bluuebunny/crossref_metadata_2025_split huggingface dataset:
Novel Approach to Quantifying Deepwater Laminated Sequences Using Integrated Evaluation of LWD Real-Time Shear, Porosity, Azimuthal Density and High-Resolution Propagation Resistivity
Authors: Yared Katerina , Pelorosso Mauro , Altintutar Ismail , Buster Derek , Manuel Ela , Doyle James , Russell Charles 
Published: February 2011

Abstract
Accurate reserve volume determination is crucial in the early stages of a project since planned subsurface capacity is dependent on reserve expectations. The fundamental method of calculating reserves uses bulk formation resistivity and bulk porosity to determine water saturation. This approach cannot accurately quantify reserves in laminated sand-shale sequences where the sensor resolution is insufficient to characterize the fine laminae. A tensor petrophysical model can determine laminar shale volume and laminar sand-fraction conductivities reducing the problem to a single dispersed shaly sand model. Combining this with sand-fraction porosities can lead to accurate reserve quantification.
Identification and quantification of hydrocarbons within low-contrast, low-resistivity formations can be difficult when using conventional log data. This is primarily due to the presence of laminar shale and the inherent vertical resolution of measurements acquired by wireline and logging while drilling (LWD).
A Gulf of Mexico deepwater example is used to demonstrate this novel approach in quantifying hydrocarbons in laminated sand-shale sequences. Real-time shear slowness is used in conjunction with LWD triple-combo data to identify potentially productive low-contrast reservoirs. Then, advanced resistivity post processing extracts the vertical component of resistivity, enabling calculation of sand-fraction resistivity. Sand-fraction resistivity, combined with normalized sand-fraction porosity, yields sand-fraction water saturation. Shale volume, porosity and water saturation cut-offs determine the net hydrocarbon volume. The LWD-calculated hydrocarbon volumes in place are then compared to results obtained from a wireline logging suite.
This approach demonstrates that the use of conventional empirically derived bulk-volume porosity and saturation methods in laminated sand-shale sequence formations results in underestimation of the reservoir producibility and hydrocarbon reserves. Vertical resistivity, derived from LWD-acquired propagation resistivity and electrical anisotropy sensitivity, can be used to quantify reserves in these environments.
Integrating Core Data and Wireline Geochemical Data for Formation Evaluation and Characterization of Shale Gas Reservoirs
Authors: Quirein John , Witkowsky Jim , Truax Jerome , Galford Jim , Spain David , Odumosu Tobi 
Published: February 2011

Abstract
When core data, such as mineralogy, porosity, total organic carbon, and elastic properties, are available from a large multiwell database, it is possible to extract meaningful statistical relationships between the data. These relationships can then be applied in other wells with limited or no core data. X-ray diffraction (XRD) mineralogical data is unique in that it can readily be transformed to synthetic wireline geochemical elemental data, such as the weight fractions, aluminum, silicon, and calcium. This transformation establishes a relationship between the mineralogical data and the synthetic wireline geochemical data, which can be applied to "real wireline" geochemical data to select an appropriate set of minerals for prediction from the wireline geochemical data. Statistical optimization based approaches are generally used to perform this prediction of mineralogy from wireline data.
The most difficult aspect of predicting mineralogy from wireline geochemical data is the selection of the proper mineral model. The proposed approach assists the analyst in the selection of the proper model. In addition, this paper shows how core XRD mineralogical data can be used to establish constraints between the predicted mineralogy, such as percent clay fraction illite greater than 60%. An accurate prediction of mineralogy from wireline geochemical data can be transformed to an accurate prediction of grain density, enabling an accurate prediction of total porosity (corrected for kerogen effects).
The workflow described in this paper provides an effective approach for establishing and predicting mineralogy, grain density, and porosity from wireline geochemical data. This paper presents results for a Haynesville shale example. Finally, the proposed approach helps to maximize the value of the core data for shale gas plays.
Borehole Quality Design and Practices to Maximize Drill Rate Performance
Authors: Dupriest F. E. , Elks W. C. , Ottesen S. , Pastusek P. E. , Zook J. R. , Aphale C. R. 
Published: February 2011

Abstract
In 2005 the operator implemented a workflow that ensured drilling performance limiters were identified, redesigned, and extended continuously. The use of mechanical specific energy surveillance to address bit limiters and dysfunction has previously been published. The purpose of this paper is to discuss additional practices that have been developed to extend the non-bit performance limiters, particularly those related to borehole quality.
There have been over 40 non-bit performance limiters identified and redesigned globally. While these are diverse, those with the greatest global impact were found to be tied directly to borehole quality. Consequently, in 2008 the performance management workflow was modified to increase awareness of borehole quality as a performance limiter. The result was that acceptable borehole quality became defined as that which would not limit footage per day. Quality is now redesigned to the "economic limit of performance" in the given interval. The economic limit of performance is a significantly higher standard than the common industry objective for borehole quality, which is to achieve low trouble time and run casing successfully.
The average drilling footage per day drilled by the 23 operations that have been active since the performance management process was implemented has improved by about 63%. Instantaneous drill rates have typically increased 100-300%. Advances in bit and non-bit limiters appear to have contributed equally, and the majority of the gain in non-bit limiters has come from improved borehole quality. Other gains have come from related limiters, such as an increased understanding of the manner in which cuttings transport and tripping operations are controlled by borehole quality.
The paper discusses the technical models that are used to understand the major borehole limiters, the engineering design and the real-time practices that have been developed, as well as the field results.
Statistical Analysis of Safety Incidents and the Implications of Imperfect Reporting
Authors: Jablonowski C. J. 
Published: February 2011

Abstract
Quantitative models of safety incidence allow managers to connect specific elements of the safety management system to outcomes. The results provide evidence that can be used to allocate resources to those incident prevention efforts that yield the highest returns in terms of avoided incidents. However, conventional methods of statistical and regression analysis of safety incidents do not account for the fact that not all incidents are reported. By relying on conventional methods, it is possible that resources are being misallocated, and that the industry is missing opportunities for improvement. This paper specifies regression models that explicitly account for imperfect reporting. The methods are applied to an operator provided data set of safety incidents. While all of the results of the case study are not generalizable, they clearly demonstrate the incremental value of a more complete model of safety incidence and reporting behavior.
The Potential Applications in Heavy Oil EOR with the Nanoparticle and Surfactant Stabilized Solvent-Based Emulsion
Authors: Qiu Fangda 
Published: February 2011

Abstract
This study presents the results of nano-particle and surfactant-stabilized solvent-based emulsion bench test studies under laboratory conditions that investigate the recovery mechanisms of chemical flooding in a heavy oil reservoir. In the study, bench tests, including the phase behavior test, rheology studies and interfacial tension measurement are performed and reported for the optimum selecting method for the nano-emulsion which is going to be applied in the coreflooding experiments. Specifically, nanoemulsion systems have been mixed with Alaska North Slope West Sak heavy oil with 16 API°, which was dewatered in the laboratory condition, to investigate the rheology change during this process.
The experiment results suggest that the potential application of this kind of emulsion flooding is a promising EOR process for some heavy oil reservoirs in Alaska, Canada and Venezuela after primary production. Heavy oil lacks mobility under reservoir conditions and is not suitable for the application of the thermal recovery method because of environmental issues or technical problems.
The idea of nano-particle application in an EOR area has been recently raised by researchers who are interested in its feature- reaction catalysis-which could reduce in situ oil viscosity and generate emulsion without surfactant. Also, the nano-particle stabilized emulsions can long-distance drive oil in the reservoir, since the nano-particle size is 2-4 times smaller than the pore throat.
In conclusion, the nano-emulsion can be an effective enhancement option for an oil recovery method in a heavy oil reservoir which is technically sensitive to the thermal recovery method.
New Method to Diagnose and Improve Shale Gas Completions
Authors: Palmer Ian , Moschovidis Zissis 
Published: February 2011

Abstract
The method assumes a quasi-uniform volume of enhanced permeability during and after multi-stage fracturing of a horizontal well, and quantifies both injection permeability (by predicting shear failure and matching a microseismic pattern), and production permeability (by using rate-transient analysis to match gas rate). This leads to two different permeability-based diagnostics (production permeability and loss of injection permeability), which can be correlated with fracture treatment parameters (such as pump rate, spacing of frac segments, fracture fluid cleanup, damage by additives, and proppant design). The injection and production permeabilities illustrative of several case studies appear to be consistent with other tight gas determinations. Production permeabilities can be hundreds of times greater than matrix permeabilities, but only a very small fraction of injection permeability. The fracture-dominated injection permeability is large (tens of md) and the corresponding injection porosity is small &lt;0.01%. The challenge is to retain more of the injection permeability (eg, by less damage or better proppant design). Injection permeability and porosity are generally consistent with properties of vertical fracture networks. Fracture spacing results suggest the shale can be fractured on a finer scale than revealed by microseismic data. Fracture widths appear to be consistent with widths quoted by Reiss. The method provides a new avenue for characterizing stimulation volumes (via injection and production permeabilities), and for diagnosing the effectiveness of a stimulation volume. Correlations between injection permeability loss and fracture treatment parameters should lead to improvements in volume stimulations. The perm-based diagnosis is a new approach to improve well stimulations, and is applicable to all shale gas plays.
Complete Solution for Transient Heat Transport in Porous Media, Following Lauwerier's Concept
Authors: Barends F. B. 
Published: February 2011

Abstract
The state of knowledge of heat transport in porous media lacks practical closed form solutions valid for simulating the complete process, including storage, convection, conduction, dispersion and thermal bleeding. In this paper, these various processes are explored and validation by analytical tools is extensively elaborated, adopting the concept of Lauwerier 1955, a jump temperature rise condition at the inlet and incompressible porous media. Much emphasis is put on convection and thermal bleeding, i.e. the heat transfer in adjacent formations. Convenient solutions for plane and radial situations are derived applying Boltzmann and Laplace transformation techniques. Excellent match is found with existing partial solutions and results of numerical codes (COMSOL). Comprehensive insight is obtained for the heating-up period (Danckwerts’ condition). As is shown in this paper, the analytical solutions are easily handled by MAPLE for quick assessment of specific effects and/or sensitivity aspects and in particular for disregarding processes of lesser importance when tuning detailed numerical modelling or interpreting exploitation data for the incorporation of thermal bleeding in an efficient way.
Modeling Facility Expansion Options under Uncertainty
Authors: Jablonowski C. , Ramachandran H. , Lasdon L. 
Published: February 2011

Abstract
During the concept comparison and selection phase of capital projects, decision makers compare development options and select one option to carry forward to detailed engineering. This effort is often complicated by uncertainty in one or more of the critical inputs. Therefore, project teams are tasked to investigate how different assumptions about the uncertainty influence optimal decisions. In cases where initial investment decisions are difficult and/or costly to change, the analysis of facility flexibility increases in importance. In its simplest form, the goal is to find the optimal balance of initial capacity and the allocation of space and other resources for future expansion. This paper reports the results of a research project where the authors develop an integrated asset model for a hypothetical deepwater asset and use the model to investigate various aspects of facility design under uncertainty. The method produces estimates for the optimal initial capacity, the likelihood of expansion, the expected size of expansion, and the willingness to pay for the option to expand. The approach is systematic, the model solves quickly and thus enables a wide scope of uncertainty analysis. The graphical output is intuitive and facilitates communication between the facility engineer, subsurface engineers, and management.
Volumetric Fracture Modeling Approach (VFMA): Incorporating Microseismic Data in the Simulation of Shale Gas Reservoirs
Authors: Harikesavanallur Arvind , Deimbacher Franz , Crick Martin , Zhang Xu , Forster Peter 
Published: February 2011

Abstract
The growth of hydraulically induced fractures can be very complex; this is especially true when fractures are initiated from horizontal wells that are drilled in naturally-fractured reservoirs (such as shale gas) where the hydraulic fracturing process leads to swarms of fractures forming complex three dimensional (3D) fracture networks. Traditional modeling methods, suitable for simple (penny-shaped) fracture geometries, oversimplify the 3D extent of a fracture swarm and fail to capture the real extent of the drainage volume, inevitably leading to unreliable production forecasts.
It is possible to estimate the extent of the stimulated volume for each stage of a hydraulic fracturing job from microseismic data. The Volumetric Fracture Modeling Approach (VFMA) then models the fracture network as a 3D volume with fracture properties described by variations of dual porosity parameters. The VFMA was successfully applied to modeling a horizontal well in the Barnett Shale with multiple hydraulic fractures. An automated history-matching procedure was used to estimate the productive volume from the initially stimulated volume.
The VFMA is especially suitable for multi-well or full-field simulation where other fracture modeling methods may not work due to gridding or simulator performance constraints. Using the VFMA, it is possible to obtain the real extent i.e. the drainage volume, of complex fracture networks in shale gas reservoirs. Understanding the drainage volume allows for well spacing optimization, which in turn determines the total well count, and ultimately the cost of field development.
How 24/7 Real-Time Surveillance Increases ESP Run Life and Uptime
Authors: Camilleri L. , MacDonald J. 
Published: February 2011

Abstract
This paper explains the development and implementation in the Schlumberger artificial lift real-time surveillance center of a workflow to track ESP alarms from their initial identification through their classification to the analysis of their root-cause. The workflow uses a QHSE database with Web access to enable collaboration between the surveillance center and field locations throughout Europe and Africa. Of more than 700 alarms which were substantiated over an 18 month period, over one third were classified as "critical", i.e. if no actions were taken, an Electric Submersible Pump (ESP) failure could potentially ensue. As such, real-time surveillance was seen to contribute to an increase in ESP run life, firstly, by preventing the ESP from being misoperated and experiencing excessive stress, and secondly, by using the alarm classification as the basis for service quality reviews to promptly identify remedial action items.
Improved Oil Recovery Methods: Applicability Screening and Potential Evaluation
Authors: Surguchev Leonid M. , Reich Eva-Maria , Berenblyum Roman A. , Schipanov Anton A. 
Published: February 2011

Abstract
Screening and analytical methods are often used for fast preliminary evaluations of various EOR scenarios. Screening is typically performed using real field experience and knowledge data bases, which summarize application of EOR methods to similar fields. Analytical methods are limited by simplified representation of the reservoir and EOR processes; however solutions are exact and not affected by the numerical dispersion. Often an analytical solution is used to verify numerical results. The advantages of analytical methods are in their speed and relatively small amount of data necessary to estimate the recovery of a certain EOR technique. The approach is viable and practical when a large number of reservoirs are to be screened for EOR applicability or when a decision over a new asset with limited field data is to be made.
A three-level approach to selection of EOR strategies is suggested. First the screening model allows for a fast first-order screening of key EOR applicability methods at given reservoir conditions. The applicability assessment is based on ranges for critical reservoir parameters, using a multi-criterion model and distribution functions. Than the model for oil recovery factor estimation based on the statistical data from projects carried out world wide is applied. Finally, analytical methods could be used for quantitative analysis and production profile calculations for main oil recovery methods: Depletion, Waterflooding, Cyclic Waterflooding, Polymer, Surfactant and Polymer/Surfactant flooding, Immiscible and Miscible Gas (CO2, N2, HC) flooding, Steamflooding and Immiscible WAG injection.
A wide range of reservoir parameters and computed results enable the user to perform rapid and comprehensive reservoir analyses as well as sensitivity studies. A unique feature of the developed program is its capability to handle a series of scenarios in only one single run. This tool can be compared with a “compass” helping reservoir and petroleum engineers to identify and successfully implement EOR/IOR methods at their fields.
Analytical Models to Select an Effective Saline Reservoir for CO2 Storage
Authors: Gupta Abhishek K. , Bryant Steven L. 
Published: February 2011

Abstract
Geological sequestration of CO2 in deep saline reservoirs is one of the ways to reduce its continuous emission into the atmosphere to mitigate the greenhouse effect. The selection among prospective saline reservoirs can be expedited by developing some analytical correlations which can be used in place of reservoir simulation study for each and every saline reservoir. Such correlations can reduce the cost and time for commissioning a geological site for CO2 sequestration.
The efficiency of a CO2 sequestration operation depends on risks associated with storage, several of which can be estimated by i) the time the plume takes to reach the top seal; ii) maximum lateral extent of the plume and iii) the percentage of mobile CO2 present at any time. A database has been created from a large number of compositional reservoir simulations for different reservoir parameters including porosity, permeability, permeability anisotropy, reservoir depth, thickness, dip and perforation interval. We use a dimensionless ratio of gravity to viscous forces to formulate different correlations with the factors that contribute to sequestration efficiency. We update a previously reported correlation for time to hit the top seal and develop a new correlation for the maximum lateral extent of the plume using a newly created database for different reservoir and operating properties. A correlation for percentage of mobile CO2 during the buoyancy dominated post injection period is also developed.
We find that normalizing the maximum lateral extent by a characteristic length yields a reasonable correlation with the gravity number. This characteristic length is determined as the maximum lateral distance traveled by plume at any time assuming constant sand face velocity. The correlation confirms that low gravity number allows the plume to travel laterally due to high viscous forces while a high gravity number allows it to move faster in vertical direction due to strong gravity forces. The change in mobile CO2 after injection ends also correlates well with gravity number. We normalize the change in mobile CO2 fraction (or, equivalently, the change in trapped CO2 fraction) after the end of injection by a characteristic CO2 saturation. The characteristic saturation is obtained by considering the volume filled by vertical, buoyancy-driven movement through the area associated with the maximum plume extent.
The correlations reproduce almost all simulation results within a factor of two, and this is adequate for rapid ranking or screening of prospective storage reservoirs.
Transient Well Indices: A Link between Analytical Solution Accuracy and Coarse Grid Efficiency
Authors: Archer Rosalind A. 
Published: February 2011

Abstract
A new numerically derived transient well index is presented. This well index is an elegant approach that combines and compares pressure predictions from coarse grid finite difference models and analytical solutions. The ratio of the drawdowns from each solution approach is used to modify the conventional Peaceman well index to produce a new transient well index. The new well index is shown to also be accurate for constant pressure production (i.e. for rate transient behavior) and performs well for a variety of well types, e.g. wells with wellbore storage, partial penetration of hydraulic fractures. Local grid refinements around the well do not produce the same level of accuracy. The new well index can be presented in terms of an equivalent well radius. In late time this becomes the Peaceman well index. The transient behavior of the equivalent well radius is shown to be universal when it is plotted against a dimensionless time function which includes a scaling for the grid size. The new transient well index approach means that coarse grid models can accurately reproduce pressure transient behavior making them a useful tool for numerical well test interpretation.