bluuebunny/crossref_metadata_2025_split huggingface dataset:
Carbon Dioxide Sequestration in Coal Seams: A Parametric Study and Development of a Practical Prediction/Screening Tool Using Neuro-Simulation
Authors: Odusote Olufemi , Ertekin Turgay , Smith Duane H. , Bromhal Grant , Sams W. Neal , Jikich Sinisha 
Published: December 2007

Abstract
Fossil fuels are a major source of the world's energy production and this is expected to be the case well into the 21st century. Consequently, the extensive utilization of fossil fuels has measurably increased the total load of one of its byproducts, carbon dioxide (CO2), in the atmosphere and concern about the effects on global warming has prompted the inception of various methods and policies geared at reducing the concentration of this green-house gas in the atmosphere. One of the more promising technologies is CO2 sequestration which involves the capture, separation and storage of CO2.
Production of coalbed methane is a well-developed technology, but enhanced recovery by CO2 injection has undergone relatively limited research. Recent research suggests that CO2 preferentially sorbs to coal, replacing the coalbed methane which can be produced and sold to offset the costs of sequestering CO2 thereby providing a dual role for unmineable coal seams; a source of coalbed methane and a repository for the sequestration of CO2. Production operations from a carbon dioxide-enhanced coalbed methane recovery pilot project, in the San Juan Basin, indicate that the process is technically and economically feasible.
In this work, PSU-COALCOMP, a compositional coalbed methane reservoir simulator, is used to model the primary and enhanced recovery of coalbed methane by CO2 injection for a variety of coal properties and operational scenarios. The results obtained from the simulations performed include the cumulative amount of CO2 injected and retained in the coal seam, the cumulative amount of coalbed methane produced as well as the CO2 breakthrough time. These results are considered as the performance indicators of the CO2 sequestration process. The effects of various intrinsic coal-seam properties and operational scenarios on the performance indicators of CO2 sequestration are investigated to develop a better understanding of the process.
Based on the data, results and analyses obtained from the simulations performed during the parametric study, a CO2 performance predictor tool is developed by employing neurosimulation methods. This tool is able to predict the values of the performance indicators of the CO2 sequestration process for a wide range of coal-seams and various production schemes within an acceptable margin of error and in a timely and efficient manner. The predictive capabilities of this tool also enables it to be used as a screening tool that has the ability to ascertain the viability of various coalbed reservoirs for the sequestration of CO2, as well as the optimum production scheme to be used in any given project.
An Improved Implementation of the LBFGS Algorithm for Automatic History Matching
Authors: Gao Guohua , Reynolds A. C. 
Published: December 2007

Abstract
For large scale history matching problems, where it is not feasible to compute individual sensitivity coefficients, the limited memory Broyden-Fletcher-Goldfarb-Shanno (LBFGS) is an efficient optimization algorithm1,2. However, computational experiments reveal that the original implementation of LBFGS may encounter the following problems: (i) the algorithm often does not give as good a match of production data as is expected; (ii) occasionally a bad search direction is encountered that either leads to false convergence or a restart with the steepest descent direction which radically reduces the convergence rate; (iii) on rare occasions, the LBFGS converges to a model which results in overshooting/undershooting problems, i.e., converges to a vector of model parameters which contains some abnormally high or low values of model parameters. This overshooting/undershooting occurs even though all history matching problems are formulated in a Bayesian framework with a prior model providing regularization.
Here, we show that the rate of convergence and the robustness of the algorithm can be significantly improved by: (1) a more robust line search algorithm motivated by the theoretical result that the Wolfe conditions should be satisfied; (2) an application of data damping procedure at early iterations; (3) rescaling of model parameters prior to application of the optimization algorithm; (4) an application of constraints on the permeability/porosity fields; and (5) a minor modification of the LBFGS updating formula for the inverse Hessian matrix calculation.
Applications of New Reservoir Simulation Technology in GOM Oil Fields
Authors: Litvak Michael , Johnson Daniel , Towery Lisa 
Published: December 2007

AbstractThe applications of the following new reservoir simulation tools are presented in the paper: Latest achievements in geophysics for the construction of sand/shale 3-D volumes based on seismic spectral decomposition;Synthesis of rock physics and fluid PVT analysis for correlation of seismic data to reservoir properties;Geostatistical modeling constrained by seismic and well data;History matching based on production data and time lapse seismic;Integrated reservoir and facility modeling;Field production optimization.Object based geostatistical modeling tools are applied for the construction of the 3-D facies models constrained by seismic, well data and consistent with depositional environment. The placement of these facies bodies is conditioned to a seismically derived sand/shale 3-D volume used to detect differences in a dual-facies system. The main purpose of adding the generation of these facies bodies into the workflow was to add internal heterogeneities to the model both laterally and vertically, and to ensure proper facies placement at the well locations.Three-dimensional models of reservoir properties (net-to-gross ratio, porosity, permeability, and initial fluid saturations) are built using geostatistical methods with seismic and well constraints. Correlations from rock physics are applied to directly derive rock properties from seismic attributes (separately for each facies). The seismically derived rock properties are used as the 3-D trends in the geostatistical modeling.Integrated modeling of multiphase fluid flow in reservoir, well tubing strings, pipeline system, and separation facilities are applied. Production optimization tools are used to determine well production/injection rates constrained by well and surface facility limitations.The applications of the new simulation technology in Gulf of Mexico (GOM) oil fields are presented. Included examples demonstrate robustness of the integrated models of reservoir geology and surface facilities and their business values. New reservoir simulation tools presented in the paper are very general and they are applicable in large variety of oil and gas fields.
A Stochastic Optimization Algorithm for Automatic History Matching
Authors: Gao Guohua , Li Gaoming , Reynolds A. C. 
Published: December 2007

Abstract
For large-scale history matching problems, optimization algorithms which require only the gradient of the objective function and avoid explicit computation of the Hessian appear to be the best approach. Unfortunately, such algorithms have not been extensively used in practice because computation of the gradient of the objective function by the adjoint method requires explicit knowledge of the simulator numerics and expertise in simulation development. Here we apply the simultaneous perturbation stochastic approximation (SPSA) method to history match multiphase flow production data. SPSA, which has recently attracted considerable international attention in a variety of disciplines, can be easily combined with any reservoir simulator to do automatic history matching. The SPSA method uses stochastic simultaneous perturbation of all parameters to generate a down hill search direction at each iteration. The theoretical basis for this probabilistic perturbation is that the expectation of the search direction generated is the steepest descent direction.
We present modifications for improvement in the convergence behavior of the SPSA algorithm for history matching problems and compare its performance to the steepest descent, gradual deformation and LBFGS algorithm for history matching examples. Although the convergence properties of the SPSA algorithm are not nearly as good as our most recent implementation of a quasiNewton method (LBFGS), the SPSA algorithm is not simulator specific and it requires only a few hours of work to combine SPSA with any commercial reservoir simulator to do automatic history matching.
To the best of our knowledge, this is the first introduction of SPSA into the history matching literature. Thus, we make considerable effort to put it in a proper context.
Direct Prediction of the Absolute Permeability of Unconsolidated and Consolidated Reservoir Rock
Authors: Jin Guodong , Patzek Tad W. , Silin Dmitry B. 
Published: December 2007

Abstract
A procedure of estimating the absolute rock permeability directly from a microscopic 3D rock image has been developed. Both computer-tomography and computer-generated images of reconstructed reservoir rock samples can be used as input. A physics-based depositional model serves to reconstruct natural sedimentary rock, and generate 3D images of the pore space at an arbitrary resolution. This model provides a detailed microstructure of the rock, and makes it possible to calculate the steady state velocity field in the single-phase fluid flow. In particular, using our model, one can analyze unconsolidated rocks whose micro-tomographic images cannot be obtained. The lattice-Boltzmann method is used to simulate viscous fluid flow in the pore space of natural and computer-generated sandstone samples. Therefore, the permeability is calculated directly from the sample images without converting them into a pore network or solving Stokes' equation of creeping flow. We have studied the effect of compaction and various styles of cementation on the microstructure and permeability of reservoir rock. The calculated permeability is compared with the Kozeny-Carman formula and experimental data.
Three-Phase Flow in Porous Media: Wettability Effect on Residual Saturations During Gravity Drainage and Tertiary Waterflood
Authors: Caubit C. , Bertin H. , Hamon G. 
Published: December 2007

Abstract
Three-phase flow configurations occur in many situations in petroleum engineering, gravity assisted gas displacement, tertiary waterflood, water alternating gas process (W.A.G.). Therefore residual saturations (oil and gas) knowledge during three-phase flow is a crucial point for reservoir engineers.
In this paper we present experimental results dealing with the influence of wettability on two and three-phase flow in porous media in short (0.25m) and long (1m) cores.
Forced displacement of gas by water and oil have been performed on the short cores while gas/oil gravity drainage in presence of irreducible water (Swi) followed by a tertiary waterflood have been performed on the long cores.
For all the experiments the saturation profiles are measured using a dual-energy gamma-ray attenuation technique.
Originality of the experiments lies on the fact that gas/oil gravity drainage and tertiary waterflood are performed on the same core during the same experiment. Two phase flow is obtained at the bottom of the core (in the capillary head region) while three-phase flow is observed in the upper part of the core. Local measurement of saturation profiles show that residual oil saturation at the end of gravity drainage depends on wettability. However we do not observe a wettability effect on three-phase residual gas saturation. Behaviour of three-phase residual oil saturation is much more complicated because its value and saturation profile depends strongly on wettability.
Evaluation Study of Various Produced-Water Treatment Technologies to Remove Dissolved Aromatic Components
Authors: Descousse A. , Mönig K. , Voldum K. 
Published: December 2007

Abstract
In the frame work of the zero discharge work ongoing in Norway, all oil companies operating on the Norwegian Continental Shelf have been obliged to deliver a field specific strategy to the Norwegian Pollution Control Authority (SFT) in 2003 explaining how to achieve the zero discharge goal in 2005. A high focus within the various presented strategies was given to the implementation of new technology or combination of existing and new technologies, especially for reducing the amount of harmful aromatic components. These components often constitute a considerable contribution to the total environmental risk of produced water.
The traditional technologies such as separators, hydrocyclones, etc. in general only remove dispersed oil and the aromatic fraction dissolved in the oil phase. However, fairly new water treatment technologies on the market are also able to remove the aromatic components dissolved in the water phase. These new technologies are usually based on extraction, stripping or adsorption technology.
By knowing the amount of aromatic components present in the dispersed oil, the removal of aromatics by traditional treatment techniques can be assessed. The results from such an assessment are presented in this paper for the Ekofisk field and compared to results from other fields, all located in the North Sea. Based on these results and on recent pilot field tests on Ekofisk, various new technologies such as CTour and Cetco units have been evaluated for their possible increased efficiency on the removal of aromatics from the water phase, compared to traditional technologies.
When is Steady-State Upscaling Valid?
Authors: Jonoud S. , Jackson M. D. 
Published: December 2007

Abstract
Steady-state upscaling techniques for multi-phase transport properties have been proposed as an alternative to dynamic methods because they are faster and simpler to implement: there is no need for fine grid simulation and the upscaled transport properties are not case dependant. However, although their speed and ease of implementation is attractive, it is still not clear under what circumstances the assumption of steady state is valid and whether the upscaled transport properties properly capture flow.
We have run numerical experiments on some simple geological systems, to investigate the validity of the capillary equilibrium limit (CEL) method, in which it is assumed that capillary forces dominate the distribution of fluids. The CEL method is likely to be valid at small length scales and low flow rates.
We begin by demonstrating that existing criteria are not sufficient to accurately specify the conditions under which the method is valid. Upscaling using steady-state methods outside this range can yield significant errors in predicted recovery. However, we are able to match upscaled and fine grid simulation results under a different range of conditions. We have derived a new set of criteria to specify the conditions under which the CEL method is valid, which are applicable to a variety of different geological heterogeneities including those in which capillary trapping occurs.
We find that the CEL method can be applied over length-scales of up to tens of meters for thinly laminated systems (i.e. high aspect ratios) and with low to near typical flow rates. Our results demonstrate that the CEL method can be used in the first step of a two-step upscaling process, to generate effective multi-phase transport properties quickly and cheaply which capture the impact of small-scale heterogeneities at the scale of a geological model grid-block.
Use of a Fiber Optic Pressure/Temperature Gauge in an Exploration Well to Minimize Formation Damage Potential and Reduce Costs During Production Testing
Authors: Bond Andy , Blount Curt , Kragas Tor , Mathias Steve 
Published: December 2007

Abstract
The addition of real-time, permanent, downhole pressure and temperature monitoring systems to completion design is often regarded as a "nice to have" that is difficult to economically justify. Management is hesitant to commit up-front capital for downhole surveillance systems whose value is uncertain and not easy to quantify and whose reliability in the past has sometimes been less than outstanding. However, in recent years the reliability of many conventional systems has improved and new, high-reliability alternative sensing technologies such as fiber optics have become available. In addition, the value of real-time downhole data in both production and reservoir management is becoming more and more recognized and demonstrated in case studies.
This paper discusses the installation, application, and value of a permanent fiber optic pressure and temperature gauge system installed in a sidetrack of an exploration well at Cape Starichkof, Alaska in June, 2003 (Fig. 1). Prior experience in the original completion and testing of this well suggested that significant formation damage might have been caused due to the lack of real-time pressure drawdown data during initial production well testing. Because of the importance of the real time data, a conventional electronic gauge was included in the completion design for redundancy. The gauges were installed and subsequently operated in this well to provide real time bottom-hole flowing pressures and temperatures. Challenges and unique aspects of the installation included survival of the gauge during multiple trips in and out of the hole and a splicing operation below the tubing hanger. Comparisons of data from the two gauges and the value of having the ability to obtain high resolution downhole shut-in buildup information during the multi-stage tests are discussed. Fiber optic gauge data proved invaluable in monitoring flowing pressures during initial well productivity tests and providing downhole pressure buildup data during shut-ins. The high speed, high resolution data stream from the fiber optic gauges allowed the well to be tested without significant damage to the formation and in a minimum time period.
Analysis of Imbibition in Mixed-Wet Rocks Using Pore-Scale Modeling
Authors: Behbahani Hassan , Blunt Martin J. 
Published: December 2007

Abstract
Counter-current imbibition is an important recovery mechanism during waterflooding in fractured reservoirs. While this may be a rapid and efficient recovery process in strongly water-wet systems, the vast majority of reservoirs show some mixed-wet or oil-wet characteristics. If the reservoir is mixed-wet, it is possible for some water to imbibe spontaneously, but the ultimate recovery is lower and the imbibition rate may be several orders of magnitude slower than for strongly water-wet rock.
We use quasi-static pore-scale network modeling as a tool to study the behavior of mixed-wet rocks and to predict relative permeability and capillary pressure. The model uses a topologically disordered network that represents the pore space of Berea sandstone. We adjust the distribution of contact angles at the pore scale to match previously publised experimental co-current waterflood recoveries and wettability indices on Berea. We then input the relative permeabilities and capillary pressures into a conventional grid-based code and simulate counter-current imbibition in one dimension. We make predictions, with no matching parameters, of the recovery as a function of time and compare the results with the experimental measurements. We are able to reproduce the observed dramatic increase in imbibition time as the system changes from being water-wet to mixed-wet. In a mixed-wet system spontaneous imbibition, where the capillary pressure is positive, is limited to a narrow saturation range where the water saturation is small. At these low saturations the water is poorly connected through the network in wetting layers and the water relative permeability is extremely low, leading to recovery rates tens to thousands of times slower than for water-wet media.
We present a semi-empirical equation to correlate imbibition recovery in mixed-wet rocks with different wettability states and for a wide range of viscosity ratios. We show that the recovery rate is proportional to the water mobility at the end of imbibition.
A Framework for History Matching Using Local Optimization in Streamline Defined Regions
Authors: Barthelemy Maud , Fenwick Darryl H. , Gautier Yann , Blunt Martin J. 
Published: December 2007

Abstract
We develop a general methodology for history matching that uses the method of local deformation and streamline-based simulation. We generate a geostatistical realization that can obey constraints at wells and other geological information. The history matching process consists in a chain of optimizations. First, streamlines are used to define regions of the field influencing each producer. In each step of the chain one single parameter is used to deform the reservoir description in each streamline-defined region independently. The optimum value of the deformation parameter that minimizes for each well the mismatch between observed and predicted data is found. Then, the reservoir description is updated and the streamline regions are re-defined. A new chain begins and the process continues.
We demonstrate that the objective function is an irregular, multiple valued function of the deformation parameters, making optimization using a gradient-based method difficult. We also define objective functions based on matching time moments of the production data. This approach does not eliminate the multiple-valued nature of the objective function.
We test the validity of the local deformation method on a simple case. We compare it with the global deformation method on this same case.
Effects of OBM Invasion on Irreducible Water Saturation: Mechanisms and Modifications of NMR Interpretation
Authors: Chen J. , Hirasaki G. J. , Flaum M. 
Published: December 2007

Abstract
In this study, the effects of synthetic oil base mud (OBM) surfactants (emulsifiers and oil-wetting agents) on wettability alteration, NMR response and irreducible water saturation (Swir) were systematically examined with Berea and limestone cores. Results show that the originally strongly water-wet Berea and limestone cores are altered to be intermediate-wet or oil-wet by OBM surfactants. As a result, Swir from NMR T2,cutoff model with the default assumption of water-wetness generally underestimates the measured value. The magnitude of underestimation depends on three parameters: the type of OBM surfactants, their concentration in the flushing fluid, and the flushing volume. The magnitude of underestimation correlates with the Amott-Harvey wettability index. These results suggest that the effects of OBM invasion on estimation of Swir can be minimized by controlling the volume of OBM invasion and the concentration of OBM surfactants.
The mechanisms of Swir underestimation and modifications of NMR interpretation when wettability alteration occurs were investigated. In the case of an oil-bearing zone at irreducible water saturation, OBM invasion does not significantly decrease the actual Swir, but changes the water and oil relaxation time distributions due to wettability alteration. This is visualized by the diffusion editing technique. When wettability alteration occurs (water-wet to intermediate-wet or oil-wet), a T2, cutoff value larger than the one based on water-wetness is needed because the irreducible water relaxes at a longer relaxation time. Correlation between this modified T2,cutoff value and the Amott-Harvey wettability index was found.