bluuebunny/crossref_metadata_2025_split huggingface dataset:
Drilling Salt Formations Offshore With Seawater Can Significantly Reduce Well Costs
Authors: Willson Stephen M. , Driscoll Peter M. , Judzis Arnis , Black Alan D. , Martin J. Wesley , Ehgartner Brian L. , Hinkebein Tom E. 
Published: December 2007

Summary
The rate of penetration (ROP) increases significantly if salt formations are drilled with undersaturated fluids. This is especially true when drilling riserless. Of primary concern is the amount of hole enlargement that will occur. However, if managed, then a step change in drilling performance and costs can be achieved.
This paper presents in detail the results of a comprehensive and large-scale laboratory testing program performed on outcrop salt samples that replicate drilling salt formations with undersaturated drilling fluids with flow rates of up to 1,000 gal/min (gpm). The laboratory testing program includes tests performed in a computerized tomographic (CT) scanner to map hole enlargement in real time, as well as variously sized borehole leaching tests with borehole diameters of up to 6 in. Flow rates are scaled to produce comparable levels of turbulence occurring in the field.
An analytical hole-enlargement prediction model is presented that incorporates the effects of ROP, pump rate, drill-fluid saturation, dissolving salt drill cuttings, and salt leaching from the borehole wall. This model accurately predicts to within 10% the measured hole enlargements produced in the scaled laboratory tests for a wide range of flow rates and fluid saturations.
Predictions of field performance are made, and the implications of the predicted hole geometry are discussed. Provided that high rates of penetration are realized, acceptable hole geometries will result, even when pumping seawater at flow rates of up to 1,600 gpm. A field application is described whereby the historical practice of drilling the last 200 ft of the 20-in. hole into salt using a saturated brine drilling fluid was discontinued in preference to the continued use of seawater. The competing influences of increasing rate of penetration and avoiding the cost of a sacrificial mud system, offset by the increased cost of cement, resulted in cost savings of U.S. $250,000 per well. Implemented in a multiwell subsalt development, cost savings of more than U.S. $1.5 million will be realized in the drilling program. Further applications of this technology are now being sought.
Horizontal Drilling and Openhole Gravel Packing with Oil-Based Fluids-An Industry Milestone
Authors: Wagner M. , Webb T. , Maharaj M. , Twynam A. , Green T. , Salamat G. , Parlar M. 
Published: December 2007

Summary
An increasing number of horizontal wells requiring sand control are being gravel packed, particularly in deepwater and/or subsea environments in which completion reliability is paramount because of the prohibitively high cost of remediation. Tophole sections in many of these wells are being drilled with oil-based (OB) fluids, with the common practice of switching to water-based fluids when the reservoir drilling starts. In the last several years, some operators started using OB drilling fluids in the reservoir section as well and gravel packed them with water-based fluids. In some cases, these practices required running predrilled liners in OB fluids and subsequently displacing to water-based fluids before running in hole with the sandface screens and gravel packing. In other instances, screens could be run in hole with OB fluids in the wellbore, and gravel packing could be performed with water-based fluids. In both cases, the presence of reactive shales and/or water-sensitive productive zones can introduce serious concern, in the event that carrier-fluid losses occur into the formation during gravel packing. Although a base-oil or diesel can be used as a carrier fluid, low density of the base oil limits such applications to low-pressure/depleted wells.
In this paper, we present a case history of the first successful application of drilling and completing in an all-oil environment, using a reversible OB reservoir-drilling fluid (RDF) (the filter cake of which reverses wettability from oil to water when exposed to an acidic fluid) and an OB gravel-packing fluid. The carrier fluid used in this application included a filter-cake cleanup solution in the aqueous internal phase of the OB carrier fluid, extending the application of simultaneous gravel-packing and cake-cleanup processes that have been successfully practiced in water-based-fluid environments to OB systems. The subject application was in a high-rate gas field located offshore Trinidad, with anticipated production rates in excess of 150 MM scf/D per well. Presented in the paper is the drilling and completion selection methodology based on extensive laboratory and yard testing, along with the details of the completion and recommendations for future applications based on lessons learned. A direct comparison of the all-oil drilling and completion process to water-based drilling and completion is also presented based on a case history from the same field.
The Shortcomings and Challenges of Metering–System Automation in the Petroleum Industry
Authors: Ogwo O. U. J. 
Published: December 2007

Summary
Since about 1990, the automation of flowmetering systems has been gaining momentum. During this time, operations have been simplified by flow-system automation, but the petroleum industry has been exposed to significant fiscal losses arising from "teething problems." This paper reviews the problems that are yet to be addressed by the automation industry, based on field experience over an extended period of time. The fiscal significance of these shortcomings is presented, and measures are suggested to correct the problems. It is expected that this work will prompt the automation industry to address the existing limitations of metering systems when designing future flow computers.
Oil-Viscosity Predictions From Low-Field NMR Measurements
Authors: Bryan J. , Kantzas A. , Bellehumeur C. 
Published: December 2007

Summary
Canada contains vast reserves of heavy oil and bitumen. Viscosity determination is key to the successful recovery of this oil, and low-field nuclear magnetic resonance (NMR) shows great potential as a tool for estimating this property. An NMR viscosity correlation previously had been developed that is valid for order-of-magnitude estimates over a wide range of viscosities and temperatures. This correlation was built phenomenologically, using experiments relating NMR spectra to viscosity. The present work details a more thorough investigation into oil viscosity and NMR, thus providing a theoretical justification for the proposed correlation. A novel tuning procedure is also presented, whereby the correlation is fitted using the Arrhenius relationship to improve the NMR viscosity estimates for single oils at multiple temperatures. Tuning allows for NMR to be potentially used in observation wells to monitor thermal enhanced oil recovery (EOR) projects or online to monitor the viscosity of produced-fluid streams as they cool.
The Potential Role of Passive Seismic Monitoring for Real-Time 4D Reservoir Characterization
Authors: Maxwell S. C. , Urbancic T. I. 
Published: December 2007

Summary
This paper details the application of passive seismic monitoring to image reservoir fracturing and deformation from the stage of an initial well completion to final field production. Instrumented oil fields with seismic arrays either permanently installed or temporarily deployed on wireline offer the possibility of imaging production activities in a real-time sense that complements other seismic reflection and engineering measurements. During the well-completion stage of development, real-time microseismic imaging offers the possibility of monitoring well stimulation. Fracture images may be used to optimize the fracture design and the net present value (NPV) of well production, as well as understand fracture complexity and the associated well-drainage pattern to target future well placement. During production stages, time-lapse microseismic imaging may be used for image deformation associated with fracturing or fracture reactivation from pressure or stress changes, strains in the overburden in fields with casing-deformation problems, and image fronts associated with secondary recovery. In this paper, several case studies are used to illustrate various potential applications, along with discussion of the potential limitations. The reservoir conditions necessary for the success ful application of the technology are presented along with a potential method to quantify the technical feasibility at a particular site.
Polymer Gels Formulated With a Combination of High-and Low-Molecular-Weight Polymers Provide Improved Performance for Water-Shutoff Treatments of Fractured Production Wells
Authors: Sydansk R. D. , Al-Dhafeeri A. M. , Xiong Y. , Seright R. S. 
Published: December 2007

SummaryA laboratory study has shown improved performance for fracture-problem water-shutoff polymer gels that are formulated with a combination of high-and low-molecular-weight (MW) polymers. These gels are intended for application to fractures or other high-permeability anomalies that are in direct contact with petroleum production wells. More specifically, we focused on evaluating the mechanical strength and improved performance of these water-shutoff gels for use when exceptionally large fracture apertures or large drawdown pressures are encountered. During our study, the gels were injected into laboratory-scale fractures while the gel was in a partially formed state. The flooding-experiment study involved the placement of partially formed chromium(III)carboxylate/acrylamide-polymer (CC/AP) gels in 1-to 4-mm (0.04-to 0.16-in.) apertures, by 2-ft-long × 1.5-in.-height fractures where the fracture walls were 700-md unfired Berea sandstone.During the injection of a 1.5% high-MW and 2.0% low-MW polymer-gel formulation, the partially formed gel fluid exhibited an effective viscosity of approximately 500 cp during placement in a 1-mm (0.04-in.) -aperture fracture, and the matured gel exhibited exceptionally good fracture-plugging characteristics. The gel withstood 52-psi total differential pressure across the fracture length (26-psi/ft pressure gradient) for 24 hours, while permitting no detectable brine flow through the gel-filled fracture. Subsequently, when the differential pressure was increased to 175 psi (88-psi/ft pressure gradient), the gel rendered a brine permeability-reduction factor in the fracture of 30,000. When placed in a 4-mm (0.16-in.)aperture fracture, a 25-psi/ft critical pressure gradient was required to render first and limited brine flow through the fracture containing gel of the same composition. After exceeding the critical pressure gradient, the stabilized permeability-reduction factor imparted by the gel to brine flow in the fracture was 260,000. When increasing the brine flow rate through a gel-containing 4-mm fracture from 500 to 8,000 cm3/hr (superficial velocities of 260 to 4,100 ft/d in the open fracture), the stabilized permeability-reduction factor decreased from 100,000 to 39,000.The high-and low-MW CC/AP gels exhibited disproportionate permeability-reduction (DPR) effects during oil and brine flow through gel-filled fractures. However, the gels of this study are probably better characterized as total-shutoff or sealing agents (not DPR agents) because of the large permeability reduction imparted to oil flow through the gel-filled fractures.
Oil/Water Separation Experience From a Large Oil Field
Authors: Kokal Sunil , Al-Ghamdi Abdullah 
Published: December 2007

Summary
This paper discusses challenges related to emulsions that have been encountered in a large Saudi Arabian field. The field produces from several different reservoirs with a range of fluid properties. These properties provide an interesting case of operational challenges in oil/water separation, including increased incidents of shorting in the separator, tripping of equipment, and increased demulsifier consumption.
This paper presents the results of a comprehensive study that was initiated to understand the main causes of emulsion formation in the field and ways to optimize oil/water separation. The effects of several recommendations that were implemented by operations engineering in the field were evaluated. These include the conversion of a two-phase separator into a three-phase separator, splitting of the demulsifier injection between offshore producing platforms and onshore wet-crude handling facilities, and field trials with promising chemicals. The demulsifier costs have been reduced by more than 50% by the implementation of retrofitting and proper demulsifier-injection strategies. The results presented in the paper provide invaluable operational experience, and many lessons learned are applicable to any crude-oil-treating facility.
The Penetration of Coiled Tubing With Residual Bend in Extended-Reach Wells
Authors: Zheng Andrew , Adnan Sarmad 
Published: December 2007

SummaryResidual bend exists in every coiled tubing string. When the coiled tubing is placed inside a wellbore, its initial configuration is not straight but has a certain residual bend. This paper's objective is to explain how this residual bend in coiled tubing affects its extended reach.This paper presents a new modeling technique to account for the effect of residual bend on coiled-tubing posthelical buckling behavior and maximum penetration. The initial configuration of the coiled tubing is assumed to be the form of a helix along the wellbore. By using the energy method, a set of solutions is obtained for the helix configuration and the radial contact force under the conditions of applied axial force and initial residual bend. These solutions are used to analyze axial load transfer and extended-reach capability of coiled tubing on horizontal wells. It is shown that in a horizontal well, with a relatively small residual bend radius, the existence of residual bend significantly reduces the maximum depth the coiled tubing can reach. Results of this work can be used to enhance job design for extended-reach applications.
Phase Behavior of Athabasca Vacuum Bottoms + n-Alkane Mixtures
Authors: Zou Xiangyang , Zhang Xiaohui , Shaw John M. 
Published: December 2007

Summary
The phase behavior of Athabasca vacuum bottoms (ABVB), a 798.15+K (525+°C) boiling fraction comprising 32 wt% pentane asphaltenes +pentane mixtures, is elucidated using x-ray transmission tomography. These pseudobinary mixtures are models for the development of novel heavy-oil/bitumen production and refining processes. Depending on their overall composition, these mixtures are shown to exhibit three- and four-phase equilibria, including both expected (L1L2V) and unexpected (L2L3V) phase behavior separated by a small L1L2L3V zone. These multiphase equilibria provide challenges in production environments, where miscible flooding is typically desired, but afford new opportunities for the development of separation technologies in refining. Example phase diagrams are presented (pressure-temperature at constant composition and pressure-composition at constant temperature), which focus on the bubble pressure region where multiphase regions arise. Limited phase equilibria data sets for ABVB+heptane, decane, and dodecane are also presented so that trends for ABVB+alkane mixtures with the size of the alkane diluent can be explored. It is expected that these phase diagrams will provide useful insights to heavy-oil producers and refiners, in addition to providing a benchmark for testing phase-behavior models for these and related complex hydrocarbon mixtures.
Worldwide Field Applications of a Polymeric Gel System for Conformance Applications
Authors: Eoff L. , Dalrymple D. , Everett D. , Vasquez J. 
Published: December 2007

Summary
Water production becomes a major problem as hydrocarbon-producing fields mature. Higher levels of water production result in increased levels of corrosion and scale, increased load on fluid-handling facilities, increased environmental concerns, and eventually well shut-in (with associated workover costs). Consequently, producing zones are often abandoned in an attempt to avoid water contact, even when the intervals still retain large volumes of recoverable hydrocarbons. Many polymer systems have been applied over the years to control undesired water production from hydrocarbon wells, with varying degrees of success.
For approximately eight years, a polymer gel system based on an acrylamide/t-butyl acrylate copolymer (PAtBA) crosslinked with polyethyleneimine (PEI) has been used successfully for various water shutoff applications. This article describes results from a sampling of over 200 jobs performed throughout the world, including the average results from more than 90 jobs performed in one geographic location alone. In addition to "standard" matrix treatments, results will be shown for other types of treatment, including a design to plug annular communication and a combination of sealant and temporary gel in an openhole horizontal completion. In addition, laboratory data pertaining to work aimed at increasing the temperature limit of the system will be presented. The upper placement temperature of the system originally was ~260°F. Data presented in this article indicates the development of a retarder system that allows the upper placement temperature to be raised to at least 350°F.
Applying Radial Acoustic Amplitude Signals To Predict Intervals of Sand-Stuck Tubing
Authors: Siems G. , Boudreaux S. 
Published: December 2007

Summary
The reuse of existing well bores is a cost-saving technique used by oil and gas producers in mature fields. This process usually requires the removal of tubing and packers to allow the well to be deepened or sidetracked. The tubing removal process is often made difficult when the tubing is stuck inside the casing because of mechanical binding or binding caused by dehydrated mud or sand in the annulus between the tubing and casing. Conventional direct and indirect methods of finding the stuck point(s) along an interval of tubing, such as free-point indicator tools or acoustic attenuation measurements, have proved themselves useful in finding the point(s) where the tubing is stuck. However, when the sticking is caused by uncompacted sand that has entered the annular space between the tubing and casing, these conventional stuck-pipe indication methods are often inconclusive or misleading.
Technological advancements in the design and development of slim, 11116-in. outside diameter (OD), radial cement bond tools allow the application of a new measurement to find sand-stuck tubing intervals. These tools provide up to six independent, closely spaced acoustic attenuation measurements distributed radially around the tool body. When the recording operation is performed inside the tubing, the increased sensitivity of these tools to sound attenuation, as compared with conventional omnidirectional amplitude signals, allows sand intervals along the outside of the tubing to be distinguished from intervals where little or no sand is present. This information is used to select the best depth to sever or back-off the free tubing in order to reduce the interval length and expense associated with the washover process required to remove the remaining tubing from the wellbore.
An overview of conventional stuck-pipe recovery techniques is provided here, along with a brief explanation of applicable acoustic technology. A case study of a South Louisiana well is presented to demonstrate the application and illustrate the cost savings which can be gained by use of this very new technology.
Real-Time Field Surveillance and Well Services Management in a Large Mature Onshore Field: Case Study
Authors: Ormerod L. , Sardoff H. , Wilkinson J. , Erlendson B. , Cox B. , Stephenson G. 
Published: December 2007

Summary
This paper describes the planning for, implementation of and results generated by a real-time field surveillance and well services management system, as it was deployed in an onshore mature field in California, USA. The motivation behind the deployment of this system was simultaneously to improve efficiency and reduce operating costs in this large field with over 1,000 wells.
The paper will describe how the business processes and supporting workflows were defined. This is an essential step before any technology can be deployed. The challenges of data management included not only the automatic handling of very large quantities of real-time data, but also the management of inventory and the integration of field level data with corporate level data. Historical data had to be brought into, and made compatible with the new system. The technologies required for this project included the software systems and the integration of these with remoteintelligent field sensors and data transmission systems.
The impact of the system has been material to the performance of the asset. Examples will be given of tangible improvements in performance across the disciplines of surveillance, production engineering, and well services. One critical factor to the successful deployment of this system includes the organizational changes needed to support the new working practices enabled by the system. The paper will discuss the required change management programs.
The success of this project has clearly established that a "smart" solution integrating intelligent remote devices, communications networks and workflow management software can be successfully deployed on large, mature fields. The deployment process to achieve this has been assimilated and is now being reproduced in many other similar fields across North America. The paper will indicate some of the areas where this combination of technology and supporting change management will be expanded in the future.
Fault‐Tolerant Software
Authors: Lyu Michael R. , Cai Xia 
Published: December 2007

AbstractFault tolerance is the survival attribute of a system or component to continue operating as required despite the manifestation of hardware or software faults. Fault‐tolerant software delivers continuous service complying with the relevant specification in the presence of faults typically by employing either single‐version software techniques or multiple‐version software techniques. We address four key perspectives for fault‐tolerant software: historical background, techniques, modeling schemes, and applications.
Regression Analysis
Authors: Weisberg Sanford 
Published: December 2007

AbstractIn statistics, regression is the study of the changes in the distribution of a response as the values of predictors of it are varied. Regression models are used in virtually all areas of science and represent fundamental tools in understanding data.Simple and multiple linear regression methodology are the basic tools of regression analysis. These methods can be used with only minimal assumptions and are described in this article. Linear regression is not always appropriate, for example, if the response is a category or a count. For these cases, specialized methods have been developed. More recent developments in regression include nonparametric, semiparametric approaches, among others.
Visual Software Engineering
Authors: Zhang Kang , Kong Jun , Cao Jiannong 
Published: December 2007

AbstractGraphical notations, such as data flow diagrams and class diagrams, are widely used in software design and development. While being easy to understand and convenient to use, these graphical notations are not amendable to automated verification and transformation. This article provides an overview on visual assistance in software engineering, and it focuses on a graph grammar approach to visual software modeling, architectural design, and evolution. A graph grammar enables a high‐level abstraction of the general organization of a class of software architectures, and it forms a basis for formal analysis and transformations. In this approach, software verification is performed through a syntax analyzer. Architectural evolution is achieved by applying predefined transformation rules.