bluuebunny/crossref_metadata_2025_split huggingface dataset:
Machine Learning-Based Optimization of Well Locations and WAG Parameters under Geologic Uncertainty
Authors: Nwachukwu Azor , Jeong Hoonyoung , Sun Alexander , Pyrcz Michael , Lake Larry W. 
Published: March 2018

Abstract
The effects of well locations and control parameters on reservoir responses is important during CO2 enhanced oil recovery (CO2-EOR) and water-alternating-gas (WAG) injection. Oil recovery and CO2 storage capacity typically vary with respect to corresponding changes in WAG ratio, slug size, and injector locations. The relationships between control parameters and response variables are usually studied using compositional simulators. However, the computational expense required to run such simulators could hinder their applicability to optimization procedures requiring many evaluations. Surrogate models (proxies) provide inexpensive alternatives for approximating reservoir responses. In this study, a machine learning-based proxy is developed to predict responses to changes in location and control parameters during WAG injection.
Slight adjustments in injector well locations, WAG ratio and slug size could yield dramatic changes in the objective function responses. This complex relationship between control parameters and reservoir-wide responses makes data-driven methods an attractive option. We extend a recently developed machine learning approach in which the primary predictors are physical well locations, and water and gas injection rates, and the primary response is net present value (NPV). Because of the complexity of the response surface, we augmented the predictor variables with well-to-well pairwise connectivities, injector block permeabilities and porosities, and initial injector block saturations. Connectivities are represented by ‘diffusive times of flight’ of the pressure front, which is computed using the Fast Marching Method. Training observations are obtained from a handful of compositional simulations. We then used the Extreme Gradient Boosting method (XGBoost) to build intelligent proxies for making predictions given any set of observations.
We propose a hyperdimensional, simultaneous optimization of well locations and controls using a novel optimization scheme similar Mesh Adaptive Direct Search (MADS). Our optimization scheme was developed to fully take advantage of the speed and statistical output of the proxy. The proposed approach is demonstrated using a case study in which the underlying geology is uncertain. Results show significant correlation between proxy predictions and reservoir simulations, which validates application of the trained proxy. In addition, we demonstrate that simultaneous optimization of location and controls yields improvements over a sequential approach without any significant increase in computational cost.
A New Chemical EOR Surfactant Polymer Flood Model
Authors: Huang C. K. , Shiralkar G. S. , Li G. , Abbas S. 
Published: March 2018

General Overview
This paper describes a new chemical EOR numerical model capable of simulating surfactant and polymer floods. We present the highlights of a highly efficient and robust IMPES implementation within a legacy, in-house gas-oil-water compositional simulator. The additional computational overhead, over say a waterflood calculation, is on the order of only 20% for large scale (type pattern model) simulations. We present performance results both in serial as well as parallel (multi-processor) mode.
Flow within all three Winsor Type environments is modeled, with the ability to transition between the different types. The effects of a separate microemulsion (ME) phase are accounted for. Temperature effects on surfactant phase behavior as well as on adsorption are also considered. Other important physical effects that are modeled include phase trapping and oil bypassed by surfactant, near wellbore polymer injectivity and the reduction of surfactant adsorption associated with a sacrificial agent such as alkali. Gas phase is included in the model.
The model has been extensively benchmarked against another reservoir simulator. We also present some validation results at the laboratory as well as at the field scale.
Case Studies: Pressure-Transient Analysis for Water Injector with the Influence of Waterflood-Induced Fractures in Tight Reservoir
Authors: Wang Yang , Cheng Shiqing , Zhang Kaidi , Xu Jianchun , Qin Jiazheng , He Youwei , Luo Le , Yu Haiyang 
Published: March 2018

Abstract
Pressure-transient analysis (PTA) of water injectors with waterflood-induced fractures (WIFs) is much more complicated than hydraulic fracturing producers due to the variation of fracture properties in the shutting time. In plenty of cases, current analysis techniques could result in misleading interpretations if the WIFs are not well realized or characterized. This paper presents a comprehensive analysis for five cases that focuses on the interpretation of different types of pressure responses in water injectors.
The characteristic of radial composite model of water injector indicates the water erosion and expansion of mini-fractures in the inner region. The commonplace phenomena of prolonged storage effect, bi-storage effect and interpreted considerably large storage coefficient suggest that WIF(s) may be induced by long time water injection. Based on this interpreted large storage coefficient, fracture half-length can be obtained. In the meanwhile, the fracture length shrinks and fracture conductivity decreases as the closing of WIF, which has a considerable influence on pressure responses. Results show that the upward of pressure derivative curve may not only be caused by closed outer boundary condition, but also the decreasing of fracture conductivity (DFC). As for multiple WIFs, they would close successively after shutting in the well due to the different stress conditions perpendicular to fracture walls, which behaves as several unit slopes on the pressure derivative curves in the log-log plot.
Aiming at different representative types of pressure responses cases in Huaqing reservoir, Changqing Oilfield, we innovatively analyze them from a different perspective and get a new understanding of water injector behaviors with WIF(s), which provides a guideline for the interpretation of water injection wells in tight reservoirs.
Immiscible Nitrogen Flooding in Bentheimer Sandstones: Comparing Gas Injection Schemes for Enhanced Oil Recovery
Authors: Janssen Martijn T. , Azimi Fardin , Zitha Pacelli L. 
Published: March 2018

Abstract
Gas injection is a widely applied enhanced oil recovery method. However, poor vertical and areal sweep efficiency result in inefficient oil displacement. For improving gas mobility control, Water-Alternating- Gas injection has often been applied. The goal of this study was to compare several immiscible nitrogen injection schemes and to investigate how rock-fluid and fluid-fluid interactions control the immiscible flooding process. Well-controlled core-flood experiments were performed in Bentheimer sandstone cores. Nitrogen was injected into cores saturated with n-hexadecane at connate water saturation at constant pressures (5 and 10 bar) and while varying backpressure (5 to 60 bar). Nitrogen was also injected at residual oil to waterflood and a Water-Alternating-Gas injection scheme was assessed. Coreflood results clearly demonstrated the beneficial effects of Water-Alternating-Gas injection over continuous gas injection. The findings in this study suggest that a) an increase in pressure favours oil recovery slightly during continuous nitrogen injection at connate water saturation, b) residual oil saturation for immiscible nitrogen flooding is lower under three-phase flow compared to two-phase flow and c) the relatively high oil recovery, i.e. lower ultimate residual oil saturation, by Water-Alternating- Gas injection is most likely related to an increase in trapped gas saturation.
Estimation of Capillary Pressure and Relative Permeability from Downhole Advanced Wireline Measurements for Waterflooding Design
Authors: Al-Rushaid Mona , Al-Rashidi Hamad , Ahmad Munir , Azari Mehdi , Hadibeik Hamid , Kalawina Mahmoud , Hashmi Gibran , Hamza Farrukh , Ramakrishna Sandeep 
Published: March 2018

Abstract
Reservoir relative permeability and capillary pressure, as a function of saturation, is important for assessing reservoir hydrocarbon recovery, selecting the well completion method, and determining the production strategy because they are fundamental inputs to reservoir simulation for predicting lifetime production of a well. Estimation of relative permeability and capillary pressure curves at reservoir conditions is also an important task for successful planning of waterflooding and enhanced oil recovery. The relative permeability and capillary pressure data estimated from core analysis might cause concern regarding representativeness, and adjustments are typically necessary for successful production forecasting. This paper proposes a new method to obtain relative permeability and capillary pressure curves with downhole pressure-transient analysis (PTA) of mini-drillstem tests (miniDSTs) and well log-derived saturations.
The new approach was based on performing miniDSTs in the free water, oil, and oil-water transition zones. Analyses of the miniDST buildup tests provided absolute formation permeability, endpoints of relative permeability to both oil and water, and curvature of the relative permeability data. Additionally, resistivity, dielectric, and nuclear magnetic resonance (NMR) logs were used to determine irreducible water, residual oil, and transition zone saturations. Combining these downhole measurements provided the relative permeability and capillary pressure curves.
Best Practices for Laboratory Evaluation of Immiscible WAG
Authors: Itriago Yani C. , Araujo Mariela , Molinaris John 
Published: March 2018

Abstract
Immiscible Water Alternating Gas (IWAG) is an EOR process whereby water and immiscible gas are alternately injected into a reservoir to provide better sweep efficiency and reduce gas channelling from injectors to producer wells, aiming to stabilize the displacement front and increase contact with the unswept areas of the reservoir. In this work, we present a summary of best practices for laboratory evaluation of IWAG. This work was motivated by observations related to the way laboratory measurements are normally done, which could result in erroneous interpretation if the results were to be used directly for the design of a field application.
The set of best practices were collected from own work expanding over two decades of laboratory work, discussion with experts from laboratory services and research centres, and a comprehensive literature review. They were tested in a laboratory workflow and compared to conventional workflows used by most laboratories. The recommended approach covers steps from sample preparation, experimental setup, measurement protocols, guideline for process design, and data QA/QC for later use in reservoir simulation.
Among the best practices, particular attention is given to the type of fluids and samples used for the measurements based on the strong effect of rock-fluid interactions on the IWAG performance. The layout of the experimental setup, and how the injection and displacement process is done and the flow effects quantified. Other best practices relate to the selection of the WAG slug ratio, and required initial conditions of the core where the laboratory testing is done. The number of cycles in the WAG injection affects the recovery. On the initial condition of the sample, the knowledge of the sample wettability at the start of the WAG is critical since the optimum ratio is influenced by the wetting state of the rock. A WAG ratio of 1:1, which is the most popular in field applications, is not necessarily the most appropriate.
Regarding flow properties, relative permeability should be evaluated under three-phase conditions and making sure hysteresis effects are well captured data in general not readily available. Special attention should be given to the selection of correlations for calculating three-phase relative permeability widely reported in the literature; in most cases they are not accurate for WAG injection since they do not consider special treatment of water-gas cycle.
We present a side by side comparison of the impact on the laboratory results will be given on using recommended best practices to more routine laboratory implementations. These best practices, with focus on immiscible WAG, provide a new unique workflow for the execution of laboratory programs supporting a better understanding of the involved phenomena and providing accurate data for immiscible WAG process design.
Theoretical Investigation of the Transition from Spontaneous to Forced Imbibition
Authors: Deng Lichi , King Michael J. 
Published: March 2018

Abstract
Spontaneous and forced imbibition are recognized as important recovery mechanisms in naturally fractured reservoirs as the capillary force controls the movement of the fluid between the matrix and the fracture. For unconventional reservoirs, imbibition is also important as the capillary pressure is more dominant in these tighter formations, and the theoretical understanding of the flow mechanism for the imbibition process will benefit the understanding of important multiphase flow phenomenons like water blocking. In this paper, a new semi-analytic method is presented to examine the interaction between spontaneous and forced imbibition and to quantitatively represent the transient imbibition process. The methodology solves the partial differential equation of unsteady state immiscible, incompressible flow with arbitrary saturation-dependent functions using the normalized water flux concept, which is very identical to the fractional flow terminology used in traditional Buckley-Leverett analysis. The result gives a universal inherent relationship between time, normalized water flux, saturation profile and the ratio between co-current and total flux. The current analysis also develops a novel stability envelope outside of which the flow becomes unstable due to strong capillary forces, and the characteristic dimensionless parameter shown in the envelope is derived from the intrinsic properties of the rock and fluid system and can describe the relative magnitude of capillary and viscous forces at the continuum scale. This dimensionless parameter is consistently applicable in both capillary dominated and viscous dominated flow conditions.
Suppressing Frontal Instabilities and Stabilizing Miscible Displacements with Time-Dependent Rates for Improved Oil Recovery
Authors: Yuan Qingwang , Wang Shuoshi , Wang Jinjie , Zeng Fanhua , Knorr Kelvin D. , Imran Muhammad 
Published: March 2018

Abstract
The frontal instabilities are a key control factor which can significantly affect the sweep efficiency and oil recovery in miscible flooding processes. Under unfavorable viscosity ratio between injection solvent and oil, the frontal instabilities are nearly unavoidable. However, how to suppress the instabilities, especially with low additional costs, should be carefully investigated. The present study examines the time-dependent displacement rates on flow instabilities in miscible flooding. Within the capacity of injection pumps, the injection rates are varied with time in a fast alternating manner. It is found that this kind of variable rates can stabilizing frontal instabilities by enhancing initial uniform mixing of solvent and oil. It therefore suppresses the later development of instabilities. Eventually, a much less unstable front is obtained when compared with the constant injection rate. Other parameters such as the amplitude of rates are also examined. The variations of propagation of front with time are analyzed for the change of rate strength. It is can therefore be concluded that this kind of time-dependent rate can improve oil recovery at very low additional rate within the capacity of pumps for the field EOR processes.
Unstable Waterflood Performance Diagnostic Methods
Authors: Tillero Edwin , Mogollón Jose Luis , Gomez Delfín , Zambrano Hector 
Published: March 2018

Abstract
This paper discusses a review and adaptation of some classic waterflood performance analytical methods, such as X-plot, comprehensive Y-plot (cY-plot), and WOR vs cumulative oil (Np) for the case of unstable immiscible displacement (viscous-oil fingering effect). These methods were reviewed based on fractional flow analysis (FFA) for unstable immiscible waterflood.
These classic techniques account for the solution of the one-dimension frontal advance Buckley-Leverett theory (1942), assuming stable flow. In addition, the traditional semilog linear relationship between oil-water relative permeability ratio and water saturationis assumed (constant parameters A and B). Those assumptions tend toover predict ultimate oil recovery for the case of viscous-oil waterfloods because flow functions do not capture the viscous fingering effect.
This work proposes to redefine aforementioned classic waterflood performance analytical methods with novel oil and water relative permeability expressions derived from the effective-fingering model(EFM) presented by Luo et al. (2016), which accounts for viscous fingering effects. In addition, an accurate exponential expression of kro/krw ratio as function of water saturation and an exact solution for a water saturation-dependent parameter B (named Bj) are proposed. New approaches of classic analytical methods were derived, and both laboratory and field cases were tested at the light of new equations.
Adaptation of classic equations (stable) to solutions that account for unstable flow results in more reliable diagnostic-plot techniques for the case of viscous-oil, allowing to correct predictions of oil and water production in the case of heavy-oil waterflooding Additionally, new equations resulted in unified solutions that can be applied for both stable and unstable waterflood and help to improve reliability when estimating ultimate oil recovery, volumetric sweep efficiency, and various reservoir parameters. In the presence of viscous fingering, the water breakthrough and oil recovery from new X, cY, and WOR functions are viscous-finger number dependent (Nvf). The bigger the Nvf the lower the oil recovery, the earlier the water breakthrough, and the narrower the water saturation ranges.
In its entirety, these novel waterflood performance analytical methods incorporate viscous fingering features in the traditional flow functions, encouraging the ability to predict ultimate oil recovery for both unstable and stable waterflooding cases and for chemical flooding (i.e., polymer with future adaptation) in heavy-oil reservoirs and facilitating the optimization of heavy-oil enhanced oil recovery (EOR) projects. These results might provide a basis to adapt other classic waterflood performance analytical methods.
Compositional Simulation of CO2 Huff-n-Puff in Eagle Ford Tight Oil Reservoirs with CO2 Molecular Diffusion, Nanopore Confinement and Complex Natural Fractures
Authors: Yu Wei , Zhang Yuan , Varavei Abdoljalil , Sepehrnoori Kamy , Zhang Tongwei , Wu Kan , Miao Jijun 
Published: March 2018

Abstract
The effectiveness of CO2 injection as a Huff-n-Puff process in tight oil reservoirs with complex fractures needs to be investigated due to the fast decline of primary production and low recovery factor. Although numerous experimental and numerical studies have proven the potential of CO2 Huff-n-Puff, relatively few numerical compositional models exist to comprehensively and efficiently simulate and evaluate CO2 Huff-n-Puff considering CO2 molecular diffusion, nanopore confinement, and complex fractures based on an actual tight-oil well. The objective of this study is to introduce a numerical compositional model with an embedded discrete fracture model (EDFM) method to simulate CO2 Huff-n-Puff in an actual Eagle Ford tight oil well. Through non-neighboring connections, the EDFM method can properly and efficiently handle any complex fracture geometries without the need of local grid refinement (LGR) nearby fractures. Based on the actual Eagle Ford well, we build a 3D reservoir model including one horizontal well and multiple hydraulic and natural fractures. Six fluid pseudocomponents were considered. We performed history matching with measured flow rates and bottomhole pressure using the EDFM and LGR methods. The comparison results show that a good history match was obtained and a great agreement between EDFM and LGR was achieved. However, the EDFM method performs faster than the LGR method. After history matching, we evaluated the CO2 Huff-n-Puff effectiveness considering CO2 molecular diffusion and nanopore confinement. The traditional phase equilibrium calculation was modified to calculate the critical fluid properties with nanopore confinement. The simulation results show that the CO2 Huff-n-Puff with smaller CO2 diffusion coefficients underperforms the primary production without CO2 injection; nevertheless, the CO2 Huff-n-Puff with larger CO2 diffusion coefficients performs better than the primary production. In addition, both CO2 molecular diffusion and nanopore confinement are favorable for the CO2 Huff-n-Puff effectiveness. The relative increase of cumulative oil production after 7300 days with CO2 diffusion coefficient of 0.01 cm2/s and nanopore size of 10 nm is about 12% for this actual Eagle Ford well. Furthermore, when considering complex natural fractures, the relative increase of cumulative oil production is about 8%. This study provides critical insights into a better understanding of the impacts of CO2 molecular diffusion, nanopore confinement, and complex natural fractures on well performance during CO2 Huff-n-Puff process in the Eagle Ford tight oil reservoirs.
Critical Reflections on the Effective Implementation of ICTs in Moroccan Universities
Authors: Laabidi Hicham 
Published: March 2018

Computers offer several opportunities that encourage the promotion of teaching and learning experiences. Like many other nations, Morocco has understood the importance of using computers in schools and universities. For this reason, the Moroccan government has launched several projects aiming at the diffusion of Information and Communication Technologies (ICTs) in education system. Actually, ICTs are useful for both teachers and students in the sense that they help teachers develop professionally. Also, students can increase their achievements and become independent learners. This paper aims to examine the various factors that have high impact on English professors’ use of computer technologies for pedagogical purposes in Moroccan universities. Descriptive analysis of means, and standard deviations were used to analyse the collected data. Also, inferential statistics, mainly Pearson Product Moment Correlation, were employed to account for this correlation. The findings revealed that lack of institutional support has a big influence on professors’ decision to utilize or refrain from using ICTs in their classroom practices.