bluuebunny/crossref_metadata_2025_split huggingface dataset:
Computational Fluid Dynamics (CFD) Study and Investigation of Proppant Transport and Distribution in Multistage Fractured Horizontal Wells
Authors: Bokane Atul , Jain Siddharth , Deshpande Yogesh , Crespo Freddy 
Published: September 2013

Abstract
Multistage hydraulic fracturing has become the key technology for completing horizontal and many vertical wells. In horizontal wells, the perf-and-plug method is the most commonly used staging method; in each stage, multiple perforation clusters are used to create separate transverse fractures at each cluster. How these clusters are placed can significantly affect a well's short- and long-term production performance. The simultaneous creation of multiple fractures is a cost effective and time saving method for stimulating both vertical and horizontal wells. Multistage fracturing is an effective method from the perspective of production, but the challenge of achieving even proppant distribution to each cluster is an intricate task for the industry.
Numerical simulations predict uneven proppant distribution for the fluid streams entering different perforation clusters. Field data indicates that, in many cases, some of the clusters do not contribute to production. This led to hypothesizing that actual proppant and fluid distribution along the stimulated clusters might be different from the assumed uniform distribution. However, in limited entry fracture design concept, the proppant distribution among the different perforations is assumed to be the same as the fluid distribution. Until recently, this assumption remained unchallenged.
This paper presents an extensive study and investigation of proppant transport in different perforation clusters within a single stage by using computational fluid dynamics (CFD) techniques. The effects of varied fluid and proppant specific gravity, viscosities, proppant sizes, and slurry flow rates were analyzed while keeping outside-casing parameters constant. Validation of empirical proppant transport CFD simulation results are compared to experimental test data. This is helpful to better understand fluid and proppant behaviors in multicluster fracturing processes to help achieve maximum efficiency.
The results of the study indicate that proppant transport can be accurately modeled when the effects of single particle settling, density driven flow, particle velocity profiles, and slurry rheology are all considered. The investigation shows CFD is an effective tool for optimizing proppant distribution among perforation clusters and enhancing production.
Effect of Some Parameters Influencing Enhanced Oil Recovery Process using Silica Nanoparticles: An Experimental Investigation
Authors: Hendraningrat Luky , Li Shidong , Torsæter Ole 
Published: September 2013

Abstract
Align with current dynamic technology development, waterflooding techniques have been improved and optimized to have better oil recovery performance. In addition the latest worldwide industries innovation trends are miniaturization and nanotechnology materials such as nanoparticles. Hence one of the ideas is using nanoparticles to assist waterflood performance. However it is crucial to have a clear depiction of some parameters that may influences displacement process.
The focus of this study is to investigate the effects of some parameters influencing oil recovery process due to nanoparticles such as particle size, rock permeability, initial rock wettability, injection rate and temperature. This study is part of our ongoing research in developing nanofluids for future or alternative enhanced oil recovery (Nano-EOR) method.
Three different sizes of hydrophilic silica nanoparticles with single particle diameter range from 7 to 40 nm were employed and have been characterized under scanning electron microscope (SEM). Nanofluids were synthesized using 0.05 wt.% nanoparticles that dispersed into synthetic brine (NaCl 3 wt.% ~ 30,000 ppm). The contact angle variation due to nanoparticles size was also measured at room condition. Coreflood experiment has been conducted using 26 Berea sandstone cores to evaluate the effect of those parameters above on oil recovery due to Nano-EOR. The cores permeability was in range from 5 to 450 mD. To study the effect of initial rock wettability on oil recovery due to Nano-EOR, original core wettability has been changed with aging process from water-wet to intermediate and oil-wet respectively. Temperature was also studied in range 25-80 °C to fulfill the possibility of applying Nano-EOR at reservoir temperature.
The coreflood testing was repeated for each case to have consistency result. The processes and results are outlined and also further detailed in the paper to bring knowledge about nanoparticles flooding as a future promising EOR method.
Reservoir Model History-Matching and Uncertainty Quantification in Reservoir Performance Forecast Using Bayesian Framework
Authors: Okano H. 
Published: September 2013

Abstract
Reservoir performance forecasts are essentially uncertain due to the lack of data. The unknown parameters are calibrated so that the simulated profile can match the observed data. However the history-matching is ill-posed and may have non-unique solutions. The aim of our study is to quantify uncertainty of reservoir connectivity in a Turbidite sandstone reservoir where the wells have been stimulated by hydraulic fracturing. The reservoir properties were calibrated using a stochastic sampling algorithm called Differential Evolution (DE). Then a Bayesian framework along with Markov Chain Monte Carlo and Neighbourhood Approximation in parameter space is used to calculate the posterior probability.
A Bayesian framework and DE have been applied to the evaluation of CO2 injection test in the tight oil reservoir. The in-place volumes and connectivity between the wells have been calibrated in a simple model. The calibrated parameters include the length of a hydraulic fracture around the injector well and net-to-gross ratios. The observed data used for history-matching include the bottom-hole flowing pressure at the injector well and the gas composition at the wellhead of the producer wells.
We showed the best fit model for the gas breakthrough and the P10-90 envelopes in the reservoir performance forecast. Assuming an on-going injection after the actual pilot test, the uncertainty envelopes in the CO2 mole fraction in the produced gas were estimated to see a gas breakthrough at each of the producer wells. Our results contribute to the evaluation of the pilot test for a continuous CO2 injection in the tight oil reservoir.
The key is starting with a simple model, because it is much quicker to adjust large-scale heterogeneity in a simple model than in a detailed model. The simple model calibration with DE and the forecast of Bayesian inference have been successfully applied to the field test evaluation.
Multiscale Lattice Boltzmann Method for Flow Simulations in Highly Heterogenous Porous Media
Authors: Li Jun , Brown Donald , Calo Victor M. , Efendiev Yalchin , Iliev Oleg 
Published: September 2013

Abstract
A lattice Boltzmann method (LBM) for flow simulations in highly heterogeneous porous media at both pore and Darcy scales is proposed in the paper. In the pore scale simulations, flow of two phases (e.g., oil and gas) or two immiscible fluids (e.g., water and oil) are modeled using cohesive or repulsive forces, respectively. The relative permeability can be computed using pore-scale simulations and seamlessly applied for intermediate and Darcy-scale simulations. A multiscale LBM that can reduce the computational complexity of existing LBM and transfer the information between different scales is implemented. The results of coarse-grid, reduced-order, simulations agree very well with the averaged results obtained using fine grid.
Pore-Scale Simulation of Viscoelastic Polymer Flow using a Stabilised Finite Element Method
Authors: Qi Meishan , Wegner Jonas , Falco Lisa , Ganzer Leonhard 
Published: September 2013

Abstract
The paper deals with the numerical investigation and simulation of viscoelastic effects during polymer flooding. A possible pore structure is derived from high-resolution micro-CT images of a typical sandstone suitable for EOR applications. The simulation results achieved will allow for better understanding of micro-scale displacement efficiency and will help to optimize polymer flooding designs for enhanced oil recovery (EOR) projects.
Numerical modelling of viscoelastic fluids is notoriously difficult. Standard Galerkin finite element method tends to have numerical oscillations. Therefore, a stabilised finite element method was used in this work, which contains stabilization terms for the constitutive equation. The model was validated using existing literature results. The viscoelasticity effect of polymer was simulated using the Oldroyd-B model. After validation this method was applied to several pore structures (contraction, expansion and expansion-contraction structure) and one real pore geometry based on SEM (Scanning Electron Microscopy). Flow effects and recovery effects were studied by changing the Reynolds number (Re) and Weissenberg number (We). Correspondingly, the streamline plots of the polymer solution flowing through the pore structures are shown. The plot of the first normal stress difference at the re-entrant profile of a contraction structure shows the cause of vortex enhancement.
The fluid invades deeper into dead pores with higher elasticity. With a high Reynolds number, the fluid reaches into the dead pore even much deeper. The simulation results indicate the contribution of the viscoelasticity of polymer solutions to the micro-scale sweep efficiency. The non-dimensional model of simplified pore structures will contribute to the selection of suitable rheological parameters for polymer flooding processes.
Nested Karst Simulations and Uncertainty Quantification - Application Case Study from a Kazakhstan Field
Authors: Labourdette R. , Glass L. W. , Lapointe P. A. 
Published: September 2013

Abstract
In carbonate reservoirs, heterogeneity is usually driven by both depositional and diagenetic patterns, which influence the final static and dynamic reservoir properties. Karstification is one of the most crucial diagenetic phases because of the way in which it constrains the permeability behaviour of the field. Defining static rock-type can therefore be problematic due to the highly imbricate karstic phases and their various distributions and extensions. A further major difficulty is the spatial distribution of rock-types in reservoir models, each linked to different sedimentological and karstic processes and each with their own, but interdependent, geometrical characteristics.
This paper presents a modeling workflow applied to a large carbonate mound in Kazakhstan, affected by hydrothermal karstification. This new approach is based on nested stochastic simulations, geologically-driven and derived from the relationships between karst, depositional facies, and proximity to fault/fracture zones. In addition to the initial depositional model, three diagenetic phases and bitumen deposits are modeled successively in order to restore the complex spatial relationship existing between described alterations. The overall workflow is designed to quantify uncertainties at each step of the nested chain, including structural and filling uncertainties.
The results of this study are quantification of uncertainties and volumetric estimations. They underline the importance of karst distribution and density on reservoir volumes ans especially on static recovery factors. They introduce high permeability drain increasing connectivity between injector and producer wells.
This workflow provides new perspectives for reservoir modeling, including the appropriate effective porosities and permeabilities affected by karst features. It leads to multiples realization scheme allowing uncertainty quantification, either in mature or appraisal field development. The outcome of this modeling workflow, after a stage of up-scaling and dynamic simulation, allows a better assessment the potential impact on field behavior.
Developing a Methodology To Detect Non Drained Sandbodies Using Geology Techniques in Mature reservoirs To Increase Recovery Factor
Authors: Sablit R. Ch. 
Published: September 2013

Abstract
A mature area in an advanced state of depletion can be reassessed as to either maintain the current production or to increase it at least in a minimum amount. Most important of all is to be able to increase the recovery factor. The variables that are related to the oil production are correlated to the sedimentology-stratigrahy model as to give us the most appropriate arrangements of wells and to relocate locations which could have given less production than expected. The facies for each of the environment of deposition identified in every producing reservoir of the formation are described based on which we locate the present wells and compare to the future locations. This is a heavy oil field producing since 1930. The crude ranges between 10–14 °API, the viscosity is in the range of 1000 to 25000 cp. The method of production is cyclic steam stimulation (CSS) which after three cycles becomes less efficient. The steam to oil ratio (SOR) is less than five from initial values of 30–40. Having a huge reserve in the area, however the recovery factor is only 23%. Since several of the sandbodies have not been yet drained out, this gives a new challenge by which a new approach will be used as to produce these bodies. Using sedimentology concepts we can determine the paleodeposition based on the existing facies in this way we locate new locations to optimize well production. Once we locate the new wells, we will be able to screen out the most appropriate way of production by applying thermal methods. Cyclic Steam Stimulation (CSS), steamflood, SAGD, Electromagnetism or Combustion, all together will increase the recovery factor an accumulated 80% of the reserves. The non-drained sandbodies could be stimulated with Cyclic Steam Stimulation (CSS) followed by steamflood in areas of the model with good thermal communication. Finally the very depleted reservoirs with low pressure and clean sands are the best for dry or wet combustion.
Improving the Estimation of Porosity and Permeability Distribution by Linking Basin Modelling to Diagenetic Evolution of Carbonate Reservoirs
Authors: Mangione Alessandro , Lewis Helen , Geiger Sebastian , van der Land Cees 
Published: September 2013

Abstract
Carbonate reservoirs have petrophysical property distributions largely controlled by a combination of the depositional, diagenetic, and structural (burial/uplift) histories of the reservoir itself and also of the basins that contain them. Carbonates are very prone to diagenetic alteration; porosity and permeability can be strongly affected by the thermal state, fluid-pressure and pore fluid chemistry through their geological history. We use a novel workflow, adapted from basin modelling, to investigate how the burial/uplift history of an offshore carbonate reservoir and its basin, taken as a system, can have controlled the fluid and heat movement within, into and out of the reservoir. The reservoir rock properties and diagenetic history are assessed, as is the local and regional geological evolution for potential contributory factors to the diagenesis. A model of the potential basin system is developed, observed reservoir diagenetic history being added to the normal basin modelling constraints. This model provides good estimates of geometry and property evolution, and of fluid transport, through geological time. Since fluid and heat fluxes are important in the diagenetic evolution of the carbonate pore system, these results are complemented by simulating the movement of heat and brine in the reservoir using finite element-finite volume simulations. These simulations capture the complex geological structures, especially fault-fracture systems, and better represent the flow physics and chemistry that control reservoir diagenesis. Results from these simulations will later be returned to the basin model to improve the calibration of the timing, depth, and rates of diagenetic events.
This new workflow is applied to a Lower Eocene offshore carbonate reservoir with a complex diagenetic history which seems to have a strong basin evolution influence. Importantly this workflow is generic and can be applied to any carbonate reservoir to enhance the link between geological models at the basin scale and reservoir scale models.
History Match of a DST Using a Turbidite Elementary Channels Modelling Technique, Deep Offshore Congo
Authors: Labourdette Richard , Devilliers M C. , Bui T. 
Published: September 2013

Abstract
In turbidite deposits, production history analysis indicates that fluid flow behavior is often more complex than expected. The cause is commonly linked to the presence of fine-scale sedimentary heterogeneities within the reservoir particularly in the case of turbiditic submarine channel complexes with final channel-filling stages composed of lateral migration deposits usually below seismic resolution.
Depositional patterns recognized as channel migration and aggradation packages from Oligocene and Miocene series in the Congo Basin, offshore Congo, exhibit different dynamic responses when modeled in a reservoir simulator.
They are related to the various preservation rates of bank collapse sediments within isolated channel bodies. The proposed workflow comprises 3D sedimentary simulations –, based on geometrical modeling that allow a realistic distribution of elementary channels in the final fairway reservoir model. The individual channel borders, below reservoir grid resolution, are identified as the main heterogeneity, and are used to position transmissibility multipliers.
These elementary channels are used as guides for facies and petrophysical modeling. The proportions and distributions of the different parameters are controlled by well data and sedimentary concepts and architectures. The channels, localized in the main fairway, are grouped per sequence. The main dynamic heterogeneities can be addressed either by the sequence boundaries or by elementary channels borders.
Channel sequences and elementary channels were integrated in Eclipse simulations to history match the DST, with transmissibility reduction between sequences, and between elementary channels.
Multipliers that were used to match the DST are extended along the fairway and lead to a conceptual model, where the variation of channel "skin" is a function of its sinuosity and migration type. Transmissibilities are either reduced in meander zones dominated by lateral channel stacking or preserved in "linear zones" dominated by vertical channel stacking.
Accounting for Regional Aquifer Data in a Simulation Model of the Burgan Minagish Reservoir - A Novel Approach
Authors: Al-Faresi F. A. , Bond D. J. , Wang J. T. 
Published: September 2013

Abstract
The Minagish reservoir in the Burgan Field has been produced intermittently at relatively low rates since the 1960's. Full development has been delayed because of the relatively high H2S content of the reservoir fluid. A sour service production facility is now being planned. Reservoir pressure has declined over time and it has been recognized that a component of this decline is due to offset production from several other reservoirs in the area sharing an extensive common aquifer. Reservoir simulation has been used in two phases for the reservoir to assess development options as follows:
The first phase of this work, the "fast loop", involved building models of the regional aquifer and producing reservoirs, developing multiple history matched models and using these models to assess the required volume of injection needed to prevent further reservoir decline. The field level history match was highly non-unique. This work identified the need to have water injection available prior to a new sour service production facility being available and to inject at above voidage rates.
A more detailed "slow loop" simulation model has been developed for the Burgan Minagish reservoir following further geological, geophysical and petrophysical studies. This model has been used to perform development planning studies and, in particular, to plan water injection in the period up to the new production facilities being available. The simulation model has been used as one of the inputs to planning for reservoir management and data acquisition in this period.
The integration between these two models uses a novel methodology. This paper describes how the "fast loop" and "slow loop" studies are linked so as to include the effect of the regional aquifer in conditioning the "slow loop" model to historical data, and using it for predicting future development scenarios performances.
Safe-Guarding Oil Recovery Through Implementation of Cyclic Production in Short Circuited Patterns
Authors: Adhoobi A. , Ramli A. , Ghufaili A. , Bacic G. , Belushi K. , Van Koolwijk M. 
Published: September 2013

Abstract
This paper describes the principles of cyclic production implemented in a matured water flood field to manage the occurrences of short circuit in a pattern. Systematic surveillance and reservoir management tools are used to analyze the fracture initiation, impact on production and reserves performance and predict the future behavior of the field. These include analytical tools, diagnostic methods, tracer surveys and downhole temperature monitoring which lead to the implementation of cyclic production methodology.
The tight reservoir is situated in a gently dipping, fault bounded matrix carbonate in North Oman. The reservoir is thick with relatively thin oil column heights of typically 5 to 30m and low permeability. The under-saturated reservoir contains light oil, with low viscosity (API gravity of 35°)
Due to inadequate aquifer support a full water injection scheme at matrix condition was implemented 10 years after natural depletion with multilateral horizontal water injectors drilled about 30m below the producers. During peak production, the water was unintentionally injected above fracture pressure which caused fracturing in several patterns in this field.
Cyclic production is implemented in these patterns as other different methods failed to recover the oil production due to short circuit. Since May 2008, the injectors and producers are operated on scheduled cycles in three patterns where these short circuits were observed. After several years of cyclic program implementation, encouraging results were obtained where up to 20% of reserves lost due to short circuits were recovered.
The paper also describes the challenges faced during the implementation of cyclic program mainly due to flexibility of compression capacity, manpower rotation and water injection limitations; frequency and accuracy of testing and number of wells supported by the injector.