bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Thermodynamic Model for The Solution Density and Mineral Solubility Predictions up to 250 °C, 1,500 Bars for Na-K-Mg-Ca-Ba-Sr-Cl-CO3-HCO3-SO4-CO2 aq Systems
Authors: Dai Zhaoyi , Kan Amy T. , Zhang Fangfu , Yan Fei , Ruan Gordon , Bhandari Narayan , Zhang Zhang , Liu Ya , Al-Saiari Hamad A. , Tomson Mason B. 
Published: April 2016

Abstract
Deep water oil and gas production is playing an important role in global energy support. With the advancement of deep water offshore production in recent years, there are more chances encountering with the extreme conditions of high temperature (up to 250 °C), high pressure (up to 1,500 bars) and high TDS (up to halite saturated salinity) in the presence of mixed electrolytes. Scale control in such environment requires accurate prediction of scale formation tendency. However, most previous models are not capable of predicting the scale mineral solubilities over such wide ranges of temperature, pressure and ionic strength. Pitzer theory is one of the most advanced thermodynamic models for the predictions of mineral solubility and other thermodynamic properties. However, the published Pitzer models often have limited ranges of applicability and potential inconsistencies with each other. In this paper, the published Pitzer models have been thoroughly reviewed to evaluate the consistencies of Pitzer parameters among these published models. In addition, more than 5,000 density and solubility experimental data published in the past 150 years were collected as the input database for model fitting to extend the applicable ranges. These experimental data were fitted through the determinations of standard partial molar volume (V0¯) of each ion and the virial coefficients for species specific short range interactions as functions of temperature and pressure. The developed model is capable to predict the density of soluble chloride and sulfate salt solutions within ±0.1% relative error, common scale mineral saturation index (SI = lg(IonActivityProduct/Ksp) within ±0.1 units under most conditions, CO2 solubility in NaCl and CaCl2 solutions within 0.7% relative error of 95% confidence interval. The developed model has been incorporated into ScaleSoftPitzer for practical use in the oil and gas fields, along with the flash calculator based on Peng-Robinson EoS, which can accurately predict the species partitioning in oil/water/gas phases.
Modelling CaCO3 Scale in CO2 Water Alternating Gas CO2-WAG Processes
Authors: Silva D. , Sorbie K. S. , Mackay E. J. 
Published: April 2016

Abstract
CO2 Water Alternating Gas (CO2-WAG) is one of the main Enhanced Oil Recovery (EOR) techniques which is currently being implemented in the emerging pre-salt projects offshore Brazil. CO2-WAG consists of the alternated injection of CO2 and water in the reservoir for tertiary oil recovery. However, this process may lead to the enhanced deposition of CaCO3 in production wells. This may occur since, in a CO2-WAG scheme, CO2 dissolves in the water slug causing a decrease in the pH. At lower pH levels, carbonate rock is dissolved causing an increase in the carbon and calcium content in the water slug. As fluids are later produced, the operating pressure is reduced and dissolved CO2 is evolved from solution, causing an increase in the pH. At these less acidic pH levels, CaCO3 may become oversaturated and precipitate.
In order to address each process involved in CaCO3 formation, an integrated modelling approach between aqueous scale prediction modelling, Vapour-Liquid Equilibria (VLE) modelling and reservoir modelling is proposed. In particular, acid equilibria and precipitation reactions coupled with the Pitzer equations are used to build the scale prediction model. The facility to calculate CaCO3 co-precipitation with other minerals, such as BaSO4, FeCO3, FeS, etc., is also introduced. Five different equations of state (namely SRK, PR, PRSV, PT and VPT) are used in VLE calculations to model the solubility of CO2 (or a mixture of CO2, H2S and CH4) in brine. To model the reactive flows in the reservoir, the advection-diffusion equation is coupled with the scale precipitation equations. The reactive transport model addresses carbonate rock-brine interactions and fluid flow through a porous medium. Once integrated in one single model, these equations have been shown to address all steps in CaCO3 formation relevant for CO2-WAG, i.e., the geochemical processes taking place in the reservoir and at the production wells, thus capturing the full dimension of the scaling problem. In addition, the proposed model has been successfully validated with experimental data on the injection of seawater adjusted to various pH levels into a CaCO3 packed column. The measured effluent pH levels and calcium concentrations were used to validate the model.
Least Square Support Vector Machine: An Emerging Tool for Data Analysis
Authors: Panja Palash , Pathak Manas , Velasco Raul , Deo Milind 
Published: April 2016

Abstract
Development of high speed computing leads to major advancements in every field of science and engineering. Artificial intelligence (AI) method is emerging as new modern technology applied to machine learning, pattern recognition, processing and understanding data, robotics etc. Its application in oil and gas industry is new despite of the fact that it has huge potential to explore the knowledge regarding reservoir characterization, PVT properties estimation, maximize productions, locating sweet spot using pattern recognition, optimum design of fracturing job, calculation of recoverable hydrocarbon, well placement etc. The main objective of this study is to put AI such as LSSVM in perspective from reservoir engineering and encourage engineers and researchers to consider it as a valuable alternative tool in the petroleum industry. Factors most affecting the production from fractured low permeability reservoirs such as reservoir permeability, gas relative permeability exponent, rock compressibility, initial gas oil ratio, slope of gas oil ratio in PVT, initial pressure, flowing bottom hole pressure and fracture spacing, are studied. A wide range of values of each parameter based on real field data from Eagle Ford, Bakken and Niobrara in the USA are assigned. Two different kinds of mathematical surrogate models, polynomial response surface method (RSM) and least square support vector machine (LSSVM) are compared to seek the better surrogate models in terms of predictability. Data are generated from a generic reservoir model using commercial simulator. Various models of recovery factors and gas oil ratio are developed for different times (after 90 days, 1 year, 5 years, 10 years, 15 years and 20 years) and for a minimum economic rate (5 STB/ day). Multivariate regression was used to obtain coefficients for the second-order polynomial response surface models using 80% of the simulated results (144). The LSSVM models coupled with radial basis kernel function (RBF) are trained with 60% data. 20% of data is used to tune the regularization parameter and kernel parameter using genetic algorithm (GA) optimization routine. Rest 20% data is utilized for testing the models' predictability for future performance. Goodness of fit is statistically measured by calculating coefficient of determination (R2), normalized root mean square error (NRMSE) and average absolute relative error (AARE). LSSVM exhibits good predictability to forecast the production such as oil recovery, gas recovery as surrogate models. The developed models can be used with high accuracy to forecast the production of oil from ultra-low permeability reservoirs. Quick sensitivity analysis of oil recovery to any parameter used in this study can be performed. The models are also useful for uncertainty analysis of productions.
Effects of Hydraulic Fractures on the Treatment of Condensate by Huff-n-Puff Gas Injection in Eagle Ford Shale
Authors: Yang S. , Wei Y. , Chen Z. , Wu W. , Ji D. 
Published: April 2016

Abstract
With the production of a gas condensate tight reservoir, condensate in fracture can significantly decrease the productivity of gas condensate wells. Previous work shows that the negative effect of condensate bank on gas production is more seriously in tighter reservoir. The implement of hydraulic fracture and multi-stages fracturing can mitigate the negative effects on the formation of condensate bank, but the effects cannot be completely removed. A huff-n-puff methane injection has been proven to be an effective method to reduce the effect of condensate by maintaining the reservoir pressure above the dew-point pressure and revaporizing the formed condensate. However, the previous work neglects the effect of hydraulic fractures on the treatment of condensate by gas injection.
Non-aqueous components are lumped into fourteen pseudo components. Dual permeability, logarithmically spaced, locally refined grids are implemented to model natural and hydraulic fractures in a simulation model. The laboratory measured relative permeability taking account of condensate bank is used to accurately represent two-phase flow in a shale reservoir. Furthermore, two different settings of cyclic schedule are implemented to test their advantages and disadvantages.
The results show that the huff-n-puff dry gas injection can effectively improve gas and condensate recovery. A fracture conductivity has significant influences on well production during the injection, while during the primary recovery its impact is not that obvious. In addition, the huff-n-puff schedules also plays a crucial role in both gas and condensate recovery. Our study highlights gas injection mitigates the effect of condensate bank on gas production in a shale reservoir, and provides an extensive insight on optimal design of Huff-n-Puff gas injection.
Integrated Reservoir Modeling Workflow That Couples PVT and Adsorption in Confined Nano-Pores, An Eagle Ford Application
Authors: Wu Xingru , Zhou Guangqing , Najobaei Bahareh , Pu Hui , Li Yinghui 
Published: April 2016

Abstract
Enhanced oil recovery techniques are having a growing interest for unconventional reservoirs to attack the low primary recovery factor issue, especially in a low oil price environment. Tight oil behaves a quick decline without much pressure support and thus jeopardies project profitability given a large initial capital requirement for horizontal drilling and massive multi-stage hydraulic fracturing operations. However, over 90% oil is still left behind in stimulated reservoir volume. It is imperative to understand the differences in production drivers in unconventional reservoirs, especially using EOR techniques, for example, how capillarity and adsorption may greatly alter phase behavior in nano-size pores.
Previous studies showed that phase behavior and production mechanisms might be significantly different under nano-scale pore confinement in organic matter in Eagle Ford formation. This research was to shed light to quantify such differences under the influce of large capillary forces in organic and inorganic pores integrating petrographic and/or petrophysical measurements, for example, mercury injection capillary pressure (MICP) experiments. Further, this study developed a new methodology to consistently evaluate the effect of adsorption at the same pore size distribution as capillary evolved.
Results showed that a large difference of phase and adsorption behavior existed for unconventional reservoirs in the oil window in the Eagle Ford formation, and pore size distribution played an important role in quantifying such differences. This may lead to additional rock-typing techniques to better characterize the Eagle Ford oil play and improve well expected ultimate recovery (EUR) and economics.
Phase Behavior of Multicomponent Hydrocarbons in Organic Nanopores Under the Effects of Capillary Pressure and Adsorption Film
Authors: Dong Xiaohu , Liu Huiqing , Hou Jirui , Chen Zhangxin , Wu Keliu , Zhan Jie 
Published: April 2016

Abstract
The presence of nanopores in tight rocks and shales have been confirmed by numerous studies. These pores are also the primary storage space of oil and gas in shales. Due to the effect of nanoscale confinement, the phase behavior of fluids confined in such extra-low permeability formation (nanodarcy scale) differs significantly from those observed in the conventional formation.
In this paper, the cubic PR EOR is coupled with the capillary-pressure equation and adsorption theory to investigate and represent the phase equilibria of pure components and their mixtures in cylindrical nanopores. The pore confinement effects of interaction between fluid molecule and pore wall and the shift of critical properties are all considered. Also due to the effect of adsorption film, an improved Young-Laplace equation is adopted to simulate the capillarity instead of the conventional equation. For the adsorption behavior, the experimental data on the adsorbent of silicalite are used to represent the adsorption behavior of hydrocarbons in nanopores. Then, a prediction process for the behavior of methane, n-butane, n-pentane, n-hexane and their mixtures are performed. And the results are compared against the available experimental data to confirm the accuracy of this scheme. The actual Eagle Ford oil is also used to examine the performance of our scheme.
Results indicate that the presence of adsorption film could further increase the vapor-liquid equilibrium constant (K-value) and capillary pressure of the confined pure-component fluid, especially for the nanopores with few nanometers. The smaller the nanopore radius, the higher the deviation between the actual K-value and bulk value. For methane, when the pore radius is higher than about 20 nm, the K-value is approaching the bulk fluids and the effect of capillary pressure and adsorption film can be neglected. For n-pentane, it is about 18 nm. For binary mixture, it is found the higher the difference between the two components, the stronger the nanopore confinement effects. The capillary pressure will present a bilinear relation with the pore radius in the log-log plot. For multicomponent mixture, as the pore radius decreases, the bubble-point pressure is depressed, the dew-point pressure is increased, and the phase envelop of confined fluids is also shrinked. When the adsorption film is neglected, the bubble-point pressure will be overestimated, and the dew-point pressure is underestimated. For Eagle Ford oil, when the nanopore radius is higher than about 100 nm, the behavior will approach the bulk value and the influence of nanopore confinement can be neglected. This study will shed some important insights for the phase behavior of tight oil and gas condensate in nanopores.
Effects of Nanoscale Pore Confinement on CO2 Immiscible and Miscible Processes
Authors: Zhang Kai , Kong Bing , Zhan Jie , He Ruijian , Qin Tianjie , Wu Keliu , Chen Zhangxin , Chen Shengnan , Zhang Jiaming 
Published: April 2016

Abstract
CO2 flooding is a promising technique for improving oil recovery in tight oil reservoirs. Because of existence of nanoscale pores in tight oil reservoirs, which can affect phase equilibrium, there will be some variations between CO2 immiscible and miscible processes in conventional and tight oil reservoirs. In this paper, the effects of nanoscale pore confinement on CO2 immiscible and miscible processes are studied.
On the basis of Cardium crude oil composition, phase equilibrium at various nanoscale pore radii is investigated. Since the interfacial tension is related to capillary pressure, it can be scaled in normalized oil recovery calculations. Furthermore, a reservoir can be assumed an immiscible zone, a miscible zone, or an unswept zone during CO2 injection. In this case, nanoscale pore confinement on CO2 immiscible and miscible processes can be evaluated.
Taking the nanoscale pore confinement into consideration, the tie line length and interfacial tension can be reduced, which contribute to a lower CO2 minimum miscible pressure (MMP). In this way, the efficiency of CO2 immiscible flooding is improved, while the efficiency of miscible flooding is not affected by a confinement effect. Furthermore, the length of a CO2 immiscible zone can be decreased by nanoscale pore confinement.
Effect of Methane Adsorption on Stress-Dependent Porosity and Permeability in Shale Gas Reservoirs
Authors: Pang Y. , Soliman M. Y. , Deng H. , Emadi Hossein 
Published: April 2016

Abstract
Although stress-dependent porosity and permeability have been applied to majority of models to calculate effective porosity and permeability, effect of adsorbed gas specified as pore volume occupied by adsorbate is not properly accounted. However, nanoscale porosity and permeability of shale rocks would be significantly reduced, since the pore volume is occupied by layers of adsorbed gas molecules.
In this paper, we combine stress and adsorption effects to establish a new correlation of shale porosity and permeability. We calculate the stress-dependent pore volume with a constant pore compressibility and obtain the volume of adsorbate from doing regression analysis for density of adsorbed gas by Dubinin-Astakhov (D-A) equation under the supercritical condition. Lab experiments for methane adsorption in shale are measured by five real core samples. The data of Gibbs adsorption obtained by experiments is converted to absolute adsorption so that it could be used to generate the correlation of stress-dependent porosity and permeability including consideration of adsorption effect.
The new generated correlation illustrates that the trend of changes in porosity and permeability with pore pressure is quite similar to the trend calculated by Shi-Durucan (S-D) model in application to coalbed methane, which indicates that porosity and permeability decrease with the increase of pore pressure. This tendency is the inverse of changes in stress-dependent porosity and permeability in relation to pore pressure, which demonstrates that adsorption has a larger influence on pore volume than stress, because more gas attempts to adsorb on surface area of matrix as pore pressure increases. The new correlation is added into a numerical model in field-scale, which successfully matches production data from a horizontal well with multistage hydraulic fractures in Barnett shale reservoir. The simulation results point out that without considering the impact of pore volume occupied by adsorbed gas, cumulative gas production would be greatly overestimated during economical producing period in shale gas reservoirs.
Thus, overestimation of porosity and permeability in shale might be avoided by applying the new correlation considering both stress and adsorption effects. The correlation incorporated into numerical simulators could provide accurate estimation and evaluation of gas production.
A Multi-Scale Imaging and Modeling Workflow for Tight Rocks
Authors: Ruspini L. C. , Lindkvist G. , Bakke S. , Alberts L. , Carnerup A. M. , Øren P. E. 
Published: April 2016

Abstract
Heterogeneous rocks with broad pore size distributions, such as carbonates and clay-rich sandstones, often display widely varying behavior. The interaction of micro- and macro-porosity in these complex rocks makes them difficult both to understand and to characterize. Pore scale imaging and modeling has the potential to greatly improve our understanding and predictive capabilities of these complex rocks. However, a single imaging technique can rarely capture the relevant length scales in desired detail due to restrictions of image size vs. resolution. Similarly, direct simulations of transport properties in heterogeneous rocks with broad pore size distributions are prohibitively expensive computationally.
In the present work we present a multi-scale imaging and modeling workflow to compute transport properties of rocks with wide pore size distributions. A dry/wet micro-CT imaging sequence is used to spatially map the porosity distribution and connectivity of macro- (i.e. resolved) and micro-porous (i.e. sub-resolution) regions. The registered 3D porosity map is transformed into a multi-scale pore network model where macro-porosity regions are modeled in a conventional pore network manner while micro-porous network elements are treated as a continuous porous medium. The necessary input parameters to characterize the micro-porous elements are computed from high resolution BSE images of different micro-porosity regions.
The multi-scale workflow was applied to two samples of tight sandstones. Computed petrophysical properties as well as capillary pressure and relative permeability relationships are compared with available experimental data. The agreement between computed and measured results is encouraging. The results clearly demonstrate that the distribution and connectivity between macro- and micro-porosity regions control the observed transport properties.
Improved Hole Size Calculated from Cement Data in Williston Basin
Authors: Sheperd Paul , Noman Sarah , Beery William , Bridge Alexander 
Published: April 2016

Abstract
The intermediate casing hole size can be calculated from empirical data in the Williston basin. Using this calculation reduces the cement excess required, helps achieve the top of cement objectives, and reduces the cementing costs. Many operators in the Williston basin are using an outdated assumption of average hole size for calculation of cement volumes on their intermediate casing section. This results in excessive cement volumes to sometimes detrimental effect; breakdown is occurring frequently at the Mission Canyon. This occasionally causes operators to fail to meet cementing job objectives. Very few open hole calipers are run in the intermediate section in this basin, making direct measurements very rare.
In an extensive review, cement evaluation logs from approximately 300 wells in a 15-month period from January 2014 through March 2015 were used to approximate top of cement and then derive an average effective hole size. The logs evaluated were from cement bond log (CBL) and ultrasonic imaging tools. The data are controlled in a statistical manner for cement job anomalies such as losses or severe channeling.
The findings prove that intermediate casing hole size in the Williston basin is much smaller today than in the recent past. The switch from water-base mud to oil-base mud and a marked improvement in drilling speed have limited the size of the intermediate section hole. One operator was able to substantially reduce cement volumes, keeping the top of tail slurry a minimal height above the weakest formation and thus avoiding losses. As a result, this operator is achieving top of cement objectives more frequently and has substantially reduced cementing cost.
This analysis contributes to the community valuable empirical data about intermediate section hole size in the Williston basin using a large dataset and statistical controls to ensure quality of the conclusions.