechanisms was conducted. A commercial full-physics reservoir simulator is coupled with a robust optimization and uncertainty tool to run the model where a simplified gel kinetics is assumed to form a microgel with no redox catalyst. Water injection continues over all 6 layers for 450 days, followed by gel system injection for 150 days in the bottom 2 layers. Water injection is continued to 4 years. The top four layers have higher horizontal permeabilities and a high-permeability streak is at the bottom of the reservoir to reduce any helpful effects of gravity.
Results demonstrate deep penetration of gel and blocking of the high permeability bottom layers. Sensitivity studies indicate the relative merits of biopolymer, xanthan polymer in terms of viscosity effects vs synthetic PAM in terms of resistance factor vs insitu gelation treatments and their crossflow dependence. Adsorption and retention of polymer and gel are permeability dependent.
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Non-linear Newton Solver for a Polymer Two-phase System Using Interface-localized Trust Regions
Authors Ø.S. Klemetsdal, O. Møyner and K.A. LieSummaryModels of polymer flooding account for several processes such as concentration dependent viscosity, adsorption, incomplete mixing, inaccessible pore space, and reduced permeability effects, which altogether gives strongly coupled nonlinear systems that are challenging to solve numerically. Herein, we use a sequentially implicit solution strategy that splits the equation system into a pressure and a transport part. Our objective is to improve convergence rates for the transport subproblem, which contains many of the essential nonlinearities caused by the addition of polymer. Convergence failure for the Newton solver is usually caused by steps that pass inflection points and discontinuities in the fractional flow functions. The industry-standard approach is to heuristically chop time steps and/or dampen saturation updates suggested by the Newton solver if these exceed a predefined limit. An improved strategy is to use trust regions to determine safe saturation updates that stay within regions having the same curvature for the numerical flux. This approach has previously been used to obtain unconditional convergence for waterflooding scenarios and multicomponent problems with realistic property curves. Herein, we extend the method to polymer flooding, and study the performance of the method for a wide range of polymer parameters and reservoir configurations.
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Numerical Modelling Analysis of Smart Water-oil Interactions in Carbonates
Authors P. Kowollik, A. Behr, L. Genolet, P. Bedrikovetski and M. AmroSummaryThe present work is an attempt to formulate the today’s understanding of the EOR mechanisms of “Smart” waterflooding as a closed system of equations, aiming to adapt it to numerical modelling applications. Within a two-phase water-oil framework, the model describes how the dissolved ions Ca2+, SO42−, Na+ and Cl− interact within the rock-fluid system. Complex phenomena, involving thinning out of the electrical double layer by lowering the overall water salinity and changes in water chemical composition, are represented by an adsorption/desorption scheme. Since Ca2+ ions at the rock surface react with polar oil components, causing detachment of oil (wettability change), special bi-parametric adsorption isotherms are introduced for Ca2+ ions, together with mono-parametric adsorption isotherms for SO42− ions. This is the key-component affecting the behavior of Ca2+ by mitigating the positive surface potential at the carbonate surface. The model also accounts for the non-equilibrium kinetics.
The main target on the development of this technique is describing the processes that occur inside the matrix block when “Smart” waterflooding is used to increment the oil recovery in fractured-porous systems. Special emphasis is put on the molecular diffusion mechanisms that are responsible for establishing the water compositional equilibrium between fracture and matrix structures.
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Impact of Biodegradation - Consideration in the Polymer Flood Model
Authors A. Behr, S. Mukherjee and D. PrasadSummaryPolymers are susceptible to degrade under reservoir conditions due to impact of various factors. It is well known that synthetic polymers such as partially hydrolyzed polyacrylamide (HPAM) are more prone to mechanical and chemical degradation. However, biological degradation by microorganisms is deemed to be the primary property changing mechanism in case of biopolymers. Thus, for a sound technical and economic viability using polymer flooding, it is important to include this possible phenomenon to complete the analysis of the biopolymer behavior in the reservoir.
Mathematical modelling of oil recovery by polymer injection involving biodegradation has so far not been investigated and documented extensively in the literature. In this paper, two numerical approaches as well as a distinct analytical solution are presented which allow quantitative analysis of the biodegradation impact on the polymer flooding.
The analytical model assumes radial flow with the polymer degradation rate proportional to its concentration (decay model). For the first numerical approach, this kinetic model is generalized for realization on a real reservoir model.
The other numerical approach is more sophisticated and considers explicitly biopolymer together with bacterial population in-situ. In this case, the model distinguishes clearly between the planktonic and the sessile bacterial communities. Biodegradation process, the mass exchange between polymer molecules and bacteria, is described by the chemical reaction equations.
We adapted a CMG STARSTM for numerical solution of the model which was applied to interpret a pilot test with biopolymer. A reasonable history match was achieved for the polymer injection well using bottomhole pressure as the primary control parameter, although this was not considered as unique. Our primary focus lies on the characteristic degradation time, which is an explicit input parameter in the first model. We estimated the characteristic degradation time in the model from the outcomes of the multiwell and multiple huff and puff tests. However, the challenge lies in the estimation of this value, due to the complex kinetic of the model in the second approach.
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Data Conditioning of 4D Seismic Timelapse Data for Improved Inversion of Reservoir Pressure and Saturation
Authors S.F.A. Carpentier, T.P.H. Steeghs, Y. Zhang and O. LeeuwenburghSummaryRecent progress in 4D seismic history matching benefits greatly from the use of 4D seismic timelapse data. Several methods for inversion of 4D seismic timelapse data for reservoir pressure and saturation have been developed with mixed success. Most of these methods work well on synthetic data or real data with low noise levels, but degrade in performance using data with high noise levels or artefacts. Improvements on the algorithmic side as well as on the data side are necessary to enforce further progress in 4D seismic timelapse inversion and 4D seismic history matching.
A seismic timelapse inversion method specifically aimed at direct inversion for reservoir pressure and saturation from AVO timelapse data is investigated on performance. This method performs robust on noisy timelapse data from which timelapse AVO intercepts and gradients are inverted to changes in pressure and saturation. Considerable uncertainties and ambiguities remain however in the inversion results in terms of interpretation of pressure and saturation fronts, fault transmissibility and reservoir compartmentalisation. Next-generation image-denoising and edge-preserving algorithms are employed to condition the seismic timelapse data prior to AVO computation, timelapse differences and inversion thereof. Two algorithms in particular are used: the Non Local Means (NLM) algorithm and the Alternating Guided Filter (AGF). These two algorithms have been shown to perform exceptionally well on both image-denoising and edge-preservation, two key properties of successful data conditioning of timelapse data ultimately for 4D seismic history matching. To create stable and smooth pressure and saturation fronts while preserving sharp boundaries in these fronts, the AGF algorithm is found to be most effective. In this study, we demonstrate this by application of our technique to the 4D seismic data in the Norne field in offshore Norway. Inversion for reservoir pressure and saturation from Norne AVO timelapse data is performed with data conditioning by the two algorithms applied in several stages of the inversion. It is found that data conditioning with the AGF algorithm posterior to the AVO timelapse differences gives best results.
Reservoir pressure and saturation fronts are obtained with great detail, honoring reservoir compartments and fault boundaries. These results are of much use for subsequent 4D seismic history matching.
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Modeling the Rheology of Two-phase Polymer Flow
Authors D. Shogin, P.A. Amundsen, A. Hiorth and M.V. MadlandSummary
Two-phase concentric annular tube flow is investigated. We study the case when one of the phases is Newtonian, e.g. oil, and the other non-Newtonian fluid, e.g. solution of an EOR polymer. The kinetic theory-based FENE-P dumbbell model is used to describe the polymer rheology. Both possibilities are considered: when the phase in the core is non-Newtonian and when it is Newtonian.
The system of differential equations governing the dynamics of the phases is solved analytically, and the fractional flows of the phases are determined. Further, the concept of relative permeability is generalized. It is demonstrated how Darcy’s law can be extended to take non-Newtonian effects into account. It is illustrated that the relative permeabilities of the phases depend not only of their saturation, but also on the pressure gradient in the flow direction, due to the polymeric phase rheology.
Finally, the role of the normal stresses in the non-Newtonian phase is discussed. We show that in a cylindrical tube the normal forces do not contribute to the pressure drop in the flow direction and, therefore, do not affect the dynamics of the phases; but, in slightly more complicated geometries the impact of normal stresses on the fluid dynamics can be essential.
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Detailed Modeling of Injection and Production Induced Rock Displacements
Authors M. Niebling, J. Haukås, M. Nickel and J. BakkeSummaryReservoir injection and production leads to stress changes in the reservoir and the surrounding rock. For compacting reservoirs, these effects are particularly prominent. The associated rock displacements make infill drilling and optimization of performance and integrity challenging. Constant monitoring and prediction of the displacements of the rock is key to identify risks early. Once such risks are identified the production strategy can be adjusted to mitigate such risks and overall increase the recovery of hydrocarbons.
This paper describes how displacement information obtained from time-lapse seismic data and estimates of rock material properties from well data or databases can be used in detailed modeling of geomechanical effects. The output of the geomechanical simulation is the stress change and the vertical and horizontal rock displacements. The displacements at the boundary of the model are imposed based on displacement estimates from the time-lapse seismic data, and together with the computed displacements in the interior of the model a complete description of the stress exchange can be obtained.
An advantage of the method is, that no input from reservoir flow simulations coupled with potentially complex yield functions is required, and a detailed description truly consistent with the time-lapse seismic data can be obtained. As a starting point the displacement at top reservoir is estimated from the observed time-lapse time shift using an R-factor model for the time shift to depth shift conversion. Together with the locally dependent material parameters the boundary displacements are used as input to the geomechanical model. The displacements can then be simulated everywhere in the interior of the model. In a next step these displacements are compared to the displacements observed in the time-lapse seismic data. According to the mismatch, the accuracy of the current geomechanical model can be evaluated. To improve the match between simulated displacements and the displacements estimated from the time-lapse seismic data, the local material properties in the model and/or the depth shift estimates can be adjusted. The whole process improves the confidence in the proposed model parameters.
Once the parameters are adjusted and the simulated displacements agree well with the seismic observations the resulting local stress conditions can be trusted. Knowledge of the local stress conditions is important in infill drilling and optimizing well performance and integrity.
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When Size Matters - Polymer Injectivity in Chalk Matrix
Authors I.W. Jolma, D. Strand, A. Stavland, I. Fjelde and D. HatzignatiouSummaryThis paper investigates the injectivity of polymers in chalk matrix by experimental methods. Different polymers with variable molecular weight and structure was injected into a chalk core plug while monitoring the differential pressure. Based on the experimental results in this study, we found that it was possible to inject polymers with low molecular weight and low viscosity through chalk matrix core plugs, without causing major plugging of the rock.
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4D Seismic History Matching of the Norne Field Model Using Ensemble-based Methods with Distance Parameterization
Authors Y. Zhang, O. Leeuwenburgh, S. Carpentier and P. SteeghsSummaryA distance parameterization of flood fronts derived from time-lapse seismic anomalies was recently developed to facilitate incorporation of time-lapse seismic data into history matching workflows based on ensemble methods such as the ensemble Kalman filter (EnKF) and the ensemble smoother (ES). A number of advantages were demonstrated on synthetic data including a significant reduction in the number of data points and flexibility in the type of attribute from which the front information can be extracted. In order to enable the use of the proposed method in real-field history-matching cases, we first extended the applicability of the algorithm computing the distance between observed and simulated fronts from regular Cartesian grids to generic corner-pint grids. Secondly, we used concepts from image analysis to generalize the innovations from the distance parameterization used in the EnKF as a directed local Hausdorff distance (from simulated to observed fronts) whereby a further improvement was achieved by taking into account the reverse measure (from observed to simulated fronts) as well. The workflow was subsequently applied to a series of numerical experiments on synthetic realistically complex test cases with promising results. The next step is a comprehensive examination on real field data as an objective of the study supported by National IOR Centre Norway. In this paper, we apply the history matching workflow to the Norne field where multiple high-quality seismic surveys were conducted. An iterative ES is used for history matching. The estimated model parameters include permeability, porosity, net-to-gross ratio, vertical transmissibility multipliers, fault transmissibility multipliers and saturation endpoints of relative permeability curves. The observations of front positions are acquired from an inversion of the Norne AVO seismic data set. Special attention is paid to the generation of the initial ensemble of reservoir models and the interpretation of inverted seismic data to ensure a proper estimation of the uncertainties for both model variables and data. The results show that additional benefits are received by matching to both production and 4D seismic data which contributes a better understanding of the reservoir and some new insights are gained regarding the performance of the proposed method. The outcomes of the application to the Norne field cases also suggest a couple of topics that are worth of further investigation. The order in which production and seismic data are incorporated, the localization approach, and for example parameterization of production data could all potentially improve the results.
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Foam Coarsening - Behaviour and Consequences in a Model Porous Medium
Authors S.A. Jones, N. Getrouw and S. Vincent-BonnieuSummaryGas injection was introduced to the petroleum industry in the early 1950s. Nevertheless, the process efficiency is impacted by the low density and viscosity of the gas, which decrease sweep efficiency. Foam for Enhanced Oil Recovery (EOR) can overcome the downside of the viscous fingering by increasing the apparent viscosity of the gas. Importantly, the structure of the foam evolves with time due to gas diffusion between bubbles (coarsening). In a bulk foam, the coarsening behaviour is well defined, but there is a lack of understanding of coarsening behaviour in confined geometries, especially in porous media. Nonnekes et al [2014] predicted numerically and analytically that coarsening will cause the foam lamellae to move to low energy configurations in the pore throats, resulting in greater capillary resistance when trying to restart flow.
This study describes foam coarsening in a porous medium and the implications for foam propagation. Foam coarsening experiments have been conducted in both a micromodel and in a rock core. The micromodel is etched with an irregular hexagonal pattern, with a Gaussian distribution of pore diameters. Foam was generated by coinjecting surfactant solution and nitrogen gas into the micromodel. Once steady state flow had been achieved, the flow was stopped. The coarsening behaviour of the foam was recorded using time-lapse photography. The core flood coarsening experiments were carried out using a Bentheimer Sandstone core. Foam was produced by coinjecting surfactant solution and nitrogen at the base of the core. Once a steady state flow was achieved, the flow was stopped and the core sealed off. When flow restarted, the additional driving pressure required to reinitiate flow was measured, and this could be attributed to the stable configuration of the coarsened foam.
The microfluidic results found that the bubbles coarsened rapidly (t < 10 minutes) to the size of the pores. At the completion of coarsening the majority of the lamellae were located in the pore throats with minimum length. Because of the effect of the walls, the behaviour did not conform to the unconstricted coarsening growth laws. Furthermore, results on coreflood showed that coarsening is a rapid process, in agreement with microfluidic results. An increase in the additional pressure required to re-initiate flow was observed for the first 1 – 5 minutes of flow stoppages, while the pressure peaks did not increase for durations above 5 min. The implications of this behaviour for the field scale are also discussed.
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Environmental Consequences of Polymer Flooding
Authors E. Opsahl and R.K. KommedalSummaryWorldwide polymer flooding (PF) is being introduced as a viable option for increasing recovery rates. In PF projects, back-produced polymer are ideally disposed of by reinjection or injection to a deposit well. However, significant challenges with offshore produced polymer water management creates possibilities for intermittent overboard discharge. If polymers are released to the sea, then how does structure of the polymers change over time and is it important for the marine ecosystem? In spite of the polymers having very low toxicity, the sheer volume of polymer applied in a PF constitutes a major hazard. In addition, the impact and fate of these polymers are largely unknown beyond standardized acute toxicity and biodegradability data. Very few studies on toxicological mechanisms and long-term environmental fate exist, likely because of lacking analytical tools and incentives for in-depth studies. Currently, biodegradability is decisive for chemical classification within the Norwegian offshore environmental regulations. Biopolymers satisfy the criteria, while the non-biodegradable synthetics do not and are as such prohibited from use. Nonetheless, modern PF favor synthetic polymers due to a variety of factors, including concurrent use of biocide. This together with harsh reservoir conditions favors development of physio-chemically stable polymers, impeding environmental performance and complicating risk management. Moreover, the regulations does not take into account that these polymers are especially sensitive to physical and chemical degradation. To begin solving this puzzle we have set up 80-days inherent and ready biodegradability studies on a variety of partially hydrolyzed polyacrylamide derivatives. Respirometry allows for continuous monitoring of biotic degradation. After the end of the experiment, size exclusion chromatography with multi-angle laser light scattering (MALLS) will examine shifts in molecular weight (Mw) distribution. Regarding MALLS limitation on low concentrations and “dirty” samples, we aim to overcome those by applying ultrafiltration techniques capable of isolating and concentrating the Mw-range of interest. The results will yield structure-activity relationships for both aerobe and anaerobe, biotic and abiotic degradation pathways. Preliminary results show that the presence of synthetic polymer does not affect metabolic rates. Which means that if any degradation is observed, it must be through abiotic mechanisms. This study is a part of a larger effort to generate data forming a basis for a mechanistic model that can predict environmental performance based on polymer chain-length and structure. We believe such a model can be made through mentioned long-term degradation studies, mechanistic eco-toxicological studies and state of the art analytical techniques.
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Mineral Dissolution and Precipitation Rate Laws Predicted from Reactive Pore Scale Simulations
Authors J.L. Vinningland, E. Jettestuen, O. Aursjø, M.V. Madland and A. HiorthSummaryWhen injecting water into an oil reservoir for pressure support, during an EOR operation or in well treatment operations, the injected water will interact with the formation and the equilibrate with the formation at a distance from the injection point. For some operations the exact composition of the pore water is crucial, and it is of importance to know how fast the chemical interactions are. This is of particular importance when injecting a low salinity brine or optimised brine to improve the microscopic sweep. Normally one uses mixed flow reactors to determine the reaction rates of minerals, in our experience these experiments greatly overestimate the reaction rates compared to core flooding experiment. Core scale simulations, used to interpret the experiment, also showed that the precipitation pattern of secondary minerals must be such that they allow for contact between the original mineral phase and the pore fluid. Thus allowing for a complete alteration of the primary mineral. In this work we present a pore scale reactive flow simulations using a lattice Boltzmann advection diffusion solver coupled with a geochemical solver to study the effect of uneven precipitation and nucleation of secondary minerals and how this alters the effective reaction rates on the Darcy scale. The dissolution of primary minerals and precipitation of secondary minerals alter the pore space and the changes in permeability and porosity are predicted from the pore scale model. We apply the model to chalk, and use chalk geometries obtained from three types of outcrop chalk: Stevns-Klint, Kansas and Liege. The pore geometries have been obtained by FIB-SEM techniques that has been segmented into binary images. The samples have sizes ranges of from 6 to 8 micrometer and a resolution of 10x10x10 nanometers. The pore scale simulations and up scaled rate laws are compared with core scale flooding experiments on the same type of outcrop chalk.
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Effects of Compositional Variations on CO2 Foam Under Miscible Conditions
Authors S. Kahrobaei, K. Li, S. Vincent Bonnieu and R. FarajzadehSummaryFoam can potentially solve the associated problems with gas injection by reducing the mobility of the injected gas leading to a more stable displacement front. It is known that under immiscible conditions, the presence of oil can be detrimental for foam stability through several mechanisms. Under miscible conditions, there is no separate oil or gas phase; instead, CO2 and oil mix in different proportions forming a phase with varying composition at the proximity of the displacement front. There are then two fundamental questions, which arise from addition of surfactant to the system: (1) what is the nature of the “mixed phase” in the presence of the surfactant, and (2) how do the properties of this mixture change with compositional variations? This study reports the results of core-flood experiments conducted using CO2 and decane (nC10) as the model oil under miscible conditions. Surfactant and a mixture of CO2-decane were co-injected with variations of CO2 molar fractions, mixture volume fractions and total flow rates. We found that separate injection of CO2 or oil with the surfactant solution into the cores creates in-situ fluids that exhibit both low-quality (increasing viscosity with decreasing fraction of surfactant) and high-quality (decreasing viscosity with decreasing fraction of surfactant) regimes. However, upon simultaneous injection of CO2 and oil with the surfactant solution and depending on the molar fraction of CO2 in CO2-decane mixture (xCO2), three distinct regimes were observed. In Regime 1 (xCO2>0.8) the apparent viscosity of the in-situ fluid was the highest and increased with increasing xCO2. In Regime 2 (xCO2<2) the apparent viscosity increased with decreasing xCO2. In Regime 3 (0.2< xCO2<0.8) the apparent viscosity of the fluid remained relatively low and insensitive to the value of xCO2. Shear-thinning rheology was observed in all three regimes: supercritical CO2 foam (xCO2 =1), decane emulsion (xCO2 = 0), as well as CO2-decane-surfactant floods. Moreover, in Regime 1 and Regime 2, there is a transition at shear rates from 10 s-1 to 100 s-1, where the apparent viscosity increases by one order of magnitude. In Regime 3, however, this transition is not observed. Finally, we found that the current implicit-texture foam model cannot simulate our experimental data.
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A Laboratory Study of Production Enhancement Mechanism of Natural Gas Huff and Puff
Authors R. Wang, Bojun Wang, Xueqing Tang, Xinzheng Zhang and Pengyu ChenSummaryIt was found that natural gas could dissolve into B pool crude and formation volume factor could increase to 1.23. Crude oil viscosity was significantly decreased by 50%, indicating viscosity drop mechanism. 1D and 2D visible microscopic experiments revealed foamy oil behavior including emulsification, dispersion and displacement. Three phases, i.e. oil-gas phase, foamy oil phase and oil phase could be observed in 2D visible experiments. In long tube physical simulation experiments, formation dip and condensate content had been incorporated to simulate field natural gas huff and puff operations. Good match of cycle recovery factor to date and GOR had been realized.
The production enhancement mechanism revealed by laboratory study of natural gas huff and puff includes viscosity drop, oil swelling, foamy oil behavior. Long tube physical simulation experiments had realized good match in terms of key production indicators. This paper provided an insight into natural gas huff and puff behavior and mechanism through laboratory study.
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Chemical-foam Design as a Novel Approach Towards Immiscible Foam Flooding for Enhanced Oil Recovery
Authors S.M. Hosseini-Nasab and P.L.J. ZithaSummaryFoam flooding as an enhanced oil recovery (EOR) method can greatly improve Water-Alternating-Gas (WAG) injection and Cyclic CO2 injection in the secondary phase of oil production. However, foam flooding suffers from a lack of high efficiency in terms of oil recovery compared with chemical EOR methods. Despite of possibility of generating strong foam in the presence of oil, incremental oil recovery by the foam flooding is limited. Additionally, a noticeable portions of oil recovery by foam flooding are as mixture with a surfactant solutions, which involves the oil separation from emulsion which won’t be economically favorable. To tackle these issues, this paper presents experimental study of a novel alkali-surfactan-t foam(ASF) flooding process as a chemical-foam design to improve immiscible foam flooding. The ASF enhanced oil recovery (EOR) process involved the use of alkali-surfactant solution as a slug and foam as the drive to mobilize and displace the remaining oil after water flooding process. In this study, a blend of two type of anionic surfactant formulations was formulated for slug and drive: IOS, which exhibits low interfacial tension (IFT), AOS which creates strong foam. Prior to the oil recovery experiments, foam mobility reduction behavior at the transient and steady state condition in the absence of oleic phase was investigated. During this, experiments performed using the Bentheimer sandstone cores, pressure-drop measurement aimed to determine foam solutions’ ability to reduce total mobility. X-ray CT images were taken during foam generation to find out the stability of advancing front of foam propagation and to map the gas saturation. Then, proposed ASF strategy for enhanced oil recovery was tested through the co-injection of immiscible nitrogen gas and slug/drive surfactant solutions with three different formulation properties in terms of IFT reduction and foaming strength capability. The performance of this ASF slug/drive chemical formulation was evaluated by a core-flood test on Bentheimer sandstone rock with the aid of X-ray computed tomography. The discovered optimal formulation contains a foaming agent surfactant, a low IFT surfactant, and a co-solvent, which has high foam stability and low IFT (1.6 *10–2mN/m). This co-injection gave higher oil recovery and much less MRF than the same process with only using a foaming agent. Oil displacement experiment revealed that co-injection of gas with a blend of surfactants containing co-solvent can recover a significant amount of oil recovery (33% OOIP) over waterflood.
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Effect of Newtonian and Non-Newtonian Viscosifying Agents on the Stability of Foam for EOR - Part I, under Bulk Condition
Authors S.M. Hosseini-Nasab, M. Taal and P.L.J. ZithaSummaryFoam has shown poor stability with respect to oil for enhanced oil recovery (EOR) applications, and stimulation processes in the oil-well operations for the oil fields.This paper presents a laboratory study to investigate the effect of Newtonian and non-Newtonian viscosity enhancement materials on the stability of foam under bulk conditions. For this goal, glycerol and hydrolyzed polyacrylamide (HPAM) were utilized to enhance the viscosity of foaming agent solutions, which were composed of Alpha-Olefin Sulfonate (AOS) surfactant and salinity. To this end, a comparative study of the foam stability for the solution containing different percentages of glycerol and polymer was undertaken. In the foam stability analysis which examined in the absence of the oleic phase, several characteristics such as foam volume evolution, foam half-decay time and a liquid fraction of foam were measured over a wide range of concentrations. Measuring conductivity and volume of injected gas during foam generation and foam decay provided the foam capacity (FC) and the maximum density (MD) to characterize the generated foam more accurately. Results of bulk foam experiments indicated polymer and glycerol could either increase or reduce the foamability, but both materials increased foam stability with the certain range of concentration. This could be explained by the fact that increasing the viscosity of the liquid phase of foam attributed to decreasing the velocity of liquid drainage out of the foam structure. Tow regimes of foam drainage and coalescence were different for the same viscosity of solutions containing either glycerol or HPAM polymer. The solutions containing glycerol exhibited a small but sharp decay right after gas sparging stopped, while for high polymer concentrations this didn’t happen.
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