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IOR 2021
- Conference date: April 19-22, 2021
- Location: Online
- Published: 19 April 2021
61 - 77 of 77 results
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Monitoring subsurface temperature from radar scans using machine learning with applications to EOR using thermal injection
Authors K. Van den Doel, G. Stove and M. RobinsonSummaryTechnological advances and depletion of easily extracted oil reserves have led to the development of enhanced oil recovery (EOR) methods that allow significantly more oil to be extracted from a reservoir. An increasingly commonly used technique uses thermal injection, which requires a good knowledge of the subsurface thermal conditions.
Temperature observation wells (TOW) are used to measure subsurface temperature profiles, an expensive and invasive process.
We present a noninvasive method for the remote monitoring of subsurface temperature using low frequency radar pulses. Radar surveys were performed at 40 locations near TOWs in an oilfield and returns were correlated, after signal processing to extract the modulation, with measured down hole temperatures by machine learning techniques. The TOW temperature logs were fed to an autoencoder/decoder network, compressing the data to 3–5 neural activations. A feedforward neural network was then trained on the outputs of the autoencoder to predict the activations from the radar data and finally converted into actual temperature logs using the decoder.
The results were evaluated by excluding one of the 40 data sets from training and use the remaining data sets to predict the excluded site, resulting in 40 blind tests. We believe results are encouraging, though not yet fully reliable and we discuss further avenues for improvements.
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A Predictive Approach for Condensate Blockage Risk Evaluation with Limited Data Availability
More LessSummaryCondensate blockage is a major risk in gas-condensate field development. In the investigated field, the initial reservoir pressure is close to the dew point, leading to condensate dropout and banking from the very beginning. The uncertainty in condensate blockage in the absence of reliable SCAL measurements is considered one of the main challenges. In this work, two approaches were presented to approximate gas-condensate relative permeabilities including high-velocity flow effects. Furthermore, condensate blockage mitigation methods are evaluated.
The first investigated method is that of Whitson, based on the relation krg=f(krg/kro) in which PVT data and analog coreflood experimental data were used to generate relative permeabilities, also including a model for the capillary number effect. In the second method, a digital rocks SCAL analysis, based on Lattice Boltzmann two-phase flow simulation on a microscale 3D scan of remnants of sidewall core plugs, was used to simulate the relative permeabilities at low to high capillary numbers. For implementation of the curves in the dynamic simulation, the model by Henderson was used.
The estimated relative permeability curves for different rock types were used directly in reservoir simulation to evaluate the risk of condensate blockage. In both methods, the effects of high velocity and non-Darcy flow were considered. The simulation results show that the designed gas plateau production rate cannot be maintained even for a few months. However, in an artificial single-phase gas flow case in which the presence of condensate is not influencing the gas flow, the gas plateau production could be sustained up to four years. As a result, the field needs to be produced three to four years longer to reach the same recovery factor, and thus significantly less return on investment is expected.
Comparing both generated relative permeability curves, it is remarkable that the immiscible relative permeability curves (at lower capillary numbers) do not differ significantly from each other, despite the fact that neither of them is based on conventional SCAL experiments. Furthermore, a gas cycling scenario, well placement optimization, and a near wellbore treatment with wettability altering surfactants were analyzed in numerical simulations with promising preliminary results to mitigate condensate banking. The risk of condensate blockage for a real case scenario in the absence of reliable SCAL measurements, by adapting and comparing two approaches to approximate relative permeability curves including high-velocity flow effects, was evaluated and numerically analyzed in the present work.
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Analysis of Density, Viscosity and CO2 Solubility in the Water-Oil-CO2 System for CO2-WAG Simulation
Authors L. Bastos, M.O. Rios, G.M.N. Costa and S.A.B. Vieira de MeloSummaryCO2 injection has been considered as an advantageous method for improved oil recovery (IOR) in terms of increasing the oil recovery factor as well as for carbon storage due to environmental issues. Water alternating CO2 injection (CO2-WAG) has recently been evaluated to improve the sweep efficiency and promote CO2 mobility control, but further studies are needed for a better understanding. In this study, a comparative evaluation of different methods was done to calculate the density, viscosity and solubility of CO2 in aqueous and oily phases, for CO2-water, CO2-oil and CO2-water-oil systems. In addition, the behavior of these properties was analyzed through CO2-WAG simulations. The results indicated high accuracy of the semi-empirical correlation proposed to calculate CO2 solubility in water, with an average deviation of 4.17%. For the aqueous phase density, an average deviation of 0.25% was obtained. The effects of swelling and extraction of light components on the oil properties along the flow due to the presence of CO2 in the system were also observed. The analysis of CO2-water-oil system, relating to the CO2-WAG injection, shows that the CO2 solubility is much higher in the oil phase than in the aqueous phase. However, according to preliminary results, the CO2 solubility in water also affects the oil recovery factor (around 5%) during CO2-WAG simulation.
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New Correlations to Calculate the CO2-Oil Interfacial Tension Including the Asphaltene Precipitation Effect
Authors I.E. Lins, P.H.A. Dantas, G.M.N. Costa and S.A.B. Vieira de MeloSummaryCOi-based Enhanced Oil Recovery (CO2 EOR) methods have been widely applied and studied in the recent years due to their capability to increase the reservoir recovery factor, as well as an alternative for carbon capture and storage. For instance, CO2 EOR projects have been extensively employed in the Brazilian Pre-Salt reservoirs to take advantage of the high CO2 content in the associated gas. However, CO2-oil interfacial tension (IFT) strongly affects the performance of CO2 EOR processes because the major mechanisms of CO2 injection depend on oil swelling and viscosity, which govern the capillary number and the oil displacement in the porous media. Thus, an accurate modeling of the CO2-oil IFT is required to reach reliable numerical reservoir simulations of CO2 EOR methods. For this reason, this work used CO2-oil IFT and oil characterization data from the literature over pressures up to 55.15 MPa and temperatures from 40 to 70°C – typical conditions of Pre-Salt reservoirs – to develop empirical equations for the CO2-oil IFT prediction. First, new equations to calculate IFT as a function of pressure and CO2 solubility in oil, for dead oils. Afterwards, a sensitivity analysis was performed to evaluate the factors that most affect IFT for live and dead oils, such as pressure, temperature, and oil molecular weight and density. Subsequently, correlations for IFT prediction as a function of the three most relevant factors were proposed. The new equations were validated with additional experimental data from the literature. They are able to predict the CO2-oil IFT under Pre-Salt conditions with high accuracy, providing an absolute average deviation of 6.28% for dead oils and 8.34% for live oils, which are much more accurate than the Parachor model – usually chosen in the numerical reservoir simulators –, which yields 23.38% and 49.69%, respectively. Emphasis should be given to the applicability of the new proposed correlations to calculate IFT in numerical reservoir simulation, once they require low computational efforts, contrasting the overcomplexity of other recently developed equations, which are unfeasible for simulations purpose. Finally, an unprecedented procedure was proposed to examine the effect of the precipitated asphaltenes on the CO2-oil IFT, relating it to the Asphaltene Onset Pressure (AOP) curve. The results are presented with Figures and Tables and properly discussed.
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Upscaling Miscible CO2 EOR Processes: Characterisation of Physical Instabilities
Authors P. Ogbeiwi and K. StephenSummaryObjectives/Scope:
An approach for upscaling of miscible displacements is presented which adequately represents physical instabilities such as viscous and heterogeneity induced fingering on coarser grids using pseudoisation techniques is presented. The approach has been applied to compositional numerical simulations of two-dimensional and three-dimensional reservoir models with a focus on CO2 injection.
Methods:
The approach is based on the pseudoisation of relative permeability and the application of transport coefficients to upscale viscous and heterogeneity induced fingering in a multi-contact miscible CO2 injection in a black oil- water system. Fine-gridded compositional simulations of 2D cross-sectional and 3D reservoir models were performed for calibration purposes. The cases considered included a homogeneous 2D model and heterogeneous 2D and 3D models.
The effects of transmissibility schemes on the performance of the fine-grid 3D miscible displacement process was quantified by considering the minimisation of grid orientation errors by each scheme. The permeability and porosity distribution of the 3D model were extracted from a quarter five-spot of the SPE 10th comparative project. Pseudo-relative permeability curves were computed using various pseudoisation techniques and these were applied in combination with transport coefficients which account for small-scale variations in phase composition and behaviour to upscale the fine-grid simulations to coarser scales. Results and Conclusions:
We upscale the fine grid compositional 2D and 3D reservoir models to coarser grid compositional flows. In the fine-grid homogeneous and heterogeneous 2D models, four fingering regimes were observed which we link to very-early time, early time, intermediate time, and late time regimes. These regimes occur both near and far away from the injection well. Our results show that fingering behaviour is adequately captured and represented in the upscaled coarse grids.
In the 3D model, a nine-point transmissibility weighting was required to adequately reduce grid orientation effects and was thus employed in the upscaling procedure of the 3D models. The robustness of the upscaled models was assessed by comparing the total volume of fluid produced versus pore volume of fluid injected, and the saturation profiles and history of the upscaled models with those of the fine-grid simulation. The accuracy of the results of the pseudoisation procedures was assessed by applying statistical analysis to compare them to the results of the fine-grid simulations. The results show that the coarse models provide accurate predictions of the miscible displacement process and that the fingering regimes are adequately captured in the coarse models.
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Specificities of surfactant-polymer flooding modeling and its role in the technology implementation at the Tatneft plays
Authors L. Minikhairov, A. Lutfullin and A. GaifullinSummaryPJSC Tatneft has significant experience in the mature oil fields development and the application of various “local” low-volume technologies for increasing oil recovery, flow deviation and conformance control. Currently, in the context of residual recoverable reserves decrease, one of the main tasks of the company is to test and replicate technologies aimed at increasing the ultimate oil recovery factor. One of the optimal technologies that can solve the current problem is surfactant-polymer flooding technology, which is chosen due to high levels of formation water salinity, which greatly restricts the use of alkaline compositions and decrease the effectiveness of polymer flooding. A distinctive feature of this technology from those currently available in the company is the injection volumes (more than 10% of the pore volume) and a significant increase in the final oil recovery factor of the oil field. Considering the capital intensity and the importance of the project for the organization of surfactant-polymer flooding, PJSC Tatneft pay great attention to high-quality preparatory work, including laboratory filtration studies, the results of which were then used during the reservoir modeling of the process to form the most reliable feasibility study of the technology. This paper will highlight the features of the preparatory work, the applicability of their results in reservoir modeling, the assessment of various options for implementing the technology, the results of forecast scenarios and the role of the obtained calculations in the feasibility study of the technology implementation. To assess the correctness of setting the properties of the surfactant-polymer composition in the reservoir model, a core model was built, which was used to simulate laboratory filtration studies. There were built more than 150 forecast scenarios for the surfactant-polymer composition injection, differing in the size of the injected pore volume, surfactant and polymer concentrations, as well as the sequence of surfactant and polymer injection.
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Advanced Surfactant-Polymer EOR Pilot in Algyő Field, Hungary; Experiences and Lessons Learned
Authors S. Puskás, T. Ördög, M. Törő, G. Kálmán, R. Nagy, L. Bartha, Á. Vágó, J. Dudás, I. Dékány, R. Tabajdi, I. Lakatos and G. SzentesSummaryExtensive R&D activity provided reliable basis for testing a reservoir-specific surfactant-polymer mixture as EOR flooding pilot performed in the largest multi-layered (stacked) hydrocarbon occurrence at the Algyö field. The target formation was a sandstone reservoir with 70 mD permeability on average bearing low viscosity oil (0.64 cP at 98 °C and 190 bar).
The injected SP solution contained a specific surfactant blend developed by MOL and his Hungarian university partners, and a mobility controlling agent was a commercial copolymer of acrylamide and ATBS. For the preparation of the SP solution, after additional filtration, formation water was used at the site. During the pilot period, altogether 1/3 pore volume of SP solution was injected into the reservoir.
The surfactant/polymer solution was injected into two injection wells starting from April 2016 and was intended to finish in 2019, after 45 months of continuous injection period. The injection was started with 100 m3/day/well flow rate of chemical mixture, containing 15,000 ppm surfactant and 1,000 ppm polymer driven into the reservoir using injection well head pressure of 0 bar. Most important parameters and effects of the pilot were continuously recorded and evaluating the reservoir response as a function of the injected volume including both injection and production wells (seven oil wells were operating around the two injection wells). It should be noted that due to the high heterogeneity of the reservoir, a fine tuning of the injection plan supported the technology through the whole frame of the pilot. The successful upscaling of the surfactant manufacturing and the easily available raw materials provided a problem-free supply of surfactant with standard quality. Various laboratory measurements were performed to control the polymer and surfactant concentration as well as the rheological and interfacial properties of injected SP solution. In addition one of the main advantage of the EOR method was that the produced emulsion could be easily broken into bulk fluids.
This paper summarizes the workflow and results of the pilot performed in the past four years. The results of this pilot provided reliable information and adequate basis to start a new project of similar field-scale chemical EOR technology for other blocks, hoping that it will further increase the recovery factor in the Algyö-2 reservoir and yielding substantial incremental oil production in matured, depleted fields in the coming years.
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Role of Water Chemistry on the Adsorption Behavior of a Saponin-based Biosurfactant on the Sandstone Surface
Authors J. Amanabadi, M. Simjoo and M.S. MousapourSummaryBiosurfactants have been received more attention in oil recovery due to their low-cost and environmental friendly characteristics. In this study, we investigated adsorption behavior of a saponin-based biosurfactant named SUTBS which was extracted from the leaves of one of the Iranian plants growing in the southern part of the country. To this end, adsorption analysis of the SUTBS solution was performed on a clayey sandstone surface in the presence of different seawater solutions under high temperature that represents reservoir conditions. Role of water chemistry on the surfactant adsorption was addressed by changing the composition of seawater (SW) through tuning ionic strength and also manipulation of divalent ions. Adsorption analysis was then performed by contacting surfactant solution with the rock powder at 80 °C while tracking surfactant concentration using UV-spectrophotometer. Results showed that surfactant adsorption in the presence of SW brine increases with surfactant concentration up to 1500 ppm and beyond that it levels off to a plateau value that represents a Langmuir-type isotherm. In order to explore the effect of ionic strength, surfactant solutions were prepared by SW brine and its different dilution (0.5SW and 0.1SW). As to results, a lower surfactant adsorption was observed for diluted brines such that at surfactant concentration of 1500 ppm surfactant adsorption in the presence of 0.1SW was almost half of the SW brine. To check the role of aqueous ions on the adsorption behavior, a brine solution without any divalent ions was synthesized while keeping ionic strength equal to the SW brine only by adjusting NaCl concentration. It was found that removing divalent ions from brine solution caused a reduction in the surfactant adsorption level by 35%. Finally, to get further insights into the role of divalent ions (Mg2+, Ca2+ and SO42-), three SW brines were prepared such that in each solution only one of the divalent ions became present and the two other ones were excluded. Ionic strength of all these solutions was kept constant by adjusting NaCl concentration. As to results, adsorption level in the presence of sulphate-rich brine decreased as compared to the native SW brine. However, a higher adsorption level was observed for the case of divalent cation-rich brines. These observations could be discussed in terms of physicochemical interactions among aqueous ions/surfactant molecules/rock minerals. Findings from this study shed light on the importance of water chemistry to design an appropriate surfactant flooding.
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Initiation of a surfactant-polymer flooding project at PJSC Tatneft: from laboratory studies to test injection.
Authors M. Toro, M. Khisametdinov, D. Nuriev, A. Lutfullin, A. Daminov, A. Gaifullin, S. Puskas and T. OrdogSummaryPJSC Tatneft develop oil fields in the Republic of Tatarstan, mainly belonging to the category of mature, which leads to the systematic application of various enhanced oil recovery technologies for stimulating the formation, using gel, emulsion and other chemical compositions. Despite the high water cut, at a number of Tatneft plays there are favorable and and potential economic profitable conditions for the implementation of large chemical flooding projects, for example, using surfactant-polymer flooding technology. The choice of surfactant-polymer composition is generally due to high level of formation water salinity, which severely limits the use of alkaline compositions and reduces the effectiveness of polymer flooding. The initiation of the surfactant-polymer flooding project was conducted through several main stages: the development of primary criteria for the optimal areas selection for the technology application, the primary areas selection and a detailed description of their geological and physical conditions, laboratory studies on the selection of composition components that provide the highest level of oil displacement efficiency, in conditions close to reservoir, performing a test injection of the composition at a potential site of application, analyzing the results and adjusting the chemical composition and obtaining initial data for conducting reservoir modeling of pilot project. Laboratory studies were conducted according to accepted programs for studying the compatibility of chemical agents with injected and formation waters, studying the properties of surfactants, for example, interfacial tension and adsorption, the rheological behavior of polymer solutions depending on the concentration and shear rate, studying the properties of surfactant-polymer compositions and conducting filtration studies. All laboratory filtration studies were conducted using oil from the test injection site on the cores of 50 cm length. The data obtained during laboratory studies were used to conduct reservoir modeling of the pilot surfactant-polymer flooding and to form a feasibility study for testing and replicating the technology.
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Upscaling Simulations of 3D Displacement Processes that Include Change of Wettability using Analytically Derived Relative Permeability
Authors H. Al-Ibadi, K.D. Stephen and E. MackaySummaryWe introduce an upscaling method that can be used to improve the accuracy of forecasts of EOR processes that involve changes to fluid mobility either by modifying wettability and interfacial tension as in surfactant flooding, alkaline flooding and low salinity water flooding, or by increasing the injectant viscosity as in polymer flooding. The suggested upscaling method is designed to solve the two numerical artefacts associated with discretization of these processes which include well know dispersion effects as well as more recently reported pulses. Simulations involving changes to wettability or interfacial tension usually require two sets of input relative permeability curves. In this newly derived upscaling method, we show how to develop a single set of pseudorelative permeability curves for coarse scale models to represent fine scale behaviour. The shape of the derived properties is based on the analytical solution of the fractional flow theory of chemical flooding. Using this analysis, we are able to build a pseudo relative permeability that honours the correct velocity of the formation and chemical waterfronts with an appropriate oil banking interval. It also ensures the sharpness of the shock fronts. We derived a single set of relative permeability curves, avoiding numerically based pulses. We built pseudo-relative permeability curves that includes the impact of effective concentration range and physical dispersion induced by geological heterogeneity.
The numerical results of the upscaled models were compared against the fine scale models. We analysed the flow behaviour in 1D homogenous models and 2D models of communicating and non-communicating layers. We also analysed flow in 2D and 3D models of correlated random permeability. Our method is shown to work for all of these cases. However, for unfavourable displacement in strongly heterogenous models of correlated random permeability, some tuning was required due to significant fingering effects. Secondary and tertiary flooding were considered in the analysis.
This novel upscaling method was able to control the artefacts of numerical pulses and dispersion. It also simplified the complex modelling of these processes, improving the upscaling step and decoupling the representation of solutes. We reduced the requirement for relative permeability curves to one set, and removed the need to simulate solutes such as polymers and salinity. This means that simplified fast simulations of oil displacement can be run.
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Analytical and Numerical Analysis of EOR process in Stratified Reservoirs
Authors H. Al-Ibadi, K. Stephen and E. MackaySummaryWe develop analytical tools to predict the flow behaviour and solute transport during advanced EOR processes in stratified models as an extension to simpler waterflood models based on fractional flow theory. We also derive an extended set of dimensionless numbers that are particularly designed to quantify the flow behaviour in EOR processes. These analyses are essential for upscaling and improve the accuracy of predictions. We consider EOR flow conditions in which layered models are affected by retardation and dispersion of flow and include variations in wettability and relative permeability as well as other petrophysical properties. We developed our analysis using the principles of the fractional flow theory, applied to EOR processes. A revised model corrects for the effects of numerical and physical dispersion. By grouping and rearranging the derived formulae, we obtain dimensionless numbers and scaling groups to evaluate the effect of various scenarios of properties contrast between layers. We investigated the impact of various parameters on the recovery factor and the water cut from the production data. The scaling groups can be utilized to identify properties of the model that should be changed so we can reproduce flow behaviour from small scale (e.g. core scale) to larger scale (e.g. reservoir scale). The new analytical model was validated against numerical solution of low salinity waterflooding with varying degrees of heterogeneity and mobility ratio, where a very good match was obtained.
These analytical tools enable us to obtain ultra-fast predictions complex flow during EOR processes without a need to run a numerical simulator and with better accuracy. The approach can potentially be applied in streamline simulators and used as flow diagnostics to improve analysis of EOR methods where retardation and dispersion occur.
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An Experimental Study of Steam-Solvent Coinjection for Bitumen Recovery Using a Large-Scale Physical Model
Authors K. Sheng, R. Okuno, M. Imran, P. Nakutnyy and K. NakagawaSummaryThis paper presents a detailed investigation into compositional flow in solvent-assisted steam-assisted gravity drainage (SA-SAGD) with multicomponent hydrocarbon solvent “condensate”, which is readily available near thermal operation sites. Designing SA-SAGD with condensate requires understanding the complex interplay between phase behavior and fluid flow that affects bitumen production and solvent recovery.
This research consisted of three stages. First, an SA-SAGD experiment was performed using a cylindrical physical model with an inner diameter of 0.45 m and a length of 1.2 m. Steam and synthetic condensate (2.7 mol%) were coinjected at 3500 kPa. Second, the experimental data were history-matched by using a numerical model, and the resulting model was analyzed for the detailed analysis of solvent flow behavior. Third, observations of compositional details in the SA-SAGD experiment were further investigated with a simulation case study using stochastic realizations of a 3-D heterogeneous reservoir. We present a novel way of analyzing how much of the injected solvent was used for in-situ bitumen dilution beyond the edge of an SA-SAGD chamber, which is referred to as “utilization factor” in this paper. Solvent utilization factor is related to, but different from solvent recovery factor because different components have different volatilities in the coinjected condensate.
SA-SAGD experimental results showed that the produced condensate was heavier than the injected. Material balance analysis showed that the in-situ condensate composition for bitumen dilution was similar to the injected condensate composition, but the volatile components (C1 and C4) had lower recovery factors. The simulation case study for an upscaled 3-D heterogeneous reservoir confirmed that a large fraction of the volatile solvents in the condensate was used for in-situ bitumen dilution. The solvent recovery factor that has been used as an economic indicator for SA-SAGD does not represent how much of the injected solvent is used for in-situ bitumen dilution.
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Generalized Analytical Solutions for Shale Gas Production in Compressible Porous Media Including a New Scaling Time
More LessSummaryShale gas has been established as a key energy source over the last decades. Tight permeability, non-Darcy flow mechanisms, adsorption and compressibility make shale gas formations more challenging to model than conventional reservoirs. The aim of this work is to present analytical solutions overcoming those challenges.
We model shale gas production from a 1D porous medium, where a well or fracture with constant pressure is assumed at one side and a noflow boundary at the other (e.g. due to symmetric geometry between multiple fractures). The system is depleted accordingly. Gas is stored as mobile phase in the pores and adsorbed phase on the matrix surface as modeled by a Langmuir isotherm. The gas and rock are both compressible; when pressure is reduced, gas expands (according to a real gas equation of state), while porosity is reduced. The porosity reduction reduces intrinsic permeability. Non-Darcy flow, which is important for shale gas flow in tight porous media, is accounted for via apparent permeability depending on the Knudsen number.
The partial differential equation describing this system can be formulated as a nonlinear diffusion equation in terms of the conserved property of mass per bulk volume of free and adsorbed gas. The well pressure boundary condition corresponds to a fixed value of as boundary condition. Similarly a uniform initial pressure corresponds to a uniform initial . This system is comparable to the form described by McWhorter and Sunada (1990) for spontaneous imbibition where they derived universal analytical solutions regardless of the shape of the diffusion coefficient which could depend arbitrarily as function of the conserved property, in their case fluid saturation. Analytical solutions are thus obtained that can give spatial profiles, at given times, of pressure, adsorption, porosity and apparent permeability, in addition to time profiles of gas recovery. In accordance with the analytical solution, it is shown that gas recovery follows a square root of time profile at early times before the no-flow boundary is encountered. Late time behavior and validation is investigated using numerical solutions. We further adapt the work by Schmid and Geiger (2012) who suggested a time scale for the analytical solution during spontaneous imbibition. Adapted to our case, a similar scaled time results in the same depleted fraction of recoverable mass under the given pressure conditions and scaling different cases results in full overlap of recovery profiles at early time, typically to obtainable recoveries of 35–50%.
The late time behavior profiles deviate as individual cases may leave the square root profile at different recovery values and with different trends vs time.
The role of system length, adsorption isotherm, rock compressibility, porosity-permeability relations and non-Darcy effects are examined to see how they contribute to increase or reduce production rate and time scale, affect profile shapes and the amount produced when the no-flow boundary is met.
To our knowledge, no analytical solution yet exists for shale gas production which is able to account for either nonlinear adsorption, non-Darcy flow, compressible porous media or permeability reduction.
Keywords: shale gas production; compressible low permeable porous media; non-Darcy flow; generalized time scale; analytical solutions.
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Theoretical Comparison of Two Setups for Capillary Pressure Measurement by Centrifuge
Authors J. Abbasi and P.Ø. AndersenSummaryCapillary pressure is routinely measured using a centrifuge setup where capillary forces retain a heavy, wetting phase (e.g. water) and keep a light, non-wetting phase from entering. By increasing the rotational speed of the centrifuge, the density difference of the phases forces the heavy fluid out, while the light fluid can enter. In this work, we consider and compare the behaviour of two centrifuge setups: In the first setup the core face closest to the rotation axis is open to non-wetting phase, while the core face farthest from the rotation axis is open to wetting phase; labelled Two-Ends-Open, TEO. At increased rotation, this setup generates strictly co-current flow of both phases from the inner towards the outer radius. In the second setup, only the outer radius surface is open and is exposed to the light non-wetting phase; labelled One-End-Open, OEO. All other core faces are closed. At increased rotational speed the wetting phase is forced out the open face and non-wetting phase must flow in opposite direction through the same phase. This setup induces strictly counter-current flow. The two systems are formulated mathematically and solved by implicit pressure and explicit saturation (IMPES) numerical discretization. The standard co-current setup is validated by comparison with commercial software. Experimental data from the literature are used to parameterize the models.
It is mathematically, and with examples, demonstrated that the same equilibrium is obtained in both systems with the same rotational speed. This equilibrium, as represented by saturation and capillary pressure distributions, is only dependent on the rotational speed, capillary pressure curve, fluid densities and system geometry, not the relative permeabilities or fluid viscosities. The difference in flow regimes and transient data can be used to obtain better estimates of the relative permeabilities, which previously would need independent measurements using time consuming core flooding tests. It is observed that the counter-current setup has longer corresponding equilibration time scales than the co-current setup under otherwise identical conditions. For saturation function measurement it is still quick relative to comparable techniques.
By performing these tests in parallel, a significant difference in flow regimes and thus different dependence on saturation intervals makes it possible to better match relative permeabilities in addition to the capillary pressure. Greater intervals of the functions can be determined with greater accuracy. Measurement of flow regime dependent relative permeabilities can be captured by an expansion of the model.
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Pushing Oil Recovery Technical Limits For Liquids-Rich Shales
Authors M.R. Fassihi and A. KovscekSummaryEven with the great advancements in hydraulic fracturing and shale well completions, the current recovery factor for liquid-rich shale is about 5% whereas that for gas-rich shale is about 25%. This indicates that the full potential of unconventional resources has not yet been realized. The large initial production rate followed by a rapid decline makes the unconventional industry heavily dependent on continuous drilling and completion. With the areas available for further drilling shrinking, there is a need to revive and sustain production in existing shale wells. Hence, this paper discusses the fundamentals of EOR application in unconventional reservoirs. Through a review of existing field tests, and the knowledge base of EOR mechanisms in shale, guidelines are provided for successful EOR application in liquid-rich shales. Shale resource characterization is fundamental to any future application of EOR. Thus, advancement in this area is emphasized including core-scale studies, discrete fracture network modeling, and simulation with coupled flow and geomechanics. Results from application of chemical blends, gas injection huff-n-puff, and new hybrid methods are discussed. It is shown that EOR as a drive process is very inefficient in shale and requires the presence of a natural/complex fracture system. It is indicated that gas injection Huff-n-Puff could increase the primary recovery by an additional 50%. On the other hand, chemical blends could provide up to 20% increased recovery due to wettability alteration. Hybrid methods combining chemical blends with the hydraulic fluids and gas injection Huff-n-Puff do provide additional uplift in oil recovery. Through a review of the field results, this paper provides new screening criteria for application of EOR to liquids-rich shale
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Potential of Foam Enhanced Oil Recovery Process for a Strongly Oil-Wet and Heterogeneous Carbonate Reservoir
Authors L. Ding, S. Jouenne, O. Gharbi, M. Pal, H. Bertin, M.A. Rahman, C. Romero and D. GuerillotSummaryThe feasibility of foam enhanced oil recovery (EOR) for a heterogeneous carbonate reservoir in the Middle East with medium temperature (55°C) and high formation salinity (above 16% TDS) is presented here.
The promising surfactant formulations were firstly evaluated based on solubility tests and bulk foam tests. Afterwards, a series of core flooding experiments both in the absence and in the presence of crude oil were performed on Estaillades Limestone, a heterogeneous carbonate presenting reasonable similarities with the actual formation. In these foam tests, the influence of foam quality, injection velocity and surfactant concentration on foam strength and incremental oil recovery were investigated. Then, the lab results were reproduced by numerical simulation using a commercial reservoir simulator, where the model parameters were obtained after history matching. Finally, a synthetic 2D heterogeneous model was established to investigate how foam can assist in improving oil recovery for a stratified heterogeneous reservoir.
An Alkyl Poly-Glycoside (APG) surfactant was firstly selected based on its prominent foamability and foam stability from bulk foam tests. The optimal foam quality is found to be around 70% from foam quality scan tests in the absence of crude oil. Moreover, foam still can be generated under strongly oil-wet conditions, and it is observed that the presence of oil and surfactant concentration have negligible effects on the optimal foam quality. However, the foam strength in high quality scheme is largely dependent on the surfactant concentrations. More than 20% OOIP of the water flooded residual oil was recovered after co-injecting 5.0 total pore volume (TPV) of nitrogen and 0.5 wt.% APG surfactant (in synthetic seawater brine) at 70% foam quality (4 ft./d). The numerical simulation results indicate that the permeability effect on foam strength and foam stability need to be considered in order to accurately model the foam behavior in heterogeneous reservoirs.
In this presentation, the foam dry-out, shear thinning, surfactant concentration, permeability and oil saturation effects on foam transport in a heterogeneous carbonate were systematically investigated. The results of this study demonstrated the feasibility of foam EOR for a strongly oil-wet and heterogeneous carbonate reservoir with medium temperature and high formation salinity.
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Keynote: Comparing Benefits of CO2 storage and CO@EOR from a Climate Mitigation Perspective
Authors P. Ringrose, B. Nazarian and A.M. ZadehSummaryOver the coming decades our society has a significant challenge in achieving globally significant reductions in greenhouse gas emissions. Numerous studies show that large-scale geologic disposal of CO2 from industrial emissions will be essential to achieve this objective. There are currently 21 large-scale CCS facilities in operation. Of these large-scale CCS projects, five use geologic storage in saline formations (Sleipner, Snehvit, Quest, IBDP & Gorgon) and together inject nearly 6 million tonnes CO2 per annum (Mtpa). The remaining large-scale projects mainly use CO2EOR as the storage vehicle. Enhanced oil recovery using carbon dioxide (CO2EOR) can have a dual purpose: (a) To recover additional oil, thereby supplying energy and additional revenues; and (b) to mitigate climate change by reducing anthropogenic CO2 emissions.
Historically, CO2EOR projects have tended to maximize oil production as a function of the CO2 injected. There are various options proposed to enhance the climate mitigation effect of CO2EOR projects by maximizing the ratio of the CO2 injected to the oil produced, or by transiting projects from CO2EOR in the initial stages to pure storage projects in the later stages. However, to achieve net zero-emissions, CO2EOR projects need to include a significant fraction of non-EOR CO2 storage. CO2EOR projects also play an important role in building the infrastructure needed for large-scale carbon capture, utilisation, and storage. We illustrate these potential pathways using examples of large CCUS/CCS projects, both from offshore Norway and onshore Canada.
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