bluuebunny/crossref_metadata_2025_split huggingface dataset:
Permeability Predictions Based on Two-Dimensional Pore Space Images
Authors: Jurgawczynski Mathieu , Lock Peter A. , Jing X. D. , Zimmerman Robert W. 
Published: December 2007

Abstract
A model is developed that allows accurate prediction of the permeability of a core sample of sedimentary rock, based solely on two-dimensional image analysis of its pore structure. The only required input data are the areas and perimeters of the pores observed in, for example, an SEM image. The hydraulic radius approximation is used to estimate the individual pore conductances. Prior to this, stereological corrections are used to convert apparent pore geometries, and various hydraulic corrections are applied to account for converging–diverging flow paths. These various corrections are the principal and crucial differences between our approach and previous methods based on two-dimensional images. Finally, Kirkpatrick's effective medium approximation is used to find the effective value of the hydraulic conductances of the individual pores.
The method has been applied to several data sets, including consolidated North Sea reservoir sandstones, outcrop sandstones, outcrop carbonates, and carbonates from Middle East oil and gas fields. The permeabilities of this entire data set range from 0.5-1377 mD, which covers a significant portion of the range of permeabilities that are relevant in reservoir engineering. In 80% of the cases, the permeabilities predicted by our method are within a factor of two of the measured values, and the predictions are within a factor of three in over 90% of the cases. The method requires minimal data manipulation and computation when compared to approaches that require three-dimensional imaging and/or full solution of the Navier-Stokes equations, and is much more accurate than primitive empirical methods such as the Kozeny-Carman equation.
Aside from giving insight into the influence of pore structure on permeability, our method offers the potential of permitting permeability predictions to be made using drill cuttings, in situations where it is not possible to recover intact core. Another possible future application is to use downhole borehole imaging technology to provide an image with the appropriate resolution, thereby allowing in situ permeability estimation, without the need for core samples.
Enabling Technologies for Drill-In Sand Screen Liners
Authors: Coronado Martin P. , Pickle Brad R. , O'Malley Edward J. 
Published: December 2007

Abstract
Following successful field applications of solid-liner drill-in systems, efforts now focus on drill-in sand screen liners. This paper will discuss enabling technologies to meet the unique challenges of drill-in sand screen liners.
Rotating the screen liner to drive the bit may damage screens, so a drilling motor at the bottom of the liner must be utilized. Also, conveying fluid to drive the motor and remove debris is required. Using a conventional inner circulating string inside the screen liner may be prohibitive due to the addition of sufficient weight which may significantly limit horizontal and highly deviated well angles and length. The screen liners therefore must be able to contain pressure when drilling to allow circulation through the bit, and subsequent wellbore inflow during production. Additionally, the screen's filtration media must also be protected from possible plugging with solids during drilling.
This paper addresses a new technology that temporarily blocks flow through the screens during drilling/reaming to provide a pressure-tight circulation path through the liner to the motor, eliminating the need for an inner circulation string. Once drilling is completed and the liner is in place, the screen joints are simultaneously opened using hydraulic pressure applied within the liner, and the well is ready to be put on production. Temporarily closing off the screen joints also has application for simultaneously setting hydraulically set open-hole packers remotely without an inner circulating string.
The paper also discusses a time- and temperature-sensitive protective film applied to the screens during fabrication to prevent fluid egress into the filtration media until the film dissolves. Sufficient time for dissolution is designed into the film to allow the liner to be drilled into place while protecting the screen's filtration media from possible plugging during drilling/reaming.
Qualification testing of these technologies are discussed, along with additional applications for this technology where utilizing a temporarily closed screen system has advantages.
Microseismic Monitoring Quality-Control (QC) Reports as an Interpretative Tool for Nonspecialists
Authors: Zimmer U. , Maxwell S. , Waltman C. , Warpinski N. 
Published: December 2007

Abstract
In the oilfield industry microseismic monitoring is widely applied to determine induced fracture network geometry and stress changes in reservoirs. The basic result is usually a map of the distribution of the microseismic events describing the area influenced by injection/production of reservoir fluids, e.g hydraulic fracturing. As every microearthquake event, i.e. ‘dot’ on the map, is processed individually, it has its own level of location accuracy. To prevent any misinterpretations based on events with low accuracy, Quality-Control (QC-) reports can provide important information regarding location accuracy and other attributes which help in the overall interpretation of the maps, in addition to the standard event location. However, much of the information that is needed to assess the quality of the data is very specialized and technical, so that the figures presented in the QC- reports often appear complicated and are not easy to read for the non-specialist. By introducing easy-to-read figures that summarize the essential information, these reports have become more useful to the occasional user.
Fire Protection In The Petroleum Industry
Authors: Dawoud Sam 
Published: December 2007

Abstract
The risk of fire is present during all stages and operations of the petroleum industry, whether during exploration and production (E&P) both in onshore and offshore installations or during refining/processing or transportation, storage or during dispensing to the end user. All petroleum products from crude to final products produce vapor that is being mixed with air creating the potential for ignitable mixture. While petroleum products have different rates of releasing vapors to the environment, they all share the risk of starting a fire when an ignition source is introduced to the mixture. Fires involving hydrocarbons can take several shapes from pool fires to fire balls and jet fires. Due to the severity and Heat Release Rate (HRR) of Hydrocarbon fires (which may result in catastrophic consequences), fire prevention, protection and mitigation measures are considered to be of utmost importance/most advanced in relation to same measures in other industries.
Completion Design, Installation, and Performance—Cannonball Field, Offshore Trinidad
Authors: Healy J. C. , Powers J. T. , Maharaj M. , Ramlogan M. 
Published: December 2007

Abstract
The Cannonball field is a one Tcf gas condensate development offshore Trinidad producing at an initial rate in excess of 800 MMcf/D from three wells. The completion design selected was 7⅝ inch production tubing with an open-hole gravel pack (OHGP). The initial well (CAN01) has produced at an initial rate of 320 MMcf/D. The calculated deliverability of this well is 415 MMcf/D. This paper discusses the completion basis of design, detailed engineering assurance of the design, qualification of critical engineered equipment, and actual results.
Oil Production Gains for Mature Steamflooded Oil Fields Using Propane as a Steam Additive and a Novel Smart Horizontal Producer
Authors: Rivero Jose A. , Mamora Daulat D. 
Published: December 2007

AbstractWe have conducted an experimental scaled model study to investigate the feasibility of two methods aimed at improving oil production from mature heavy oil fields. The first method involved the use of propane as a steam additive (propane:steam mass ratio of 4:100 was used in the study). The second involved the use of a novel well system consisting of a vertical injector and a smart horizontal producer. To minimize steam over-ride, the smart horizontal producer was divided into three sections, the section furthest from the injector being opened only after steam had broken through in the first two sections. The 16 in. × 16 in. × 5.6 in. physical model was scaled to present conditions in the San Ardo field in California and crude oil from the same field was used for the tests. The sides of the model consisted of 0.75 inch thick Teflon sheets to minimize heat loss, while the top and bottom consisted of 0.125 inch aluminum sheets to maximize heat conduction to the over- and under-burden. The physical model was placed in a pressure jacket containing nitrogen that provided an overburden differential pressure of about 20-40 psi during the runs. Superheated steam at 190-210°C was injected at 48 cm3/min (cold water equivalent) while maintaining the flowing pressures in the production wells at 50 psig. Liquid samples from each producer in the model were collected and treated to break emulsion and analyzed to determine water and oil volumes.Main results of the study may be summarized as follows. First, for the vertical well system, addition of propane accelerated oil production by 53% and increased ultimate oil recovery by 7% of original oil-in-place (OOIP) when compared to pure steam injection. Second, use of the smart horizontal well system increased ultimate oil recovery to 49% OOIP compared to that obtained with the vertical well system (42% OOIP).
Fluid Flow in a Fractured Reservoir Using a Geomechanically-Constrained Fault Zone Damage Model for Reservoir Simulation
Authors: Paul Pijush , Zoback Mark , Hennings Peter 
Published: December 2007

Abstract
Secondary fractures and faults associated with larger, reservoir scale faults affect both permeability and permeability anisotropy and hence may play an important role in controlling the production behavior of a faulted reservoir. It is well known from geologic studies that there is a concentration of secondary fractures and faults in a damage zone adjacent to larger faults. Because there is usually inadequate data to incorporate damage zone fractures and faults into reservoir simulation models, in this study we utilize the principles of dynamic rupture propagation from earthquake seismology to predict the nature of fractured/damage zones associated with reservoir scale faults. We include geomechanical constraints in our reservoir model and propose a workflow to more routinely incorporate damage zones into reservoir simulation models. The model we propose calculates the extent of the damage zone along the fault plane by estimating the stress perturbation associated with dynamic rupture propagation. Fractures created by the stress pulse accompanying rupture propagation enhance permeability along reservoir scale faults in both the horizontal and vertical directions. We calibrate our modeling with observations from a number of studies and show that dynamic rupture propagation gives a reasonable first order approximation of damage zones in terms of permeability and permeability anisotropy in order to be incorporated into reservoir simulators.
A Unique Methodology for Evaluation of Multi-Fractured Wells in Stacked-Pay Reservoirs Using Commingled Production and Rate Transient Analysis
Authors: Manrique J. F. , Poe B. D. 
Published: December 2007

AbstractWe present a unique methodology designed for evaluation and optimization of multi-fractured wells in stacked pay reservoirs using commingled production. The specialized diagnostic procedures are based on rate-transient analyses, and uses historical production data (rates and cumulative) and the results from production logs to; 1) determine the flow rates for each individual stage in a multi-fractured well, 2) apply rate-transient solutions that use rate-normalized-pressures and superposition-in-time to evaluate response accordingly to the fracture flow periods, 3) estimate reservoir and fracture effective properties and 4) evaluate the completion efficiency.The field examples presented in the paper, demonstrates the application of the production optimization methodology in practice. The approach permits quantification of the reservoir and fracture properties on a layer-by-layer, or frac stage-by-stage, by evaluating the production well history as an extended drawdown and in combination with direct physical measurements of the flow rates and flowing pressures. Such a unique procedure provides a great advantage since parameters such as; permeability (keffective), fracture length (Χf,effective), conductivity (kfbf)effective and dimensionless conductivity (CfD or FCD) can now be obtained for each individual fracture stage. In addition to the effective properties, the methodology allows for estimation of the drainage area and skin for unfractured zones and fracture half-length and conductivity for the hydraulically fractured reservoir layers.The methodology is applicable to all types of reservoirs, however most of our field experience has taken place in the evaluation and optimization of stacked-pay tight permeability reservoirs and low conductivity fractures where other forms of conventional reservoir characterization techniques are technically difficult and/or cost-prohibitive.The optimization methodology allows evaluation of the fracture performance efficiency in terms of the reservoir response and contribution, identification of non-fractured zones, bypassed zones (zones without a frac), under-designed fractures, low conductivity values (and steps for improving it), re-fracturing candidates and identification of remaining well potential deliverability.
Cased-Hole Cleaning: Do Annular Velocity, Annular Coverage and Contact Time Equal Mud Removal?
Authors: Darring Michael T. , Foxenberg William E. , Niehaus R. Brad , Stein Tim W. , Miller David M. 
Published: December 2007

Abstract
Mud-to-brine displacement efficiency can be difficult to quantify. Metrics to determine the success or failure of the displacement operation have traditionally been based upon the clarity of the completion brine that follows the spacers, the interface volumes of mud and completion brine, a visual determination of the cleanliness of the drillpipe pulled from the hole, and the time and materials required to filter the fluid. Despite their widespread use, however, these factors may not adequately characterize the quality of displacements in critical wells. Opportunities for improvement are largely affected by how well the displacement process can be understood. This can be difficult with the few direct and indirect parameters used to evaluate mud-to-brine displacement quality.
The authors initiated a study of samples captured during displacement circulations to examine the effects of spacer properties, volumes, pump rate, and chemical concentration on mud removal. The laboratory analyses inspected return samples of mud, spacers, and displacing fluids from 27 cased-hole wellbore displacements of oil-based and synthetic-based drilling mud in the Gulf of Mexico.
Results from this study suggest that criteria such as annular coverage, contact time, and annular velocity of the wash spacer(s), which have become the basis for most displacement programs, although critical to overall efficiency, are not the primary agents of mud removal during a wellbore cleanup.
Data correlations between the volume of mud observed in the samples analyzed and certain spacer characteristics suggest that cased-hole cleaning, when defined as mud removal, is a function of the size of a viscous spacer relative to hole size. This observation should simplify the displacement design process.
Potential for Oil Shale Development in the United States
Authors: Biglarbigi Khosrow , Dammer Anton , Cusimano Jeremy , Mohan Hitesh 
Published: December 2007

Abstract
The development of domestic oil shale resources has regained significant attention in the past few years. Several factors have contributed to this, including high oil prices, emerging recovery technologies, increasing world demand for liquid hydrocarbons, and the continued decline in U.S. conventional oil production. In recent years, several initiatives have been taken by the Federal Government and the private sector to encourage the development of a domestic oil shale industry.
The United States has vast deposits of oil shale – Nearly 2.0 trillion barrels across the eastern and western states. The development of this massive resource, however, is constrained by a number of key factors including, but to limited to: (1) resource access, (2) technology, (3) economics, (4) environmental and regulatory issues, and (5) infrastructure.
A comprehensive analysis has been completed to address the development of this resource. The analysis is based on a representative sample (about 70 Billion Barrels) of Western Oil shale resource divided among multiple development "tracts." Four (4) production technologies were also considered. These technologies included emerging in-situ processes as well as traditional mining with surface retorting technology. Each development "tract" was screened for the potential application of each recovery technology. A detailed economic evaluation was conducted for each "tract" and the selected technology with consideration for development under alternative economics, environmental, technology, and socioeconomic options. The analysis indicated that with a concerted effort from industry, local, state, and Federal governments, the shale oil production potential could reach 2.4 million barrels per day (MMBbl/d) with substantial benefits to the local and national economy.
Methods for Incorporating Costs, Pricing, Gas Shrinkage and Transport Tariffs, NGL and Inert Revenues, and Working Interest in Gas Plants and LNG Projects into Reserves Estimates
Authors: McLaughlin John , Gouge Brad 
Published: December 2007

Abstract
This paper reviews some of the ways that pricing and costs; gas composition and usage; entitlement interests; project approvals; and reserves aggregation affect reserve estimates and methods for incorporating these parameters into reserve studies. Techniques are discussed from the perspective of both SEC (Securities and Exchange Commission) and SPE/WPC/AAPG/SPEE (Society of Petroleum Engineers; World Petroleum Council; American Association of Petroleum Geologists; Society of Petroleum Evaluation Engineers) reserve definitions under the Petroleum Resources Management System (SPE-PRMS). In the cases where the definitions are not explicit as to processes for incorporating the above-ground parameters, the authors briefly discuss issues to consider such as past guidance by the SEC and industry norms for interpretations of the definitions.
In general, the SEC and SPE/WPC/AAPG/SPEE agree in how to account for many of the commercial and non-reservoir parameters. Where the two sets of definitions most markedly diverge are: Application of commodity pricesTreatment of revenue and/or volumes of non-hydrocarbonsInclusion of fuel gas as reserves or as projected "sales gas"Inclusion of hydrocarbons recovered by unconventional means (i.e. mining and processing)Criteria used for differentiating gas re-injection versus injection and storageConsideration for the appropriate level of aggregation in summarizing reserves portfolios
SEC and SPE-PRMS definitions tend to agree on methodology and practice in the areas of: Sales reference points and pressure basisBooking dry versus wet gasInclusion of coal bed methane (CBM)Calculation of entitlement net interests for production sharing agreementsApproval levels required for a project to be classified as proved
The purpose of this paper is not to pass judgment on either the SEC or SPE-PRMS definitions but rather to provide a summary of the methods used to account for some of the more common commercial and non-reservoir related aspects that arise in reserve estimation.
Swellable Packers for Well Fracturing and Stimulation
Authors: Yakeley S. , Foster T. , Laflin W. 
Published: December 2007

Abstract
Reactive element packers (REPs), sometimes referred to as swelling packers or self-energizing packers, offer a simple solution for multiple-zone open-hole completions. These packers are run into the well and begin to swell when they come into contact with various wellbore fluids, with the typical fluids of choice being water- or oil-based fluids. As the packers swell, they seal off the annulus between the liner/casing and the open-hole wellbore to provide isolation between zones with different pressures, or to simply shut off flow in the annulus and prevent migration of fines along the wellbore.
As REP technology makes its mark in zonal isolation, application of the technology for fracturing and well stimulation is beginning to be explored. REPs used for frac'ing and stimulation offer a simplified method of breaking the desired zone into smaller sections without adding the cost and complexity that may result from using the traditional cement and perforating methods.
This paper will discuss this new application for REPs. Functionality will be discussed, as will possible advantages and disadvantages of using the REP for well stimulation and fracturing. Key packer parameters will be reviewed to help demystify a seemingly infinite number of sizing possibilities. Then, initial testing to verify and validate the packer for this application will be discussed. Finally, this extensive test data will then be shown to validate a complex mathematical prediction model used to determine the REP's capabilities.
Monitoring SAGD Steam Injection Using Microseismicity and Tiltmeters
Authors: Maxwell S. C. , Du J. , Shemeta J. , Zimmer U. , Boroumand N. , Griffin L. G. 
Published: December 2007

Abstract
A combination of microseismic and surface deformation monitoring with an array of tiltmeters was used to monitor the warm-up phase of a SAGD well pair. A sequence of microseismic events was recorded with signal characteristics suggesting deformation associated with thermal expansion of the wellbore, in addition to events apparently associated with induced fracturing in the reservoir. Integration of the microseismic data with volumetric strain, inverted from the measured surface deformation, indicates a discrete deforming region near the toe of the well. The volumetric strain also shows another region near the heel of the well, although the area is too far from the microseismic observation well for any associated microseismicity to be recorded. The central portion of the well pair did not have significant deformation, indicating poor steam conformance during this warm-up phase. A comparison of the temporal response of the microseismic deformation with the surface uplift, suggests a lag between periods of accelerated seismic deformation followed by an associated period of accelerated uplift a few days later. This timing suggests the creation of a fracture network and related seismic deformation, which then fills with steam and starts to expand over a period of a few days. In a related paper9, stress changes associated with the volumetric strain are used to examine potential geomechanical failure zones that match the observed locations of microseisms. Together the volumetric strain, computed stress changes, and failure zones could be used to calibrate a geomechanically linked reservoir simulator.