bluuebunny/crossref_metadata_2025_split huggingface dataset:
Literature Review of Modeling Techniques for Foam Flow through Porous Media
Authors: Ma Kun , Ren Guangwei , Mateen Khalid , Morel Danielle , Cordelier Philippe 
Published: June 2014

Abstract
Foam, a dispersion of gas in liquid, has been investigated as a tool for gas mobility and conformance control in porous media for a variety of applications since late 1950s. These applications include enhanced oil recovery, matrix acidization treatments, gas leakage prevention, as well as contaminated aquifer remediation. In order to understand the complex physics of foam in porous media and to implement foam processes in a more controllable way, various foam modeling techniques have been developed in the past three decades.
This paper reviews modeling approaches obtained from different publications for describing foam flow through porous media. Specifically, we tabulate models based on their respective characteristics, including empirical and semi-empirical as well as mechanistic population-balance foam models. In various population-balance models, how foam texture is obtained and how gas mobility is altered as a function of foam texture, among other variables, are presented and compared. It is generally understood that both the gas relative permeability and viscosity vary in the reduction of gas mobility through foam generation in porous media. However, as the two parameters appear together in the Darcy's equation, different approaches have been taken to alter the mobility in the various models: only reduction of gas relative permeability, increasing of effective gas viscosity, or a combination of both. The applicability and limitations of each approach are discussed. How various foam generation mechanisms play a role in the foam generation function in mechanistic models is also discussed in this review, which is indispensable to reconcile the findings from different publications. Additionally, other foam modeling methods, such as the approaches using the fractional flow theory and those using the percolation theory, are also reviewed in this work. Several challenges for foam modeling, including model selection and enhancement, fitting parameters to data, modeling oil effect on foam behavior, and upscaling of foam models are also discussed at the end of this paper.
Preformed Particle Gel Extrusion through Open Conduits during Conformance Control Treatments
Authors: Imqam Abdulmohsin , Bai Baojun , Al Ramadan Mustafa , Wei Mingzhen , Delshad Mojdeh , Sepehrnoori Kamy 
Published: June 2014

Abstract
Millimeter-sized (10 um~mm) preformed particle gels (PPGs) have been used successfully as conformance control agents in more than 5,000 wells. They help to control both water and CO2 production through high-permeability streaks or conduits (large pore openings), which naturally exist or are aggravated either by mineral solutions or by a high injection pressure during the flooding process. This paper explores several factors that can have an important impact on the injectivity and plugging efficiency of PPGs in these conduits. Extensive experiments were conducted to examine the effect of the conduit's opening size and the PPG strength on the ratio of the particle size to the opening diameter, injectivity index, resistance factor, and plugging efficiency. Five-foot tubes with four internal diameters were designed to emulate the opening conduits. Three pressure taps were mounted along the tubes to monitor PPG transport and plugging performance. The results show that weak gel has less injection pressure at a large particle opening ratio compared to strong gel. PPG strength impacted injectivity more significantly than did particle opening ratio. Resistance factor increased as the brine concentration and conduit opening size increased. PPGs can significantly reduce the permeability of an open conduit and their plugging efficiency depends highly on the particle strength and the conduit's opening size. The particle size of PPG was reduced during their transport through conduits. Experimental results confirm that the size reduction was caused by both dehydration and breakdown. Based on the lab data, two mathematical models were developed to quantitatively calculate the resistance factor and the stable injection pressure as a function of the particle strength, particle opening ratio, and shear rate. This research provides significant insight into designing better millimeter-sized particle gel treatments intended for use in large openings, including open fractures, caves, worm holes, and conduits.
New Water Soluble Anionic NVP Acrylamide Terpolymers for Use in Harsh EOR Conditions
Authors: Gaillard N. , Giovannetti B. , Favero C. , Caritey J.-P. , Dupuis G. , Zaitoun A. 
Published: June 2014

Abstract
Water soluble anionic polymers are widely used as Mobility Control agents in EOR. However, their shear, salt, free radical and thermal stability limit their domain of application. A joint industrial effort has led to new optimized polymer compositions. The chemical structure has been designed to improve long term thermal and salt stability. The functional groups on the polymer chain are acrylamide (AM), sodium acrylate (AA), sodium acrylamido-tertiary-butyl sulfonate (ATBS) and N-vinyl pyrrolidone (NVP). The composition of the different groups was varied to produce different polymer prototypes. The bulk gel polymerization process used to produce at industrial scale EOR polymers has been fine-tuned using NMR structural analysis at different conversion rates. The best polymer candidates were submitted to stability tests. Thermal stability was investigated with residual oxygen between 0 and 200ppb at temperature up to 120°C and salinity up to 70 g/L TDS with high hardness. Results show that the joint presence of NVP and ATBS in specific amounts in the polymer structure improves thermal and salt stability. Some of the polymers, whose chemical structure was optimized to maximize stability, could withstand harsh reservoir conditions with little loss of viscosity for an aging time of at least 1 year. These species were then submitted to coreflood experiments and showed good propagation properties in a 100-150 mD carbonate rock. Results show that polymer flooding can be successful in reservoirs with high temperature and harsh salinity conditions. The thermal resistant polymers can be used for polymer, surfactant polymer floods and are promising for alkaline surfactant polymer systems as well. They may be beneficial to other oil and gas applications where heat and salt stability are needed. With this technology, polymer viscosity is stable while it propagates through the reservoir and a favorable mobility ratio is maintained from injectors to producers.
Optic imaging of Oil/Water flow behavior in nano-scale channels
Authors: Liu Songyuan , Wu Qihua , Bai Baojun , Ma Yinfa , Wei Mingzhen , Yin Xiaolong , Neeves Keith 
Published: June 2014

Abstract
Unconventional oil reservoir has presented the potential to become a significant source of hydrocarbon in the future productions. Many shale oil systems consist of nano-scale pores and micro-scale fractures that are significantly smaller than those from conventional reservoirs. Such small size of the pore throats in shale may differ from the size of the saturating fluid molecules by only slightly more than one order of magnitude. This difference will result in different wettability, fluid flow mechanisms and storage capabilities in unconventional shale oil systems. However, the fluid flow behavior in the micro-scale or even nano-scale pores and channels is poorly investigated and understood. Therefore, it is increasingly important to investigate fluid flow behaviors and the fluids residue saturation in the nano-scale channels. In this work, a lab-on-chip approach for direct visualization of the water/oil flow in nano-scale channels is developed by using advanced confocal microscopy system combined with nano-fluidic chip. A comprehensive study of water/oil flow behaviors is presented. During drainage process, liquids tend to be piston like flow under micro; both residual phase saturation and configuration affect the flow behavior under smaller scale. During imbibition process, a fading out phenomenon was observed which. For residual phase saturation, confocal system can give a precise description within 3-dimensional scale.
Development of a Multi-Continuum Multi-Component Model for Enhanced Gas Recovery and CO2 Storage in Fractured Shale Gas Reservoirs
Authors: Jiang Jiamin , Shao Yuanyuan , Younis Rami M. 
Published: June 2014

Abstract
Shale gas reservoirs have been proposed as feasible choices of location for injection of CO2 and/or N2 because this method could enhance recovery of natural gas resources, while at the same time sequester CO2 underground. In this paper, a fully coupled multi-continuum multi-component simulator which incorporates several transport/storage mechanisms is developed. To accurately capture physics behind the transport process in shale nanopores, Kundsen diffusion and gas slippage are included in the flow model. An extended Langmuir isotherm is used to describe the adsorption/desorption behavior of different gas components and the displacement process of methane as free gas. Pressure-dependent permeability (due to rock deformation) of natural fractures induced by hydraulic fracturing is also considered in the simulator.
In addition, modeling of complex fracture networks is very crucial for simulating production of shale gas reservoirs because there exists various scales of fractures with multiple orientations after the fracturing treatment for horizontal well. In this work, a hierarchical approach which integrates EDFM with dual-continuum concept is adopted. The hybrid model includes three domains: matrix, major hydraulic fractures and large-scale natural fractures (described by EDFM), and micro-fractures in SRV region which are modeled by dual-continuum approach. Embedded Discrete Fractures Model (EDFM) is an efficient approach for explicitly simulating large-scale fractures in Cartesian grid instead of complicated unstructured grid. Moreover, a nested-grid refinement method is used to capture the fluids transfer from matrix to fractures.
Fully implicit scheme is applied for discretizing fluid equations, and the corresponding Jacobian matrix is evaluated by Automatic Differentiation with Expression Templates Library (ADETL). The AD-Library framework allows wide flexibility in the choice of variable sets and provides generic representations of discretized expressions for gridblocks. Several simulations and sensitivity analysis are performed with the developed research code for determining the key factors affecting shale gas recovery. Modeling studies indicate that the properties of fracture networks could greatly influence methane production. Different injection strategies including huff-n-puff scenario are also evaluated to provide insights for optimizing production of multi-fractured horizontal well. Results show that CO2/N2 injection can be an effective approach with great application potential for enhancing shale gas recovery.
Coupled Geochemical-Based Modeling of Low Salinity Waterflooding
Authors: Nia Korrani Aboulghasem Kazemi , Jerauld Gary R. , Sepehrnoori Kamy 
Published: June 2014

Abstract
Low salinity waterflooding is an emerging EOR technique in which the salinity of the injected water is substantially reduced to improve oil recovery over conventional higher salinity waterflooding. Although there are many low salinity experimental results reported in the literature, publications on modeling this process are rare. While there remains some debate about the mechanisms of LoSal®1 EOR, the geochemical reactions that control the wetting of crude oil on the rock are likely to be central to a detailed description of the process. Since no comprehensive geochemical-based modeling has been applied in this area, it was decided to couple a state-of-the-art geochemical package, IPhreeqc, developed by the United States Geological Survey (USGS) with UTCOMP, the compositional reservoir simulator developed by The University of Texas at Austin.
A step-by-step algorithm is presented for integrating IPhreeqc with UTCOMP. Through this coupling, we are able to simulate homogeneous and heterogeneous (mineral dissolution/precipitation), irreversible, and ion-exchange reactions under non-isothermal, non-isobaric and both local-equilibrium (away from the wellbore) and kinetic (near wellbore) conditions. Consistent with the literature, there are significant effects of water-soluble hydrocarbon components (e.g., CO2, CH4, and acidic/basic components of the crude) on buffering the aqueous pH and more generally, on the crude oil, brine, and rock reactions. Thermodynamic constrains are used to explicitly include the effect of these water-soluble hydrocarbon components. Hence, this combines the geochemical power of IPhreeqc with the important aspects of hydrocarbon flow and compositional effects to produce a robust, flexible, and accurate integrated tool capable of including the reactions needed to mechanistically model low salinity waterflooding.
Different geochemical-based approaches to modeling wettability change in sandstones (e.g., interpolation based on total ionic strength and Multicomponent Ion Exchange through surface complexation of the organometallic components) were implemented in UTCOMP-IPhreeqc and the integrated tool is then used to match and interpret a low salinity experiment published by Kozaki (2012) and the field trial done by BP at the Endicott field.
Impact of Surfactant Structure and Oil Saturation on the Behavior of Dense CO2 Foams in Porous Media
Authors: CHABERT Max , NABZAR Lahcen , BEUNAT Virginie , LACOMBE Emie , CUENCA Amandine 
Published: June 2014

Abstract
Miscibility with oil lies among the main advantages of dense CO2 injection for pore scale oil displacement during tertiary recovery. At reservoir scale, injecting dense CO2 in the form of foam can also improve its sweep efficiency. However, although the use of such miscible dense CO2 foams has been considered in over twenty pilots since the 1980's, only few lab studies have considered foams formed with CO2 in this particular thermodynamical state. Indeed, dense CO2 has solvation properties and a viscosity higher than that of a gas. This impacts several attributes of its foams in porous media, such as Mobility Reduction Factors (MRF) and behavior in presence of oil.
We present new results demonstrating that classical foamers are not effective in improving mobility control of dense CO2, but that relatively high MRF are achieved using carefully formulated surfactants. Based on these findings, we study the impact of foam on miscible flooding efficiency in corefloods. Reversely, we also evaluate how miscibility of CO2 with oil impacts foam MRF. Our approach is based on multiple corefloods experiments, with different formulations, at various oil saturations. Additionally, physical-chemistry measurements such as interfacial tension estimations and foam stability monitoring are performed in reservoir conditions (pressure and temperature). This set of experiments shows that a balance must be found between maximizing MRF and minimizing the risk of emulsion formation in porous media.
This paper brings new insights on the interpretation of CO2 foams coreflood results, based on the thermodynamical properties of the CO2 phase. It provides the reader with a clearer view of gas properties that must be considered when analyzing results of dense CO2 foams corefloods. This can help reconcile seemingly contradictory results appearing in the literature, particularly regarding the values of MRF as a function of pressure and in the presence of oil.
Aspects of Modeling Asphaltene Deposition in a Compositional Coupled Wellbore/Reservoir Simulator
Authors: Darabi Hamed , Shirdel Mahdy , Kalaei M. Hosein , Sepehrnoori Kamy 
Published: June 2014

Abstract
Asphaltene precipitation, flocculation, and deposition in the reservoir and producing wells cause serious damages to the production equipment and possible failure to develop the reservoirs. From the field production prospective, predicting asphaltene precipitation, flocculation, and deposition in the reservoir and wellbore essentially avoids high expenditures associated with the reservoir remediation, well intervention techniques, and field production interruption. Since asphaltene precipitation and deposition strongly depend on the pressure, temperature, and composition variations (e.g. phase instability due to CO2 injection), it is important to have a model that can track the fluid behavior during the entire production process from the injection well to the production well, which is absent in the literature.
In this paper, a comprehensive thermal compositional coupled wellbore/reservoir simulator with a capability of modeling asphaltene phase behavior in the reservoir and the wellbores is presented to address the wellbore/reservoir interaction, the effect of asphaltene deposition on the flow prediction and long-term reservoir performance. Indeed, the simulator models multiphase fluid flow in the reservoir and the wellbore to enable comprehensive production system analysis. In addition, wettability alteration due to the asphaltene deposition on the rock surface is considered in our models.
We present primary production and CO2 flood simulation cases to investigate the effect of asphaltene deposition on oil recovery. The results show that injection of the light components into the reservoir significantly increases the instability of asphaltene components in the reservoir where they can precipitate further around the wellbore and in the wellbore. The precipitated asphaltene in the reservoir can be carried into the wellbore and be combined with excess asphaltene formation and deposit in the wellbore. In addition, our simulation shows that well productivity decreases significantly in case of asphaltene precipitation and deposition during the production life of a reservoir.
Modeling the Effects of Porous Media in Dry Gas and Liquid Rich Shale on Phase Behavior
Authors: Ma Yixin , Jamili Ahmad 
Published: June 2014

Abstract
Because of the confinement effects in shale formations, fluid flow is different compared to conventional reservoirs. The interactions between the fluid molecules and porous wall inside nanopores play such an important role that can change the phase behavior of the fluids. The fluids in shale reservoirs are usually stored in two forms, free fluids and adsorbed fluids. The region where free fluids are stored has negligible fluid-wall interactions while the region for adsorbed fluids is under strong pore wall influence. The current available equations of state cannot capture the phase behavior of the adsorbed phase in porous media due to the ignorance of the fluid-wall interactions. This paper discussed the effects of the fluid-wall interactions on fluid phase behavior from a modeling of of view.
The production from shale reservoirs in the US has shifted from gas windows to condensate windows and oil windows recently due to low natural gas price. Liquid-rich shales, such as Barnett, Eagle Ford, and Marcellus are brought more attentions than ever before. Thus, it is critical to understand the fluid phase behavior and properties and their impacts on production in the condensate systems. Our work focuses on the predictions of fluid critical property change and fluid density change inside nanoporous media. Simplified Local-Density theory for single component coupled with modified Peng-Robinson Equation of State was used to predict the density profiles of dry gas (pure methane) in confined pores. The model was then extended to mixtures for the study of condensate systems.
Our results showed that due to the fluid-wall interactions, the fluid density is not uniformly distributed across the pore. The fluid density is higher near the wall than that in the center region of the pore. It also showed that depending on fluid types, temperature, pressure and pore sizes, the fluid density profile would change. The pore size range we focused on was from 2 nm to 10 nm. In order to present the condensate system, a synthetic mixture of 75% methane and 25% n-butane is used. It is found that fluid composition is not uniform across the pore. Heavier component (n-butane) tends to accumulate near the wall while lighter component (methane) would like to stay in the center region of the pore. For a 10 nm wide pore, the composition of n-butane of the synthetic mixture can be as high as 66% close to the pore wall.
Enhancing Well Stimulation with Improved Salt Tolerant Surfactant for Bakken Formation
Authors: Zhou Jia , Cutler Jennifer , Hughes Baker , Morsy Samiha , Morse Aaron , Sun Hong , Qu Qi 
Published: June 2014

Abstract
The Bakken formation is located in parts of Montana, North Dakota, and Saskatchewan, Cananda. North Dakota alone produces more than 700,000 barrels per day and still growing, which accounts for 11 percent of the domestic total crude oil production, while the oil recovery factor of 1% in Bakken is necessary to be improved to a higher level. Current practice involves fracture stimulation of the mature Upper and Lower Bakken Shales above and below the middle layer (pay zone in carbonate or siltstone). The fractures penetrate and connect natural fractures within the reservoirs and promote more efficient drainage of the oil. This situation suggests that a surfactant technology incorporating in the well stimulation fluids at low dosage can be a fit in Bakken formation to enhance oil recovery. If properly designed, such additives in the fracture fluids will penetrate into the highly oil-saturated matrix or natural fracture region and accelerate the extraction of the oil in place by rapid imbibition. Extracted oil can readily flow from the matrix into the propped fracture system. Another benefit of this surfactant technology is its engineered property to leave the matrix or natural fracture face water-wet to facilitate oil movement during production.
This paper presents a study of a series of such stimulation fluid additives developed for enhanced oil recovery. Crude oil samples from the Bakken formation were analyzed for several properties pertinent to surfactant formulation including organic constituents, total acid number, and viscosity. Compatibility tests were carried out including surfactant/produced water interaction, emulsion tendency, and surfactant compatibility with proposed fracturing fluids. A spontaneous imbibition process was employed to mimic surfactant additives penetrating the tight matrix and microfractures to recover more hydrocarbons. The results show that more than one of these products improved recovery of Bakken crude oil by spontaneous imbibition. The best of these products is recommended for field application.