bluuebunny/crossref_metadata_2025_split huggingface dataset:
Capillary Pressure: Is It Critical for Investment Decisions? Case Study of Gas Condensate Reservoir Underlain with Water
Authors: Fayzullin Maksim , Nasibullin Artur , Yazkov Alexey , Kolbikov Sergey 
Published: June 2012

Abstract
The paper highlights the importance of adequate characterization of capillary pressure effects when preparing a development plan for a greenfield gas condensate reservoir with a large transition zone (TZ).
Capillary pressure data from centrifuge or porous plate (semi-permeable membrane) are used to characterise the transition zone. It is essential that a representative set of sample measurements is obtained. Core laboratories are not capable to keep initial pressure-temperature conditions during capillary pressure measurements. Hence, the conversion from surface to reservoir becomes uncertain. Conversion utilizes interfacial tension and wettability angle which are quite unknown and can be predicted using different P-T charts. Finally saturation model depends on the way of: characterization - discrete Rock Types (RT) or tuned-up Continuous Functions (Leverett, Amaefule etc.); matching log saturation profile with the one observed in the model; welltest playback in terms of mobile water and drained volumes.
In this study, the authors present a systematic workflow on how capillary pressure should be incorporated in a dynamic simulation model pointing out example pitfalls and giving validation tips. The illustrated case shows that if one of the steps is missed or wrong assumptions are made, then the TZ and the production potential will be incorrect. In our example, the discretization of connate water saturation and capillary pressure curves on early stages resulted to 8% underestimation of GIIP. Moreover, results indicated that uncertainty in conversion of capillary curves (from surface to reservoir) gives 15-20% differences in outcomes (depending on development scenario). Also it demonstrates a strong impact on the length of production plateau, rate of wellhead pressure decline, compression start-up which are vital aspects for the development concept, especially during front-end-loading stage of the project plan. We feel that the procedures presented here (both for engineers and management) can serve as a guide for QC and possible failures when they are not applied.
Improving Well Cementing Quality with an Environmentally Preferred Multifunctional Polymer
Authors: Brandl Andreas , Bray Windal Scott , Magelky Christina 
Published: June 2012

Abstract
A modified cellulose-based polymer has been tested according to API recommended practices in various cement slurries and was identified to have multiple beneficial functions in addition to be environmentally friendly. Test results demonstrate that this single additive controls fluid loss better than commonly used fluid loss additives at temperatures up to 170 °F while also controlling free fluid and performing as an extender. In addition, it was found to work as a foam stabilizer and gas control agent in cement slurries, which was not observed for any other cellulose-based polymers tested. The modified cellulose-based polymer also exhibits less slurry viscosification, which facilitates surface mixing and pumping of the corresponding cement slurries. This paper will describe test procedures, discuss test results, and demonstrate that a single modified cellulose-based polymer can replace several additives in a cement system to adjust the required cement slurry performances for optimum placement and properties in the wellbore. These findings are accomplished by a case history showing the successful application of the modified cellulose-based polymer for a deepwater cementing operation in the South China Sea. The here presented multifunctional biopolymer simplifies cement slurry design and operations contributing to higher quality cement jobs.
Machine Learning Methods to Speed up Compositional Reservoir Simulation
Authors: Gaganis Vassilis , Varotsis Nikos 
Published: June 2012

Abstract
Compositional reservoir simulation is the most powerful tool available to the reservoir engineer upon which, nowadays, most reservoir development decisions rely on. According to the number of components used to describe the fluids, there is a very high demand for computational power due to the complexity and to the iterative nature of the phase behavior problem solution process. Phase stability and phase split computations often consume more than 50% of the simulation's total CPU time as both problems need to be solved repeatedly for each discretization block at each iteration of the non-linear solver. Therefore, the speeding up of these calculations is a challenge of great interest.
In this work, machine learning methods are proposed for the solving of the phase equilibrium problem. It is shown that by using proper transformations, the unknown closed-form solution of the Equation-of-State based formulation can be emulated by proxy models. The phase stability problem is treated by classifiers which label the fluid's state in each block as either stable or unstable. For the phase-split problem, regression models provide the prevailing equilibrium coefficients values given the feed composition, pressure and temperature. The development of both models is performed rapidly and offline in an automated way, by utilizing the fluid's tuned-EoS model, prior to running the reservoir simulator. During the simulation run, the proxy models are called to provide direct answers of the phase equilibrium problem at a very small CPU charge instead of solving iteratively the phase behavior problem.
The proposed approach is presented in two-phase equilibria formulation but it can be extended to multi-phase equilibria applications. Examples demonstrate the accuracy of the calculations and the very significant CPU time reduction achieved with respect to currently used methods.
A New Comprehensive Approach for Predicting Injectivity Decline during Waterflooding
Authors: Yuan H. , Nielsen S. M. , Shapiro A. A. , Bedrikovetsky P. 
Published: June 2012

Abstract
Injectivity decline during sea waterflooding or produced water re-injection is widely observed in North Sea, Gulf of Mexico and Campos Basin fields. The formation damage occurs mainly due to the deposition of suspended solids around injectors and the build-up the external filter cakes in the well bores. The ability to predict injectivity decline accurately is of great importance for project designs and water management. A comprehensive model that incorporates a variety of factors influencing the process is desirable for the prediction. In this paper, a new comprehensive approach for predicting injectivity decline during water flooding is proposed. The deep bed filtration is described by novel stochastic random walk equations. The injectivity decline model takes into account the reservoir heterogeneity and the distribution of solid particles by sizes. It also accounts for the later formation of the external filter cake and its erosion. A piece of software SNY is developed with the proposed model. The model is able to capture the behaviors of the injectors in the field: the initial slow injectivity decline due to the deep bed filtration of suspended particles, the later faster decline due to the build-up of the external cake, and the temporary steady state due to the cake erosion. Stronger normal dispersion or median heterogeneity close to the injector leads to farther penetration of the particles and slower impedance increase. Neglecting the particle population heterogeneity may lead to the underestimation of formation damage and predicts late transition to external cake formation. The impedance at the steady state and the starting time are highly influenced by the cake properties. The impedance and the external cake thickness at the steady state are likely to be higher in horizontal wells than those in vertical wells.
New Insights Into CO2 Injection and Storage in Saline Aquifers
Authors: Sohrabi Mehran , Riazi Masoud , Bernstone Christian , Jamiolahmady Mahmoud , Christensen Niels-Peter 
Published: June 2012

Abstract
Worldwide, significant efforts and resources are being directed at evaluating potentials of CCS (carbon capture and storage) for the long term storage of large quantities of CO2 that would otherwise be released in the atmosphere. Despite many years of experience with CO2 injection in oil reservoirs, our current understanding of brine/CO2 interactions that occur during CO2 injection in aquifers (brine-bearing rocks) remains very limited. This is a source of uncertainty and concern not just for the governments and companies interested in investment in CCS but also for the public in relation to the safety of long term injection and storage of CO2 in geologic formations.
In this paper we report new insights into the pore-scale interactions between super-critical CO2 and brine obtained from the results of a series of CO2 injection visualisation experiments carried out in novel high-pressure transparent porous media. In these experiments, we have physically simulated and visually investigated the micro-scale behaviour of CO2 in brine-bearing porous media. In particular, through vivid images of fluids distribution taken during the experiments, we highlight a new mechanism in which CO2 evolution follows CO2 dissolution in brine. In parts of the porous medium in which CO2 injection was taking place, it was observed that a free CO2 phase nucleated and came out of solution and gradually expanded. The phenomenon accelerated when the brine salinity increased or when the CO2 injection rate increased.
The observed mechanism is expected to affect many important aspects of CO2 flow and retention in porous media. It may increase CO2 storage capacity by displacing more brine. On the other hand, it can adversely affect the ability of rock to safely contain the stored CO2.
Experimental and Theoretical Investigation of Gas/Oil Relative Permeability Hysteresis under Low Oil/Gas IFT and Mixed-Wet Conditions
Authors: Fatemi S. Mobeen , Sohrabi Mehran , Jamiolahmady Mahmoud , Ireland Shaun 
Published: June 2012

Abstract
Accurate determination of relative permeability values and their hysteresis is crucial for obtaining a reliable prediction of the performance of water-alternating-gas (WAG) injection in oil reservoirs. In this paper we report two series of gas/oil relative permeability curves obtained from coreflood experiments carried out in a mixed-wet core under a very low oil/gas interfacial tension (IFT) of 0.04mN.m−1. The first set of the corefloods began by oil injection (imbibition) in the core saturated with gas and immobile water (Swi). This was followed by a period of gas injection (drainage) and this sequential injection of oil and gas continued and in total, three imbibition and two drainage periods were carried out. In the second series of experiments, the core was initially saturated with oil and immobile water and the experiment started with a gas injection followed by cycles of drainage and imbibitions.
The measured pressure drop and production data were history matched through simulation analysis to obtain krg and kro values for each of the imbibition and drainage cycles. The results show that both the oil and the gas relative permeability curves show cycle-dependent hysteresis despite the very low gas/oil IFT. Therefore, the current assumption in existing models (such as Land, Carlson and Killough) that the drainage scanning kr curves follow the preceding imbibition curve is not supported by our coreflood experiments.
When compared to our measured data, Carlson model predictions for krg in imbibition direction are poor. Killough model predictions underestimate krg and overestimate kro especially near trapped gas saturation regions. Beattie et al. hysteresis model is able to capture the krg and kro behavior that we observed in our experiments qualitatively, but it is still unable to predict the value of the observed hysteresis. The results suggest that for mixed-wet systems, it is necessary to consider irreversible hysteresis loops for both the wetting and non-wetting phases. Such capability currently does not exist in reservoir simulators due to lack of appropriate predictive tools.
Depth of Investigation and Depletion Behavior in Unconventional Reservoirs Using Fast Marching Methods
Authors: Xie Jiang , Gupta Neha , King Michael J. , Datta-Gupta Akhil 
Published: June 2012

Abstract
The concept of depth of investigation is fundamental to well test analysis. Much of the current well test analysis relies on solutions based on homogeneous or layered reservoirs. Well test analysis in spatially heterogeneous reservoirs is complicated by the fact that Green’s function for heterogeneous reservoirs is difficult to obtain analytically (Deng and Horne 1993). In this paper, we introduce a novel approach for computing the depth of investigation and pressure response in spatially heterogeneous and fractured reservoirs.
In our approach, we first present an asymptotic solution of the diffusion equation in heterogeneous reservoirs. Considering terms of highest frequencies in the solution, we obtain two equations: the Eikonal equation that governs the propagation of a pressure ‘front’ and the transport equation that describes the pressure amplitude as a function of space and time. The Eikonal equation generalizes the depth of investigation for heterogeneous reservoirs and provides a convenient way to calculate drainage volume. From drainage volume calculations, we estimate a generalized pressure solution based on a geometric approximation of the drainage volume. A major advantage of our approach is that the Eikonal equation can be solved very efficiently using a class of front tracking methods called the Fast Marching Methods (FMM). Thus, transient pressure response can be obtained in multimillion cell geologic models in seconds without resorting to reservoir simulators.
We first visualize depth of investigation and pressure solution for a homogeneous reservoir with multi-stage transverse fractures and identify flow regimes from pressure diagnostic plot. And then, we apply the technique to a heterogeneous reservoir to predict depth of investigation and pressure behavior. The computation is orders of magnitude faster than conventional numerical simulation and provides a foundation for future work in reservoir characterization and field development optimization.
Evaluation of the CO2 Storage Capacity of the Captain Sandstone Formation
Authors: Jin Min , Mackay Eric , Quinn Martyn , Hitchen Ken , Akhurst Maxine 
Published: June 2012

Abstract
The volume of CO2 that can be stored in the Captain Sandstone saline aquifer in the North Sea was investigated by building a geological model and performing numerical simulations. These simulations were also used to calculate the best position for the injection wells, and the migration and ultimate fate of the CO2.
The overall migration of CO2 and the pressure response over the entire saline aquifer was studied by the calculated injection of 15 million tonnes CO2 per year. The injection rate was restricted to a maximum of 2.5 million tonnes CO2 per year for each of a possible 12 wells considered. An important objective was to predict how to avoid flow of the injected CO2 toward potential leakage points, such as the sandstone boundaries and faults. The migration of injected CO2 towards existing oil and gas fields was also a determining factor.
The summary conclusions are: The Captain Sandstone saline aquifer has significant potential CO2 storage capacity. Even with all boundaries closed to flow, the probable storage capacity is calculated to be about 358 million tonnes, giving a storage efficiency of 0.6% of pore volume, with an expected operating life-span of 15-25 years.The possible storage capacity of the formation may be at least four times greater if the aquifer boundaries are open. This increase would be a result of displacement of salt water, and not CO2.The storage capacity if the sandstone is closed to flow may be increase from 358 to 1668 million tonnes of CO2 by significant additional investment in 15 to 20 water production wells.Injection of up to 2.5 million tonnes CO2 per year in one well has an impact on the pressure throughout the entire formation, and thus interference between different injection locations must be considered.
xzsEffect of Drilling Fluid (Water-Based vs Oil-Based) on Phase Trap Damage in Tight Sand Gas Reservoirs
Authors: Mitchel Tsar , Hassan Bahrami , Reza Rezaee , Geeno Murickan , Sultan Mehmood , Mohsen Ghasemi , Abolfazl Ameri , Mahna Mehdizadeh 
Published: June 2012

Abstract
Tight gas reservoirs are mainly characterized by low matrix permeability and significant damage. During drilling and fracturing of tight formations, wellbore liquid invades into tight formation and increases water saturation around wellbore and eventually reduces permeability near wellbore or adjacent to fracture wings. The damage to permeability caused by invasion of liquid into tight formation is controlled by capillary pressure and relative permeability curves.
The phase trap damage is one of the main concerns in use of water based drilling or fracturing fluid, since due to high critical water saturation, strong capillary pressure, and sensitivity of tight sand to water. Therefore, use of oil based mud may be preferred in drilling or fracturing of tight formation. However invasion of oil filtrate into tight formation may result in a three-phase relative permeability curves in invaded zone in presence of reservoir gas and initial water, which may differently affect damage and productivity of tight gas reservoirs.
This study evaluates phase trap damage in water-based in comparison with oil-based drilled or fractured tight gas reservoir. Reservoir simulation is used to study the effect of relative permeability curves on phase trap damage and well productivity, based on reservoir and core data from a West Australian tight gas reservoir. The results highlights benefits of using oil-based fluids in drilling and fracturing of tight gas reservoirs in term of improving well productivity.
Development Of An Integrated Evaluation Methodology On Scale Management Pre- and Post-Production: An Engineer’s Perspective
Authors: Akuanyionwu Obinna , Wahid Fazrie 
Published: June 2012

Abstract
Scale formation can have a detrimental impact on production if left unchecked. Similarly, scale management can be costly without proper evaluation and planning. Developing a cost-effective scale management strategy during field development planning phase is imperative to assist decision making. Furthermore the strategy must address the procedures to explicitly assess the well and field performance during production, to optimize the production over the field life.
In the past, the assessment of potential for scale formation was performed based on static scaling risk assessment method, which relied solely on the output from static thermodynamic scale prediction models. In this document, we introduce a systematic methodology to assess the scale formation risk as time dependent by coupling dynamic modeling with static scaling risk assessments; where streamline simulation technique has been used to predict scale precipitation in the reservoir and the consequent in-situ stripping of scaling ions. Extending the use of the dynamic simulation tools to assess the scaling risks in reservoir and near wellbore will assist in field development planning, development, as well as production operation, monitoring and optimization.
Workflows developed on a North Sea field development (pre- and post-production) are described, including results from analog/synthetic datasets as examples. Our work indicates that both in-situ ion stripping and drainage patterns significantly influence chemical requirements and treatment frequencies for squeeze treatments following in-situ scale deposition. It also shows from a historical perspective how scale has impacted production in analogue wells and more importantly to characterize the location of the precipating scale. Finally, we highlight limitations in current industry tools and workflows, and what can be done to reduce uncertainties during the development of a scale management strategy.
Synchronous totally asymmetric exclusion process with a dual-input-single-output junction
Authors: Xiao Song , Wu Shuying , Zheng Dongsheng 
Published: June 2012

Synchronous totally asymmetric exclusion process with a dual-input-single-output junctionIn this paper, the dynamics of the synchronous totally asymmetric exclusion process (TASEP) with a two-input-single-output (TISO) junction was investigated, which consists of two subchains for the input and one main chain for the output. A TISO junction is a type of complex geometry that is relevant to vehicular and pedestrian traffic flow. A mean-field approach is developed to deal with the junction that connects the subchains and the main chain. Theoretical results for stationary particle currents, density profiles, and a phase diagram have been obtained. It was found that the region of the HD/HD phase increases in the phase diagram with an increase of the hopping rates of subchains. The density profiles obtained from computer simulations show very good agreement with our theoretical analysis.
Mitochondrial Transcription Factor A Serves as a Danger Signal by Augmenting Plasmacytoid Dendritic Cell Responses to DNA
Authors: Julian Mark W. , Shao Guohong , Bao Shengying , Knoell Daren L. , Papenfuss Tracey L. , VanGundy Zachary C. , Crouser Elliott D. 
Published: June 2012

Abstract
Plasmacytoid dendritic cells (pDC) are potent APCs known to regulate immune responses to self-Ags, particularly DNA. The mitochondrial fraction of necrotic cells was found to most potently promote human pDC activation, as reflected by type I IFN release, which was dependent upon the presence of mitochondrial DNA and involved TLR9 and receptors for advanced glycation end products. Mitochondrial transcription factor A (TFAM), a highly abundant mitochondrial protein that is functionally and structurally homologous to high mobility group box protein 1, was observed to synergize with CpG-containing oligonucleotide, type A, DNA to promote human pDC activation. pDC type I IFN responses to TFAM and CpG-containing oligonucleotide, type A, DNA indicated their engagement with receptors for advanced glycation end products and TLR9, respectively, and were dependent upon endosomal processing and PI3K, ERK, and NF-κB signaling. Taken together, these results indicate that pDC contribute to sterile immune responses by recognizing the mitochondrial component of necrotic cells and further incriminate TFAM and mitochondrial DNA as likely mediators of pDC activation under these circumstances.
Polar Opposites: Erk Direction of CD4 T Cell Subsets
Authors: Chang Chiung-Fang , D’Souza Warren N. , Ch’en Irene L. , Pages Gilles , Pouyssegur Jacques , Hedrick Stephen M. 
Published: June 2012

Abstract
Effective immune responses depend upon appropriate T cell differentiation in accord with the nature of an infectious agent, and the contingency of differentiation depends minimally on TCR, coreceptor, and cytokine signals. In this reverse genetic study, we show that the MAPK Erk2 is not essential for T cell proliferation in the presence of optimum costimulation. Instead, it has opposite effects on T-bet and Gata3 expression and, hence, on Th1 and Th2 differentiation. Alternatively, in the presence of TGF-β, the Erk pathway suppresses a large program of gene expression, effectively limiting the differentiation of Foxp3+ regulatory T cells. In the latter case, the mechanisms involved include suppression of Gata3 and Foxp3, induction of Tbx21, phosphorylation of Smad2,3, and possibly suppression of Socs2, a positive inducer of Stat5 signaling. Consequently, loss of Erk2 severely impeded Th1 differentiation while enhancing the development of Foxp3+-induced T regulatory cells. Selected profiles of gene expression under multiple conditions of T cell activation illustrate the opposing consequences of Erk pathway signaling.