bluuebunny/crossref_metadata_2025_split huggingface dataset:
Automated Interpretation Tool for Synchronous History Matching of Multiple Scal Experiments with Advance Nurbs Representations of Relevant Functions
Authors: Manasipov Roman , Jenei Bettina 
Published: June 2020

Abstract
Relative permeability and capillary pressure are the key parameters of the multiphase flow in a reservoir. To ensure an accurate determination of these functions in the areas of interest, the core flooding and centrifuge experiments on the relevant core samples need to be interpreted meticulously. In this work, relative permeability and capillary pressure functions are determined synchronously by history matching of multiple experiments simultaneously in order to increase the precision of results based on additional constraints coming from extra measurements.
To take into account the underlying physics without making crude assumptions, the Special Core Analysis (SCAL) experiments are chosen to be simulated instead of using well know simplified analytical or semi-analytical solutions. Corresponding numerical models are implemented with MRST (Lie, 2019) library. The history matching approach is based on the adjoint gradient method for the constrained optimization problem. Relative permeability and capillary pressure curves, which are the objectives of history matching, within current implementation can have a variety of representations as Corey, LET, B-Splines and NURBS. For the purpose of analyzing the influence of correlations on the history matching results in this study, the interpretation process with assumed analytical correlations is compared to history matching based on generic NURBS representation of relevant functions.
A Study on the Adsorption Behavior of Different Surfactants in Carbonate Using Different Techniques
Authors: AlMatouq Hana , Almubarak Majed , Algadrah Abdulkarem , Alhodaythi Waleed 
Published: June 2020

Abstract
Surfactant based foams are used as one of the most effective techniques in controlling gas mobility during gas injection processes. Foam reduces gas mobility in porous media by increasing the gas apparent viscosity and decreasing the gas relative permeability, and hence it helps in improving sweep efficiency. However, one of the critical encounters when using foam in reservoirs is the adsorption of the surfactant on the rock surface. The loss of surfactant to the rock surface will lead to destabilizing the foam and accelerating the collapse rate of foam films. The objective of this paper is to study the behavior of surfactant adsorption in carbonate.
The adsorption of various surfactants in contact with carbonate was evaluated. We compared two different techniques to evaluate the adsorption of surfactant components onto the rock surface. The first method is using a total organic carbon (TOC) analyzer to measure the carbon number in each surfactant over time after being in contact with rock. The second method is using UV-spectroscopy in which the light absorbance at a certain wavelength is measured. The measurements are then used to calculate the total surfactant adsorption onto the rock surface. This paper presents the adsorption behavior of each surfactant studied in detail.
The results obtained by the techniques were compared for two different surfactants. An amphoteric surfactant and an anionic surfactant were used in this study. Results illustrated that both surfactants were adsorbed by the rock minerals. Surfactant 1 showed a higher adsorption value than the surfactant 2. However, the two used techniques to measure the adsorption showed different adsorption values for both surfactants. Using TOC, surfactants 1 and 2 showed a total adsorption of 0.746 and 0.428 mg/grock, respectively. While, using UV-spectroscopy, surfactants 1 and 2 showed a total adsorption of 1.149 and 0.306 mg/grock, respectively.
Understanding the surfactant adsorption behavior is an essential step in the surfactant selection process. Selecting a surfactant with minimal loss to the rock surfaces will lead to keeping the generated foam stable for a longer time in the reservoir and therefore, result in having a higher sweep efficiency.
Optimisation of Polymer Flooding in a Heterogeneous Reservoir Considering Geological and History Matching Uncertainties
Authors: Ibiam Emmanuel , Geiger Sebastian , Demyanov Vasily , Arnold Dan 
Published: June 2020

Abstract
Polymer flooding offers the potential to recover more oil from reservoirs but requires significant investments which necessitate a robust analysis of economic upsides and downsides. Key uncertainties in designing a polymer flood are often reservoir geology and polymer degradation. The objective of this study is to understand the impact of geological uncertainties and history matching techniques on designing the optimal strategy and quantifying the economic risks of polymer flooding in a heterogeneous clastic reservoir.
We applied two different history matching techniques (adjoint-based and a stochastic algorithm) to match data from a prolonged waterflood in the Watt Field, a semi-synthetic reservoir that contains a wide range of geological and interpretational uncertainties. An ensemble of reservoir models is available for the Watt Field, and history matching was carried out for the entire ensemble using both techniques. Next, sensitivity studies were carried out to identify first-order parameters that impact the Net Present Value (NPV). These parameters were then deployed in an experimental design study using a Latin Hypercube to generate training runs from which a proxy model was created. The proxy model was constructed using polynomial regression and validated using further full-physics simulations. A particle swarm optimisation algorithm was then used to optimize the NPV for the polymer flood. The same approach was used to optimise a standard water flood for comparison. Optimisations of the polymer flood and water flood were performed for the history matched model ensemble and the original ensemble.
The sensitivity studies showed that polymer concentration, location of polymer injection wells and time to commence polymer injection are key to optimizing the polymer flood. The optimal strategy to deploy the polymer flood and maximize NPV varies based on the history matching technique. The average NPV is predicted to be higher in the stochastic history matching compared to the adjoint technique. The variance in NPV is also higher for the stochastic history matching technique. This is due to the ability of the stochastic algorithm to explore the parameter space more broadly, which created situations where the oil in place is shifted upwards, resulting in higher NPV. Optimizing a history matched ensemble leads to a narrow variance in absolute NPV compared to history matching the original ensemble. This is because the uncertainties associated with polymer degradation are not captured during history matching. The result of cross comparison, where an optimal polymer design strategy for one ensemble member is deployed to the other ensemble members, predicted a decline in NPV but surprisingly still shows that the overall NPV is higher than for an optimized water food. This indicates that a polymer flood could be beneficial compared to a water flood, even if geological uncertainties are not captured properly.
Dynamic Immiscible Flood Monitoring in Sand Packs Via Frequency Domain Reflectometry
Authors: Kuznetcov Ilia , Kantzas Apostolos , Bryant Steven 
Published: June 2020

Abstract
Dynamic saturation distribution of fluids in oil reservoirs is arguably the most important piece of information petroleum engineers and geophysicists need. It allows them to better characterize oil fields, choose right enhanced oil recovery techniques and make accurate recovery forecasts. The main objective of the present paper is to develop and test a novel non-intrusive technology that enables real time in-situ monitoring of fluid saturations in porous media during immiscible floods.
To achieve this goal we designed, constructed and commissioned a high pressure (up to 25MPa) and temperature (up to 200°C) core-holder with an antenna that allows for low power electromagnetic sweeps in the radio frequency range. A novel inversion algorithm was created and incorporated with our core-holder-pump system that enables dynamic acquisition of the oil and water saturations. Experiments were conducted through sand packs saturated with water and then displaced with oils of varying viscosity (drainage) followed by water flooding (imbibition). Reflection and transmission coefficients in the frequency domain were measured while flooding using a commercial vector network analyzer connected to the core holder. Recorded frequency data was processed with the novel high-resolution inversion technique to obtain impulse reflection and transmission responses in the time domain. These responses were further normalized to dynamically track the water-oil volumetric saturations within the porous media. Every displacement experiment has been performed in both vertical and horizontal positions to emulate water-oil override and underride scenarios. Material balance calculations were performed to validate fluid saturation profiles for all imbibition and drainage experiments every 5 % of the pore volume of the fluids injected.
Frequency domain reflection and transmission electromagnetic responses were measured every 1 % of the fluid injected. Material balance was used to validate the measured saturation profiles. The goodness of fit was calculated between these two independent measurements for every flood experiment performed. The mean-square error was calculated to be around 1.26% of the total pore volume on average. Late breakthroughs and piston-like displacement were observed in the floods with favorable mobility ratios. In contrast, much earlier breakthroughs have been registered in all the experiments with unfavorable mobility ratios due to fingering. All our observations are in agreement with the current theory of immiscible displacement in porous media.
The novel automated system paired with the inversion algorithm were developed to allow for virtually real time monitoring of the fluid saturations during imbibition and drainage displacement cycles. Our technology is shown to be a promising candidate to compliment resistive logging measurements in the field.
Deriving Alkali Polymer Parameter Distributions from Core Flooding by Applying Machine Learning in a Bayesian Framework to Simulate Incremental Oil Recovery
Authors: Steineder Dominik , Vanegas Gisela , Clemens Torsten , Zechner Markus 
Published: June 2020

Abstract
Various physico-chemical processes are affecting Alkali Polymer (AP) Flooding. Core floods can be performed to determine ranges for the parameters used in numerical models describing these processes. Because the parameters are uncertain, prior parameter ranges are introduced and the data is conditioned to observed data. It is challenging to determine posterior distributions of the various parameters as they need to be consistent with the different sets of data that are observed (e.g. pressures, oil and water production, chemical concentration at the outlet).
Here, we are applying Machine Learning in a Bayesian Framework to condition parameter ranges to a multitude of observed data.
To generate the response of the parameters, we used a numerical model and applied Latin Hypercube Sampling (2000 simulation runs) from the prior parameter ranges.
To ensure that sufficient parameter combinations of the model comply with various observed data, Machine Learning can be applied. After defining multiple Objective Functions (OF) covering the different observed data (here six different Objective Functions), we used the Random Forest algorithm to generate statistical models for each of the Objective Functions.
Next, parameter combinations which lead to results that are outside of the acceptance limit of the first Objective Function are rejected. Then, resampling is performed and the next Objective Function is applied until the last Objective Function is reached. To account for parameter interactions, the resulting parameter distributions are tested for the limits of all the Objective Functions.
The results show that posterior parameter distributions can be efficiently conditioned to the various sets of observed data. Insensitive parameter ranges are not modified as they are not influenced by the information from the observed data. This is crucial as insensitive parameters in history could become sensitive in the forecast if the production mechanism is changed.
The workflow introduced here can be applied for conditioning parameter ranges of field (re-)development projects to various observed data as well.
Effects of Heterogeneous Local Swelling and Multiple Pore Types on Coal and Shale Permeability Evolution
Authors: Zeng Jie , Liu Jishan , Li Wai , Tian Jianwei , Leong Yee-Kwong , Elsworth Derek , Guo Jianchun 
Published: June 2020

Abstract
The permeability of fractured sorbing media, such as shale and coal, is mainly controlled by effective stresses and sorption-induced strains. Although the influence of effective stresses on permeability has been extensively studied, how sorption-induced strains affect permeability evolution has not been fully understood. Sorption-induced strains can impact the permeability in opposite ways at different time scales. If the swelling occurs at matrix surfaces (local swelling), the swelling strain purely reduces fracture aperture and results in a permeability decline. However, when the whole rock is fully invaded by injected gas, the swelling of the whole rock (global swelling) increases fracture aperture and the bulk volume, enhancing the permeability. Most existing models only use fracture (pore) pressure to describe rock swelling, assuming that the rock is fully invaded and matrix-fracture pressure equilibrium is achieved. They cannot explain some experimental data because rocks may never be fully invaded during permeability measurement. Moreover, different pore types are not considered and local swelling can be heterogeneous due to complex matrix components.
In this paper, the non-equilibrium effects are depicted by defining two continua (matrices and fractures) with distinct pressure values. The transition between local swelling and global swelling is quantified by the pressure difference between the two systems. The larger the pressure difference is, the heavier local swelling effects will be. And global swelling is only a function of fracture pressure. Different pore types are included in our permeability model. And the heterogeneous local swelling strain is characterized by a splitting strain function.
This model is verified against laboratory data from common permeability measurement conditions. Under constant effective stress and constant confining stress conditions, the permeability changes at different times and becomes stable after a relatively long time. With the matrix-fracture pressure difference first increases to a maximum value and then decreases to zero, local swelling effects change from zero to a peak value and finally drop to zero. By combining permeability curves at different injection pressure levels, 3-D permeability surfaces are obtained. The impacts of rock properties, heterogeneous local swelling, and multiple pore types on permeability evolution are analyzed. Adsorption and mechanical properties control specific regions of permeability curves. Effects of heterogeneous local swelling are determined by the adsorption capacity of the dominant matrix component. The existence of multiple pore types makes the permeability curve deviate from those of single-pore-type cases and affects a wider range of permeability curves compared with heterogeneous local swelling.
Wettability Changes and Interfacial Tension Reduction in Alkali Polymer Flooding of High and Low Tan Number Oils
Authors: Arekhov Vladislav , Hincapie Rafael E. , Clemens Torsten 
Published: June 2020

Abstract
Injection of chemicals into sandstones could lead to wettability alteration, where oil characteristics such as the TAN (Total Acid Number) may determine the wetting-state of the reservoir. By combining the spontaneous imbibition principle (Amott-Harvey method) and interfacial tension indexers’ evaluations, we propose a workflow and a comprehensive assessment to evaluate wettability alteration and IFT when injecting chemical EOR agents. The study focused on examining the effect of alkaline and polymer solutions (alone) and alkali-polymer.
The evaluation focused on comparing the effects of chemical agent injection on wettability and IFT due to: core ageing (non-aged, water-wet and aged, neutral to oil-wet); brine composition (no divalent and with divalent ions); core mineralogy (~2.5% and ~10% Clay) and crude-oil type (Low and high TAN). Amott experiments were performed on cleaned water-wet core plugs as well as on samples with restored oil-wet state. IFT experiments were compared for a duration of 300 minutes.
Data was gathered from 48 Amott imbibition experiments with duplicates. IFT and baselines were defined in each case for brine, polymer and alkali on every set of experiments. When focusing on the TAN and aging effects it was observed that in all cases, the early time production is slower and final oil recovery is larger comparing to non-aged core plugs. This data confirms the change of rock surface wettability towards more oil-wet state after ageing and reverse wettability alteration due to chemical injection. Furthermore, application of alkali with high-TAN oil resulted in a low equilibrium IFT. In contrast, alkali alone fails to mobilize trapped low-TAN oil, but causes wettability alteration and neutral-wet state of the aged core plugs. Looking into brine composition, the presence of divalent ions promotes water-wetness of the non- aged core plugs and oil-wetness of the aged core plugs. Divalent ions act as bridges between mineral surface and polar compound of the in-situ created surfactant, hence accelerating wettability alteration. Finally, concerning mineralogy effects, high clay content core plugs are more oil-wet even without ageing. After ageing, a strongly oil-wet behaviour is exhibited. Alkali-polymer is efficient in wettability alteration of oil-wet core plugs towards water-wet state.
Three main points are addressed in the paper: A comprehensive methodology to evaluate wettability and IFT changes for different oil and mineralogy types is presentedIn particular, for alkali injection, substantial wettability change effects are observed.For high TAN number oils, wettability and IFT effects can be quantified using the methodology and applied for screening of chemical agents for various rock types.
On the Role of Molecular Diffusion in Modelling Enhanced Recovery in Unconventional Condensate Reservoirs
Authors: Santiago Carla Jordana , Kantzas Apostolos 
Published: June 2020

Abstract
Molecular diffusion is a transport mechanism often ignored in conventional, non-fractured multi-component petroleum upstream simulations due to the predominance of convection. In unconventional fractured reservoirs, diffusion plays a vital role in hydrocarbon production. A "shale" reservoir is characterized by thin, ultra-tight matrix blocks surrounded by natural or induced fractures. This creates conditions in which diffusion fluxes could be significant. In ultra-tight formations, convection is a slow process, and the presence of thin blocks surrounded by fractures increases the contact area, both of which favors diffusion.
In this paper, we discuss the application of cyclic gas injection to enhance recovery in tight reservoirs in the gas condensate window. A fully implicit model is implemented with the objective to investigate the impact of diffusion on liquid dropout and vaporization on a matrix level. Diffusion fluxes are implemented considering a gradient in total chemical potential as driving force. Additionally, since capillary forces are significant in ultra-tight formations, phase equilibria calculations are modified to account for nano-confinement effects. Sensitivity is performed on matrix block size and injection gas composition (pure C1, a mixture of C1 and CO2, and a mixture of C1, C2 and C3), and the role of diffusion is evaluated for each scenario.
As gas is injected, the composition of heavier hydrocarbon fractions in the gas phase significantly increases due to vaporization of condensate. Molecular diffusion helps to spread composition banks. As a result, liquid dropout is delayed during the subsequent production stages. Heavier fractions remain in the gas phase for longer periods, which ultimately enhances its recovery. In addition to that, retention of heavier fractions due to condensate dropout is intensified as the size of the matrix block increases. Longer matrix blocks result in lower swept length for the same number of cycles. As a result, liquid dropout occurs earlier because feed of gas at in-situ composition diffuses from the center of the matrix block towards the fracture boundary.
We demonstrate that heavier components recovery is more affected by molecular diffusion than lighter components. Furthermore, it is observed that molecular diffusion strongly influences time and location of occurrence of liquid dropout in tight gas condensate reservoirs. Implementation of a rigorous model that includes convection, diffusion, adsorption and phase change allowed to investigate the commingling effects of different physics involved in enhanced recovery in unconventional reservoirs.
Modelling Micro-Proppant Transport in Stress-Sensitive Naturally-Fractured Reservoirs
Authors: Di Vaira Nathan , Leonardi Christopher , Johnson Jr. Raymond 
Published: June 2020

Abstract
Optimal proppant placement is critical to maintaining productivity from stress-sensitive reservoirs, in which gas conductivity depends on the connectivity of the network of secondary fractures to the wellbore. In a colloquial sense, this research places micro-proppants in induced and natural fractures, shows how they are excluded from reaching far into the reservoir, and describes which sizes of proppants this occurs for. Micromechanical modelling of a hydraulic fracturing fluid, in which the hydrodynamics between the fluid and solid phases are fully resolved, is achieved via the lattice Boltzmann method (LBM) for fluids coupled with the discrete element method (DEM) for particles. It is shown that proppant transport along the primary hydraulic fracture channel is strongly inhibited by leak-off into the secondary fracture system. This leak-off is strongly affected by the migration of particles across the fracture width, which in turn is a function of reservoir and treatment properties. A novel numerical approach is proposed for predicting proppant transport through the secondary fracture system, with far-reaching applications to porous media particulate transport.