bluuebunny/crossref_metadata_2025_split huggingface dataset:
History Matching Using Probabilistic Approach in a Distributed Computing Environment
Authors: Yadav S. , Srinivasan S. , Bryant S. L. , Barrera A. 
Published: December 2007

Abstract
The focus of the paper is to present a novel methodology for delineating multiple reservoir domains, for the purpose of history matching in a distributed computing environment. A fully probabilistic approach to perturb permeability within the delineated zones is implemented. The combination of robust schemes for identifying reservoir zones and distributed computing significantly increase the accuracy and efficiency of the probabilistic approach.
The information pertaining to the permeability variations in the reservoir that is contained in dynamic data is calibrated in terms of a deformation parameter rD. This information is merged with the prior geologic information in order to generate permeability models consistent with the observed dynamic data as well as the prior geology. The relationship between dynamic response data and reservoir attributes may vary in different regions of the reservoir due to spatial variations in reservoir attributes, well configuration, flow constrains etc. The probabilistic approach then has to account for multiple rD values in different regions of the reservoir.
In order to delineate reservoir domains that can be characterized with different rD parameters, principal component analysis (PCA) of the Hessian matrix has been done. The Hessian matrix summarizes the sensitivity of the objective function at a given step of the history matching to model parameters. The eigenvectors obtained during the PCA are suitably scaled and appropriate grid block volume cut-offs are defined such that the resultant domains are neither too large (which increases interactions between domains) nor too small (implying ineffective history matching).
Since the domain delineation process yields zones that are least correlated with each other, each rD parameter can be optimized independently and simultaneously using individual nodes of a cluster of computers. Upon convergence, the perturbed regions are put together and the history match is verified. The proposed approach results in a set of independent tasks of equal magnitude and thus is particularly suited for distributed computing.
A Mechanistic Study of Naphthenate Scale Formation
Authors: Shepherd A. G. , Thomson G. B. , Westacott R. , Sorbie K. S. , Neville A. 
Published: December 2007

Abstract
Static bottles tests have been conducted on model naphthenic acid solutions with the objective of studying the mechanisms of naphthenate "scale" formation. Various experimental sensitivities were analysed such as initial pH, cation type and concentration in the aqueous phase, naphthenic acid type and concentration in the oil phase. Data has been obtained for the deposits formed from sodium, calcium and barium rich aqueous phases and their combinations. Trends in precipitate mass as well as the composition of the solid deposits obtained from X-Ray diffraction (XRD) and electron microscopy/energy dispersive x-ray (ESEM-EDX) are presented. The effects of cations on bulk and surface properties such as viscosity, emulsion stability and interfacial tension are also shown. These results contribute to the understanding of naphthenate deposition mechanisms under lab conditions.
Stimulation Challenges and Solutions in Complex Carbonate Reservo
Authors: Kumar P. S. , Gisbergen S. V. , Harris J. M. , Al-Naabi A. M. , Murshidi A. , Brady M. E. , Ferdiansyah E. , El-Banbi A. , Al Harthy S. 
Published: December 2007

Abstract
This paper details the challenges of stimulation in one of the fields in North Oman. The field is a mature, heavily faulted and fractured carbonate reservoir on water flood where acid stimulation carries an inherently high risk of inducing several fold increases in water production. Acid placement challenges are immense as the fracture networks impart massive permeability contrasts and are most often the principal conduits for "premature" injection water breakthrough. We present field data of acid stimulation treatments on cased hole, oil producers as well as open-hole horizontal injectors using a novel self-diverting acid system. This fluid has been recently applied in other reservoirs but to date, none of these applications have held the same magnitude of challenges and barriers to successful implementation of stimulation treatments. We present numerous field studies which identify self-diverting acid systems as a key solution, together with best practices in candidate selection (through reservoir logging evaluation) and coiled tubing placement methodology, in providing consistent improvement in net hydrocarbon well productivity and enhanced injection profile for reservoir management. In addition we present results of a new surfactant based self-diverting system and compare the results to conventional polymer based treatments in this field. The results are indicative of a further improvement in success ratio of acidizing treatments. Similar methodology and fluid systems are applicable in other complex fractured reservoirs where acid placement and minimizing water production present the principal challenges. Moreover, as reservoir management becomes an ever-increasing concern, we present a treatment methodology to enhance productivity, reduce water cut and optimise reservoir sweep, all of which reduce the overall lifting costs.
After-Closure Analysis to Determine Formation Permeability, Reservoir Pressure, and Residual Fracture Properties
Authors: Soliman M. Y. , Craig D. , Bartko K. , Rahim Z. , Adams D. 
Published: December 2007

Abstract
A minifrac test is usually performed before a fracture stimulation treatment to calculate formation and fracture properties. Recently the analysis techniques were extended to the after-closure period. The after-closure data are analyzed to calculate formation permeability and reservoir pressure.
Technology developers have hypothesized the existence of either pseudo-radial or linear flow behavior during the after-closure region. Identifying the presence of the flowing regime is an awkward process at best. The roots of the linear flow equations are different from those of the pseudo-radial flow equations. Many tests do not follow either flow regime.
In this paper, we have created a general approach for analysis of after-closure pressure decline data. Because the determination of the flow regime and type of fracture depends only on time and monitored pressure, the analysis may even be performed in real time. The technique determines whether sufficient data have been obtained to perform a reliable analysis. The calculated parameters would be used to update the fracture design and, in turn, for performing the fracture treatment.
The new technique is simpler and more generalized than what currently exists. The technique initially determines whether analyzable data exist. It shows that three flow regimes may dominate the after-closure region, depending on the reservoir properties and residual fracture conductivity. The technique presented not only determines the type of regime, and consequently, the type of residual fracture, it also determines the formation permeability and reservoir pressure.
There is no reason to restrict the application of this test to minifrac test analysis. We believe the approach is also applicable to analysis of data after performing a fracture stimulation treatment. A numerical simulator was used to model the pumping and closure process and to validate the new approach.
The paper also presents a detailed discussion and analysis of several field cases, demonstrating the various flow regimes and, ultimately, the validity of the developed technique.
Calculating Derivatives for History Matching in Reservoir Simulators
Authors: Rodrigues J. R. P. 
Published: December 2007

AbstractThe use of gradient-based optimization methods in automatic history matching requires that the reservoir simulator provides the necessary derivative information in the most efficient way. The implementation of these techniques in existing complex simulators is a difficult task, however. This paper describes the implementation of the forward and adjoint methods for derivative calculation in a full-featured adaptive implicit black-oil simulator. To show how the derivative calculation methods can be used even outside the framework of standard optimization algorithms, a new algorithm for automatic history matching, based on the truncated singular value decomposition, is proposed. Application to simple synthetic cases shows promising results.
Multiscale Process Coupling by Adaptive Fractional Stepping: An In-Situ Combustion Model
Authors: Younis R. , Gerritsen M. 
Published: December 2007

Abstract
We propose a time-stepping methodology for in-situ combustion simulation that is designed specifically to accommodate the various physical sub-processes, including conduction, advection, and kinetics, that have widely varying time-scales. The approach combines operator splitting with fractional time-stepping. The method is applied to a scaled form of the governing equations. We derived seven independent scaling parameters in the in-situ combustion process, representing ratios of heat capacity, mass transfer and heats of reaction.
We provide a proof of concept for one particular splitting and fractional step method that we found to be intuitive. In each time-step of this scheme, we solve the pressure equation semi-implicitly. Conservative accumulation treatment is assured by elimination at the Jacobian level. This is followed by an explicit solve for temperature, where a second elimination is performed to de-couple accumulation terms from the remaining concentration equations. The concentration equations are then integrated in a fractional- step, additive-splitting fashion. This means that reactions are separated numerically from the concentration advection- reaction equations. The overall solution for concentrations is obtained by performing a sequence of solves for reactions alternating with pure advection. A local fractional time-step size for either sub-process is introduced, and may be varied according to the local physics. Finally the global time-step solution is composed in an accurate fashion out of the sub-process solves.
To test the method a couple of test problems were designed for which the parameters are given in full detail so that it can be used for inter-code comparisons.
Binary Decomposition of Three-Term Seismic Inversion Data to Estimate Recoverable Hydrocarbon Volumes
Authors: Engelmark F. 
Published: December 2007

Abstract
Three-term seismic inversion volumes can define key reservoir properties such as porosity and water saturation that together define the hydrocarbon pore volume. The problem is that the vertical resolution of the elastic data is limited to, at best, approximately 10 m. That means the inversion volumes actually represent elastic properties of a net-to-gross (N/G) with unknown porosity and saturation in the net.
The binary decomposition is described by a model that shows how the elastic data can be decomposed into the properties of the reservoir rock, typically sand, and properties of the non-reservoir rock, typically shale. Given a production scenario, the recoverable hydrocarbon volumes can be estimated directly from the seismic traces through the process of inversion, creation of support data, binary decomposition, hydrocarbon pore volume estimation, and seismic trace volume sampling.
Fluid Transfer Mechanism Using Geochemistry in Shallow Oil Zones of Bahrain Oil Field
Authors: Murty C. R. K. , Zubari H. K. , Beeunas M. A. , McCaffrey M. , Thompson K. F. 
Published: December 2007

Abstract
Geochemical data of oil integrated with geological and engineering data have contributed to an understanding of the mechanism and relative timing of hydrocarbon emplacement in shallow oil zones (Rubble, Ostracod & Magma) of Bahrain's Awali oil field. These zones contain heavy as well as light oil. It is observed that the different oil types reside in different reservoir compartments. To efficiently develop and produce from these reservoirs, it is required to know the current distribution of the oil types and whether they result from different charging histories (gradations developed during initial or late stage migration) and or post-emplacement alteration (i.e. water washing, biodegradation, gas stripping, gravity segregation or de-asphalting).
The primary objective of the study was to determine the vertical and lateral continuity of the reservoir intervals to geographically identify areas for development drilling and EOR processes. A geochemical study involving an advanced gas chromatography technique was used which included: (a) comparison of abundance of "inter-paraffin peaks" between the different oil samples, (b) determination of the magnitude of the compositional differences between the oil "Star Diagrams" and "Cluster Diagrams", and (c) "Slope Factor Analysis" where the relationship between molar concentration and molecular weight (carbon number) are compared between the oils.
The Geochemical evaluation provided compositional data that helped to: Characterize the difference between the oils.Verify reservoir compartment-talization.Reveal the level of biodegradation, charging fluid type and relative charge histories for the different fluid types.Identify the geographical distribution of the different fluid types and their relation to potential migration pathways (e.g. faults).
In addition to providing information concerning the lateral continuity within specific reservoir intervals and vertical continuity between intervals, the geochemical data also indicate three charging events with oils of differing thermal maturity: Primary: Charges of extremely immature oil were introduced along a nearly linear path which traverses the field from SE to NW. These lines could be the major fault (N-S) and fractures providing initial migration paths.Secondary: Oils of increasing maturity (mixtures of light & heavy oil) were introduced progressively, as the basin subsided and the oil source matured. It is possible that the light liquids condensed from gas at the sites where they presently occur, the oils acting as a stripping liquid.Tertiary: (Emplacement of highly mature oil). This process has occurred predominantly in the Mauddud oil bearing formation, produced primarily close to the perimeter of the field.
History Matching of Heavy-Oil Production for Comparing New Approaches to Generating Reservoir Property Distributions, West Coalinga Field, California
Authors: Brame S. E. , Castle J. W. , Fawumi O. K. , Falta R. W. 
Published: December 2007

Abstract
Reservoir simulation of steam injection into heavy oil sands of West Coalinga Field in California has been conducted to assess suitability of different permeability distributions generated from geological and fractal modeling processes. Permeability distributions in each model were derived by integrating stratigraphically controlled models with core data provided by Chevron Production Company. Three distinct distributions were generated for each lithologic group: facies tract, facies group, and a fractal distribution of the facies group. The grid design is based on stratigraphic architecture of depositional facies. Construction of these models involved application of advanced analytical property-distribution methods conditioned to continuous outcrop control for improved reservoir characterization.
Numerical simulation of steam injection into three adjacent 5 spot well configurations was used to assess suitability of each model. Injection and production histories of wells in the study area were simulated, including shutdowns and the occasional conversion of production wells to steam injection wells. The framework provided by the facies groups yielded a more realistic representation of reservoir conditions than facies tracts, which is revealed by a comparison of history-matching results. Permeability distributions obtained using the fractal model predict the high degree of heterogeneity within reservoir sands of West Coalinga Field. Modeling results indicate that predictions of oil production are strongly influenced by the geologic framework and by the boundary conditions.
Improved predictions of interwell reservoir heterogeneity have the potential to increase productivity and to reduce recovery cost for California's heavy oil sands, which contain several billion barrels of reserves in the San Joaquin Valley.
Reservoir Rock Typing in a Giant Carbonate
Authors: Varavur S. , Shebl H. , Salman S. M. , Shibasaki T. , Dabbouk C. 
Published: December 2007

Abstract
Lithofacies classifications are a purely geological grouping of reservoir rocks, which have similar texture, grain size, sorting etc. Each lithofacies indicates a certain depositional environment with a distribution trend and dimension. Petrophysical groups are classified by Porosity, Permeability, Capillary Pressure and Pore throat size distribution. A Rock Type combines both these classifications by linking petrophysical properties and lithofacies as part of the reservoir rock type definition. It has been previously shown that the static rock types are not always representative of multi-phase flow behavior in the reservoir.
In this paper, we will present evolution of the rock types scheme within ZADCO. We discuss criteria used to define reservoir rock types in the current scheme and its limitations. The objective of the proposed rock type scheme is to address shortcomings identified with the current one in use and is based on the following criteria: Each Rock Type can be characterized by similar depositional and diagenetic environment■Each rock type has a typical and unique set of Pore Throat Size Distribution curves.■Each rock type has similar set of Capillary Pressure/Relative Permeability curves at a given wettability.■Porosity/Permeability overlap is minimal between different rock types.■Rock types can be predicted with satisfactory accuracy using logs in uncored wells.■Spatial 3D distribution of the rock types is predictable within a well-defined geological framework.
Use of Genetic Algorithm to Predict Minimum Miscibility Pressure (MMP) between Flue Gases and Oil in Design of Flue Gas Injection Project
Authors: Emera M. K. , Sarma H. K. 
Published: December 2007

Abstract
There is an increasing global awareness of the detrimental effects of industrial flue gases on the environment. As a consequence, much emphasis is being placed to harness flue gases that contain high CO2 concentrations and sequester them in suitable geological formations. A plausible means of sequestrating flue gases is to inject them into petroleum reservoirs while also enhancing oil recovery. An a priori understanding of the pressure at which various flue gas components, notably CO2, become miscible with reservoir fluids is critical to the design and implementation of a flue gas injection project.
A new genetic algorithm (GA)-based correlation has been developed to estimate the flue gas-oil MMP. In developing this correlation, the GA software developed in our earlier work has been modified to account for various component gases in the flue gas stream. The correlation estimates the MMP as a function of the injected gas solvency in the oil. The solvency, in turn, is related to critical properties of the injected gas. The correlation has been successfully validated against published experimental data and several correlations in the literature. It yielded the best match with an average error of 4.7% and a standard deviation of 6.3%, followed by Sebastian et al. correlation with 13.1% error and 22.0% standard deviation and Alston et al. correlation with 14.1% error and 43.2% standard deviation.
An advantage of the GA-based correlation over other correlations is that it can be used for gas mixtures with higher N2 concentrations (tested up to 20 mole%) and with non-CO2 component concentrations of H2S, N2, SOx, O2, and C1-C4 up to 78 mole% with a higher accuracy. Equally important, it could be a useful tool when experimental data are not available and/or when developing an optimal and economical laboratory program to estimate the flue gas-oil MMP.
Integrated Reservoir Studies Optimize Hydraulic Fracturing and Post-Frac Well Performance: Case Studies in Saudi Arabian Gas Sandstones
Authors: Raba'a A. S. , Rahim Z. 
Published: December 2007

Proposal
This paper presents a methodology for an integrated reservoir study to identify different facies in the reservoir, select perforations interval and type of hydraulic fracture, understand pre- and post-fracture reservoir performance, and optimize fracturing treatments and reservoir development. The target formation is mainly from a Permian eolian ‘Unayzah-A gas bearing sandstone reservoir which is highly heterogeneous and poorly consolidated that requires a systematic and integrated assessment prior to its development.
Integrated reservoir studies utilizing engineering and petrophysical data showed the complexity and heterogeneity of the ‘Unayzah-A reservoir. The reservoir constitutes of clay mineral (illite) and hence it is highly susceptible to formation damage associated with drilling fluids. In order to remove damage, control sand production, and improve productivity, all gas wells are routinely fracture stimulated employing screen or screenless completion.
This paper provides a summary of the reservoir and fracture treatments focusing particularly on the fracture design, execution, fracture modeling, and post-treatment production analysis from the recently completed wells. A comprehensive data set of logs, pre- and post-fracture pressure buildup tests (PBU's), drill stem tests (barefoot and cased hole DST), and detailed fracture modeling are presented to demonstrate the fracture performance in this complex eolian dune reservoir environment.
Estimation and interpretation of reservoir pressures, fracture geometry, and transient tests from these wells indicate possible water-zones compartmentalization, reservoir continuity, and depletion as primary drive mechanisms.
This paper shows that understanding reservoir quality and characteristics, using focused reservoir studies, leads to successful completion results and optimum development. The study identifies the dominant flow unit, eliminates unnecessary perforation intervals, determines stimulation treatment type and size and optimizes cost for overall field development.