bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Decomposition of Volumetric Sweep Efficiency and Its Utility
Authors: AlSofi Abdulkareem M. , Blunt Martin J. 
Published: September 2019

Abstract
The traditional definition of volumetric sweep efficiency sums the effects of both fingering (arising due to contrasts in mobility) and bypassing (arising due to contrasts in permeability as well as well placement). Accordingly, we cannot quantitatively attribute poor sweep to either bypassing or fingering. Similarly, in EOR, the incremental recovery cannot be quantitatively associated with the reduction of those effects. For such purposes, we rely on visualization and mapping of saturation profiles to quantify and characterize the remaining oil in place including its distribution. . In this work, we propose a complementary method to obtain an instantaneous insight of the remaining oil distribution. We demonstrate the decomposition of fingering and bypassing effects and its utility. We first redefine recovery factors such that we decouple bypassing and fingering effects. We then validate those redefined sweep indicators by examining a 5-spot waterflood and two idealistic polymer floods. Later, we demonstrate the possible utility of those redefined sweep indicators through different examples. In one example, we compare the performance of a shear - thinning polymer to a recovery-equivalent Newtonian polymer. Using fingering and bypassing sweep indicators, we can immediately conclude that the shear-thinning polymer exacerbates bypassing. We recommend the adoption of our redefined sweep indicators in any simulation suite. They provide instant understanding of sweep and hence can be complementary to standard practices of oil saturation mapping and of special value when analyzing the results of multiple realizations and/or development scenarios.
Numerical Simulation of Non-Equilibrium Phase Behavior of Hydrocarbons for Modeling Oil and Gas Fields with Gas Injection
Authors: Al-Jenaibi Faisal , Bogachev Kirill , Milyutin Sergey , Zemtsov Sergey , Gusarov Evgenii , Kuzevanov Maksim , Indrupskiy Ilya 
Published: September 2019

Abstract
This paper deals with the issues related to the modeling of non-equilibrium phase transition in isothermal compositional models. Based on a real case of oil and gas field in the Middle East, the importance to take into account the effects of thermodynamic non-equilibrium are demonstrated with the help of mathematical models proposed earlier.
Theoretical and experimental studies, as well as actual field development data, show that not all phase transition processes take place in the forward and reverse directions at the same rate. For example, the dissolution of gas is much slower than the gas liberation from oil. Non-equilibrium processes are those whose characteristic time is comparable to or exceeding the characteristic time of variation of external conditions. In the classical formulation, it is supposed that thermodynamic processes are equilibrium, but the effect of non-equilibrium in addition to large grid cell sizes of the dynamic model and small-time steps can significantly affect the simulation results. In the case of black oil models, there are extensions of the mathematical model that are often used to describe the non-equilibrium behavior. At the moment, the rate of establishment of thermodynamic equilibrium is not taken into account in the majority of compositional models, the neglection of which in some cases might question the reliability of the simulation results. The practical implementation of the ideas (Indrupskiy et al, 2017), which were stated about how to take into account the non-equilibrium of thermodynamic processes occurring in the reservoir for compositional models, is performed.
The paper presents the results of modeling gas and water injection as a method of pressure support after development under depletion. In the equilibrium approach gas dissolves in oil at gas-oil contact simultaneously with increasing pressure. In practice, gas dissolution in oil occurs extremely slowly, and the dissolution rate decreases as the pressure approach the saturation pressure of the oil. According to laboratory studies, the modeling of such phase transitions requires the implementation of non-equilibrium models. At the same time, usage of the equilibrium models for this type of field leads to dramatic errors in estimates of the oil recovery.
Ultrafast Core Analysis for Tight Gas Reservoirs
Authors: Bona Nicola , Santonico Dario , Machicote Saida , Battigelli Alessandra 
Published: September 2019

Abstract
For oil and gas companies, accelerating the time to first hydrocarbon is a strategic objective. Special core analysis programs for tight gas reservoirs may take many months because of the long equilibration times involved in the tests. This represents a bottleneck for achieving the goal of reducing the time-to- market. Both log interpretation and reservoir modelling activities are impacted by the long SCAL durations. In order to face the challenge, a suite of fast methods have been developed. They are fast because they operate under non-equilibrium conditions. The methods give the m&n parameters for electric log interpretation, the endpoint gas relative permeability and the relationship linking initial gas saturation, trapped gas saturation and endpoint water relative permeability in a couple of days.
An Efficient Approach to Diagnose and Improve 3D Reservoir Model Quality in a Highly Diagenetic Deterogeneous and Dynamic Pressure Carbonate Field Case Study
Authors: Susanto Maria Indriaty , Sellar Christopher , Contreras Perez David 
Published: September 2019

Abstract
This paper presents a diagnostic workflow to understand and implement rock and fluid modeling in a diagenetically heterogeneous and hydrodynamically pressured Middle East carbonate field. The workflow allows interactive field data integration, provides guidance for reservoir property distribution and fluid contact generation in order to improve reserves and forecasting estimation. The workflow is useful to a reservoir modeler in QA/QC role and in this case it proves particularly applicable in an organization with constrained resources during the farm-in process. The workflow runs on numerical methods within the static model to avoid database discrepancy during the diagnostic process. Using the core (CCAL, SCAL), log and pressure database, the geoscientist can assess subsurface modeling outputs from the simplest to more complex deterministic scenarios. The process aims to minimize the discrepancy between data input and model output while continuously honoring the data, maintaining realistic correlations (e.g. between static permeability and water saturation) and respecting inherent uncertainty.
Using a data-rich Middle East carbonate reservoir, the pre- and post-diagnostic comparison of 3D modeled reservoir properties to the input data are demonstrated. Diagnostic steps have helped to understand potential subsurface scenarios and thus minimize the discrepancy post exercise. The value of the workflow is its ability to pinpoint the key uncertainties in rock and fluid modeling from the field’s vast dataset in a shorter diagnostic time. The application of the workflow in this carbonate reservoir case study increases the importance of geological and property driven rock type classification and its 3D distribution in matching the water saturation profile. This proved particularly challenging in this case study due to the field’s compartmentalization - fluid contact scenario.
Reservoir Simulation Model With Surfactant Flooding Including Salinity and Thermal Effect, Based on Laboratory Experiments
Authors: Preux Christophe , Malinouskaya Iryna , Nguyen Quang-Long , Flauraud Eric , Ayache Simon 
Published: September 2019

Abstract
In order to improve the oil recovery factor, many oil companies employ surfactant in injected water. On one hand, the injection of surfactant influences the interfacial tension and to a lesser extent, the mobility reduction factor. On the other hand, the efficiency of the surfactant depends strongly on the salinity and temperature conditions. In order to optimize the surfactant injection procedure, the salinity and temperature effects are commonly studied through series of laboratory experiments. However, these types of experiments are often long and expensive. Therefore, engineers use numerical simulations. The present study addresses a numerical model, which allows to take into account the modifications of the interfacial tension (IFT) and the mobility reduction factor due to the salinity and temperature variations during the surfactant injection.
In this work, we propose a coupled numerical model based on five equations: i) two transport equations of water and oil phases modelized by the Darcy's law, ii) two transport equations for the surfactant and the salinity (the surfactant and the salinity are transported only in the water phase) iii) one energy conservation equation to take into account the thermal effect on surfactant flooding. The system of equations includes the salinity and the temperature impacts on the surfactant adsorption and thermal degradation, as well as the interfacial tension. Thus, this model allows improving the analysis of thermal corefloods or reservoir operations resulting from the surfactant injection.
The coupled model is used to reproduce laboratory experiments based on corefloods. We analyze the interaction phenomena between the surfactant, salinity and temperature. Then, we demonstrate a competition between two phenomena: the thermal effect on the viscosity of water on one hand, and the effect of surfactant on the mobility of water on the other hand. This study highlights the efficiency of numerical simulations for the analysis and choice of the surfactant applied to the given reservoir and well conditions.
Obviously, the knowledge of IFT and its dependence on surfactant concentration, salinity and temperature is not sufficient to understand all the physical mechanisms involved in a coreflood study. The phenomena are in fact extremely coupled, and the reservoir simulator coupling all these effects is found to be very helpful for engineers in order to take a good decision about the surfactant species to be used.
A Parallel Load-Balancing Reservoir Simulator with Dynamic Mesh Optimisation
Authors: Salinas Pablo , Jacquemyn Carl , Kampitsis Andreas , Via-Estrem Lluis , Heaney Claire , Pain Christopher , Jackson Matthew 
Published: September 2019

Abstract
The use of dynamic mesh optimization (DMO) for multiphase flow in porous have been proposed recently showing a very good potential to reduce the computational cost by placing the resolution where and when necessary. Nonetheless, further work needs to be done to prove its usability in very large domains where parallel computing with distributed memory, i.e. using MPI libraries, may be necessary. Here, we describe the methodology used to parallelize a multiphase porous media flow simulator in combination with DMO as well as study of its performance. Due to the peculiarities and complexities of the typical porous media simulations due to its high aspect ratios, we have included a fail-safe for parallel simulations with DMO that enhance the robustness and stability of the methods used to parallelize DMO in other fields (Navier- Stokes flows). The results show that DMO for parallel computing in multiphase porous media flows can perform very well, showing good scaling behaviour.
Field Application Study on Automatic History Matching Using Particle Swarm Optimization
Authors: Lee Sanghyun , Stephen Karl, Dunbar 
Published: September 2019

Abstract
The traditional trial and error approach of history matching to obtain an accurate model requires engineers to control each uncertain parameter and can be quite time consuming and inefficient. However, automatic history matching (AHM), assisted by computers, is an efficient process to control a large number of parameters simultaneously by an algorithm that integrates a static model with dynamic data to minimize a misfit for improving reliability. It helps to reduce simulation run time as well.
Particle Swarm Optimization (PSO) is a population based stochastic algorithm that can explore parameter space combined with the least squares single objective function. The process of AHM can adopt parameterization and realization methods to reduce inverse problems. In this study, realizations of various reservoir properties such as porosity, net to gross, relative permeability, horizontal and vertical permeability, and aquifer size were chosen for controlling throughout the AHM. History matching was conducted to validate the efficiency of each method. The guidelines for optimized AHM with a stochastic algorithm are also disccussed.
The realization and parameterization methods improved matching results in a full-field application with resulting in a reduced misfit and in less. A stochastic algorithm generates multiple models to deduce control parameters to reduce a misfit. In this study we identified that PSO converged effectively with updated control parameters. The optimized AHM improved the accuracy of a full-field model although some misfit remained in the match to bottomhole pressure.
We found that updating with too many parameters makes the problem difficult to solve while using too few leads to false convergence. In addition, while the simulation run time is critical, a full-field simulation model with reduced computational overhead is benefitial.
In this study, we observed that the PSO was an efficient algorithm to update control parameters to reduce a misfit. Using the parameterization and realization as an assisted method helped find better results. Overall this study can be used as a guideline to optimize the process of history matching.
Dynamic Modeling of a High Temperature CO2-Rich Giant Gas Field with a Carbon Capture and Storage Strategy
Authors: Rizzato Paolo , Castano Daniele , Moghadasi Leili , Renna Dario , Pisicchio Patrizia , Bartosek Martin , Suhardiman Yohan , Maxwell Andrew 
Published: September 2019

Abstract
This paper describes the results of an integrated reservoir study aimed at producing hydrocarbons through a sustainable development from a green High Temperature (HT) giant CO2-rich gas field in the Australian offshore. The development concept addressed the complex challenge of exploiting resources while minimizing the carbon impact.
In order to characterize the reservoir in the most detailed way and to describe the fluids behaviour, a 1.8 million active cells compositional model has been built. An analytical aquifer has been coupled in order to represent the boundary conditions of the area.
The faults system, interpreted on seismic data by geophysicists, has been included in the simulation model. The selected development plan includes the re-injection of the produced CO2 into the aquifer of the reservoir itself. The supercritical CO2-brine relative permeability curves at reservoir conditions have been provided by Eni laboratories, where the experiments were performed.
Therefore, a detailed model has been built with the purpose of: –Defining producing well and CO2 injector well locations, numbers and phasing to evaluate expected CO2 injectivity and CO2 breakthrough issues;–Optimizing the development concept through a risk analysis approach;–Estimating the CO2-rich gas injectivity and storage capacity in the saline aquifer of the reservoir;–Predicting the behavior of the CO2-rich gas after re-injection (breakthrough timing and plume migration);–Maximizing the CO2 sequestration in the reservoir.
EOR Technologies and Applications Towards 70% Recovery Factor Aspiration in Giant Carbonate Middle East Reservoirs
Authors: Al-Keebali Aaesha , Yaslam Maged , Bin Amro Ahmed , Masalmaeh Shehadeh 
Published: September 2019

Abstract
As part of enhanced oil recovery (EOR) strategic objectives to boost oil recovery towards 70% aspiration and demonstrate EOR as an attractive viable option for environmental Carbon Capture, Utilization and Storage (CCUS) applications, various conventional and novel EOR technologies and applications are being screened and studied to ensure meeting mandated objectives. Accordingly, number of EOR pilots and projects have grown substantially over recent years to ensure derisking the full field expansion uncertainties and challenges, especially in such carbonate reservoirs with harsh conditions of temperature (~ 250 F) and salinity (~ 200,000 ppm).
Detailed screening study and performance review assessment have been conducted, in which gas and chemical based EOR technologies were identified for targeted reservoirs. The candidate reservoirs have a long history of EOR projects focusing on miscible hydrocarbon gas (HC) as early as 1996, which has supported oil production meeting forecast demand. On the other hand, as part of environmental driven strategy for CCUS and EOR applications, CO2 technology has been successfully progressing as EOR business case full-integrated cycle from pilot to field expansion during 2009-2016. In 2016, Al Reyadah has been launched as a unique commercial- scale CCUS facility in the region, that captures 800,000 tonnes of CO2 annually from Emirate Steel Industries and injects it into oilfields to boost crude recovery.
Furthermore, novel EOR technologies have been screened and identified with significant potential added value, that includes SIMGAP, SIWAP, Surfactant, Polymer and others, which are currently under modeling and design phase for implementation within upcoming few years to boost recovery factor towards 70% aspiration.
Development and piloting of latest technologies are among the main enablers to ensure fit-for purpose applications, proper planning and optimum design for ultimately maximum revenue economically. This paper presents a big-picture overview of EOR technologies with the focus on some cases, challenges and opportunities for super giant carbonate reservoirs.
History Matching of Multiple Wells With Actual Downhole ICD Configuration in a Five-Spot Pattern Reservoir Development
Authors: Altaf Basit , Allouti AbdelKader , Kedia Rachit 
Published: September 2019

Abstract
Downhole control devices are being widely implemented in fields globally; and, because of the costs involved in their implementation, a robust reservoir performance forecast is necessary. A prerequisite to a sound reservoir development plan is to have a robust history-matched reservoir simulation model. This study involves use of a downhole inflow control device (ICD) well configuration in the reservoir simulation model to perform history matching of a green-field offshore Abu Dhabi. The results of this approach are compared to the results from traditional approaches. The scope of this study is to examine the differences in both history match approaches.
Reservoir A is one of the major reservoirs of a green-field located offshore Abu Dhabi, and is being developed with a five-spot water injection pattern. The producers and water injectors are horizontal wells, which are drilled across different flow units within the reservoir. Because the reservoir is heterogeneous across all the flow units, the injection pattern results in a non-uniform water front. The conventional approach to history matching the well performance is to implement a positive skin factor across the well completions to mimic the effect of the inflow control devices (ICDs) installed in the well: increasing the pressure drop (ΔP) between the formation and the well tubing. In this study, the actual downhole configuration was prepared using well-completion analysis software, followed by use of a next-generation reservoir simulator to run the full field reservoir model for the history matching period.
As the field is being developed on the principles of digital concept, continuous high-frequency downhole pressure data is available in flowing as well as shut-in conditions. The use of this data, coupled with direct modeling of the ICDs in the simulation model, resulted in a significant improvement in the reliability of the history match, as compared to traditional approaches.
This study compares two history matching approaches for fields with wells completed with downhole control devices. The core purpose of this study is to integrate the principles of the digital oil field with conventional history matching techniques, with the ultimate goal of improving the history match.
An Enhanced NMR Workflow for Heterogeneous Carbonates Characterization, Offshore Abu Dhabi
Authors: Serry Amr , Yousif Sharifa , Abouzaid Ahmed , Kieduppatum Piyanuch , Soliman Ahmed 
Published: September 2019

Abstract
Full field development of the Upper Jurassic carbonates, offshore Abu Dhabi is exceedingly challenging. The heterogeneous texture, complicated pore systems and intensive lithology changes all mark the regressive cycles of sedimentation. Such complicated characteristics obscure formation evaluation of these formations. Advanced well logging tools and interpretation methodologies are implemented to minimize the petrophysical uncertainties to qualify the products as field development critical elements. This case study highlights a newly applied NMR log interpretation approach. The results help to understand the complex pore system in a tight carbonate layer, along a horizontal drain drilled close to the oil-water contact.
NMR log data was acquired in real-time while drilling simultaneously with Gamma Ray, Resistivity and Image Logs. Earlier field studies recommended swapping standard T2 free fluid relaxation cutoff values by actual laboratory NMR measurements for a higher precision suitable for the reservoir texture heterogeneity, the study itself supported the application of higher cutoff values to better discriminate the free fluid in well-connected macro pores from the irreducible which will have a direct impact on the computed permeability.
In this case study, a variable free-fluid T2 cutoff was firstly implemented based on arbitrary estimations to match the computed Coates permeability to the offset core values. Free-fluid, irreducible fluids were sequentially computed. A unique NMR-Gamma Inversion (NMR-GI) workflow is further utilized as a mathematically defined approach to process the raw data using probabilistic functions. The result is a more precise pore size distribution, coherent with the geological variations. NMR Capillary pressure was computed.
The complex formation texture could be accurately tracked for thousands of feet drilled along the horizontal drain. After validation with offset core, the NMR-GI interpretation was combined with, Archie saturation and Image log analysis for a conclusive assessment. Hydraulic flow units were combined. Successful completion design and production zone selection articulated on the defined open hole log interpretation.
NMR while drilling logging and the applied (NMR-GI) methodology prove to be leading tools to assist in resolving carbonate reservoir complexities. Not only that they help to understand the pore system characteristics, but they effectively support well placement, completion and production.