bluuebunny/crossref_metadata_2025_split huggingface dataset:
Assessment and Diagnosis of Inorganic-Scaling Potential Using Near-Infrared Technology for Effective Treatment
Authors: Ohen Henry A. , Williams Lee E. , Lynn Jack D. , Ali Liaqat 
Published: December 2007

SummaryInorganic scaling is a predominant formation-damage mechanism in most producing and injection wells worldwide. Scales are deposited from oilfield brines when there is a disturbance in ther-modynamic and chemical equilibrium. The degree of supersaturation caused by the disturbance in equilibrium can be increased to result in scaling by changes in fluid composition through adverse mixing and by changes in temperature and pressure.Although a few cases have been reported of nonwater-producing oil wells that produced scales, typically oilfield scaling accompanies water production. Scaling problems during well development and supplemental fluid injection are primarily caused by mixing of two incompatible fluids, whereas production-related scaling is typically controlled by pressure and temperature. Acid or any common solvent cannot easily remove some types of scales like barium sulfate (BaSO4), which readily incorporates radioactive radium in its structure.Therefore detection and prevention is critical wherever any precipitation or coprecipitation that includes BaSO4 may be taking place. As severity of scaling is controlled by temperature, pressure, and composition, the key to the detection, prevention, and effective treatment is a methodology to determine at what conditions in the reservoir or at what point in the well the scales are precipitated and deposited, and also to determine the type of scale. This is important because sometimes scales can be forming at a point in the wellbore without showing up at either the surface or at the sandface.Near-infrared (NIR) technology has been used extensively in detecting the organic scales such as asphaltene deposits. To the best of our knowledge, this study presents the first extensive use of NIR technology to diagnose inorganic-scaling problems.This paper presents several examples in which NIR technology has been used to detect the onset of inorganic scale as a function of pressure depletion at reservoir temperature for water from different fields. We also show how the NIR technology has been used to determine the effectiveness of various commercial inhibitors at reservoir conditions. We also present further screening of the inhibitors (selected on the basis of results of NIR tests) to determine their effective use in the field and the design of the inhibitor treatment for the producing wells.
Scale Control Within the North Sea Chalk/Limestone Reservoirs—The Challenge of Understanding and Optimizing Chemical-Placement Methods and Retention Mechanisms: Laboratory to Field
Authors: Jordan Myles M. , Sjursaether Karsten , Collins Ian R. 
Published: December 2007

SummaryThe scale-control challenges for two North Sea carbonate reservoirs are reviewed in this paper. While carbonate reservoirs are not the largest source of hydrocarbons within the North Sea, they are very significant on a global basis.The mechanism of scale-inhibitor chemical retention observed for phosphonate, polymer, and vinyl sulfonate copolymer (VS-Co) inhibitors on carbonate-reservoir substrates is outlined. Chemical placement represents the most significant technical challenge when performing scale-inhibitor squeeze treatments into fractured chalk reservoirs. Examples from more than 50 field treatments applied in reservoirs E and V, in which both phosphonate and VS-Co chemicals have been deployed, are used to illustrate the difference in chemical retention observed in laboratory evaluations. The laboratory studies demonstrated clear potential for significant extension in treatment lifetime by changing from a phos-phonate to a VS-Co-based scale inhibitor. The selection and qualification of chemical-placement systems for deployment of inhibitors in fractured carbonate reservoirs are also outlined. To this end, novel technologies to enhance conventional scale-inhibitor-chemical placement are vital to economic success during waterflood projects.
Stabilizing Wellbores in Unconsolidated, Clay-Laden Formations
Authors: D. Nguyen Philip , Dusterhoft Ron G. , Ali Syed A. , Lockman Russell R. 
Published: December 2007

Summary
This article presents results of laboratory and field testing regarding the effectiveness of an improved, one-component, low-viscosity resin-consolidation system. The system is designed to stabilize or strengthen the unconsolidated formation sand surrounding a wellbore and to overcome the effects of cyclic loading, while minimizing reduction of original permeability. Treatment-fluid volumes, overflush fluid, and the chemical composition of the consolidation material were found to directly impact the consolidation performance and the retained permeability of the treated formation sand. The treatment renders formation fines immobile so that migration and plugging do not occur.
This study determined that application of a consolidation material containing a specific solvent chemistry for clay-laden sands resulted in excellent strengths, even at high clay contents. This finding indicates that the consolidation material was drawn onto the mineral surfaces, resulting in minimal loss in effective porosity. Scanning electron micrographs of the consolidated-core material clearly revealed the entrapment of fines as the consolidation material formed a thin film on the mineral surfaces, causing little damage to the porosity and permeability of the formation.
Results of field testing indicate that the consolidation treatment effectively stopped the production of formation sand and fines while maintaining the production of the wells at desirable flow rates. The technique provides a very attractive alternative to conventional sand-control completions in lower quality reservoirs, as well as an effective through-tubing completion alternative.
Ramey's Wellbore Heat Transmission Revisited
Authors: Hagoort Jacques 
Published: December 2007

Summary
In this work we assess Ramey's classic method for the calculation of temperatures in injection and production wells. We show that Ramey's method is an excellent approximation, except for an early transient period in which the calculated temperatures are significantly overestimated. We present a simple graphical correlation to estimate the length of this early transient period. We further demonstrate that Ramey's procedure for the estimation of overall heat-transfer coefficients holds good only for large values of the Fourier dimensionless time. Finally, we illustrate the results of this work by an example calculation of wellhead temperature in a flowing oil well.
Resistivity Modeling of Array Laterolog Tools: An Application in an Offshore Norway Clastic Reservoir
Authors: Galli M. T. , Gonfalini M. , Mele M. , Belík P. , Faivre O. , Jammes L. , Litman A. 
Published: December 2007

Summary
Resistivity logs, while used extensively in the oil industry for the determination of water-saturation profiles and, consequently, for the quantification of hydrocarbon originally in place (HOIP), are strongly affected by environmental effects such as borehole, shoulder-bed resistivity contrasts, mud-filtrate invasion, dipping beds, and electrical anisotropy. It is well known by log interpreters that the combination of the different effects may strongly affect the estimation of hydrocarbon in place and hydrocarbon reserves. This paper highlights the strong reduction of the uncertainties in watersaturation determination and, consequently, the petrophysical characterization of the reservoir achieved by applying the appropriate 2D resistivity-modeling and -inversion techniques to two wells of the Norwegian offshore area. Both wells were drilled in a sandstone reservoir, with some thin-bedded intervals, and affected by the presence of anomalous invasion profiles.
Well Surveillance with a Permanent Downhole Multiphase Flowmeter
Authors: Webster M. , Richardson S. , Gabard-Cuoq C. , Fitzgerald J. B. , Stephenson K. E. 
Published: December 2007

Summary
Flow rate and fluid type (phase) are two of the most fundamental parameters needed to characterize well performance. Traditional methods of estimating these parameters, particularly for real-time detection and diagnosis of production anomalies, have been limited by sampling frequency and data quality. This paper presents field-test results of a new type of downhole multiphase flowmeter, which confirm the value of permanent downhole metering. The meter contains only three sensors but is capable of direct multiphase-flow-rate and cut measurements without slip models, even in highly deviated, recirculating flow. The physics basis and flow-loop tests are discussed.
Lessons Learned From Using Viscoelastic Surfactants in Well Stimulation
Authors: Nasr-El-Din Hisham A. , Samuel Mathew 
Published: December 2007

SummaryViscoelastic surfactant systems are used in the industry for several applications. Initially, the application was focused on low-friction and solids-suspension (fracturing and CT-cleanout) characteristics of the fluid. In the last 4 years, the application of viscoelastic surfactants was extended to acid-based systems for carbonate stimulation. These surfactants have the ability to significantly increase the apparent viscosity and elastic properties of the treating fluids. This is because of the ability of surfactant monomers to associate and form rod-shaped micellar structures under certain conditions.Viscoelastic surfactant-based acid systems have been used in Saudi Arabian fields in matrix acid stimulation, and in leakoff control acids during acid-fracturing treatments. These surfactants were used to provide diversion during acidizing of vertical, long horizontal, and multilateral wells. They were used in sour environments where hydrogen sulfide levels reached nearly 10 mol%. They were also utilized in gas wells to reduce acid leakoff, and create deep fractures in dolomitic carbonate reservoirs (250 to 275°F). In addition, they were successfully employed to stimulate seawater injectors and disposal wells where the bottomhole temperature was in the range of 100 to 150°F.More than 250 wells (oil, gas, water injectors, and disposal wells) were treated with viscoelastic surfactant-based acid systems. The acid was placed either by bullheading, by using coiled tubing with or without a tractor. In some cases, these treatments included stages of emulsified or regular acids. All these wells responded positively to the treatment. There were no operational problems encountered during pumping these acids even when low-permeability reservoirs were treated. Because these acid systems do not contain polymers, there was no need to flow back water injectors. The spent acid in oil and gas wells was lifted from the treated wells in a very short period of time. Finally, wells treated with surfactant-based acid systems showed sustained performance for longer times than those treated with other acid systems.
Pressure Variations Inside the Hydraulic Fracture and Their Impact on Fracture Propagation, Conductivity, and Screenout
Authors: Daneshy A. Ali 
Published: December 2007

Summary
Field measurements of fluid pressure inside hydraulic fractures have shown rapid pressure declines along the fracture length. The consequence of this pressure profile is rapidly tapering fracture width. This means that a disproportionate volume of fluid and proppant injected inside hydraulic fractures remains near the wellbore, thus creating excessive near-wellbore and substantially less far-field fracture conductivity. This explains why history matching of oil well production figures yields much lower effective fracture lengths than when the same exercise is performed for gas wells, as oil wells require higher fracture flow capacity because of their higher permeability.
The rapid tapering of the fracture width also restricts the movement of the proppant inside the fracture, causing its accumulation near the wellbore. As the treatment progresses, and if sufficient proppant volume has been injected inside the fracture, the near-wellbore segment of the fracture can begin to fill with proppant, thus reducing the open width available for further movement of the fluid. Essentially, accumulation of proppant near the wellbore reduces the fracture width available for fluid flow, which then results in higher frictional pressure losses inside the fracture, further skewing the pressure distribution and eventually leading to screenout.
Producing Extra-Heavy Oil From the Orinoco Belt, Cerro Negro Area, Venezuela, Using Bottom-Drive Progressive Cavity Pumps
Authors: Ramos M. A. , Brown J. C. , Rojas M. , Kuyucu O. , Flores J. G. 
Published: December 2007

Summary
The traditional means of artificial lift production for vertical and deviated wells in the Orinoco oil belt in eastern Venezuela used to be rod pumping and top-drive progressive cavity pumps (PCPs), particularly for wells with production rates ranging from 200 to 600 barrels of oil per day (BOPD) of extra-heavy oil (8°API gravity and viscosities of 2,000 cp at a reservoir temperature of 133°F). After 1995, with the implementation of horizontal drilling technologies for the construction of wells in unconsolidated sandstones, electrical submersible pumps (ESPs) became an alternative to handle higher production volumes (Ramos and Rojas 2001). More recently, top-drive PCPs have also been installed to produce extra-heavy oil at high rates.
Hybrid artificial lift technologies, such as bottom-drive progressive cavity pumping, which combine features of the ESP and the PCP systems, have recently been successfully evaluated in the Orinoco belt to exploit extra-heavy oil reserves economically. A typical completion assembly includes a multisensor gauge to obtain downhole pressures, temperatures, and vibration amplitudes of the system, and to detect power-cable current leaks; a four-pole motor; a protector; a 4:1-ratio gear box; and the PCP. The functional design of the bottom-drive PCP facilitates the handling of viscous and abrasive fluids, increases the flow rate, and diminishes the operational costs. Further advantages of this application include the complete elimination of tubing wear by eliminating the need for a rod string, greater torque capacity, lower surface maintenance cost, lower load and horsepower requirements, and lower frictional losses.
The application of bottom-drive PCPs in the Cerro Negro area has resulted in production rates of up to 1,000 BOPD of extra-heavy oil with 50% lower horsepower requirements in comparison to those of conventional top-drive PCP systems.
Challenging Convention in Sand Control: Southern North Sea Examples
Authors: McPhee Colin , Farrow Chris , McCurdy Phil 
Published: December 2007

Summary
Sand production is a major issue facing many operators in the mature southern North Sea (SNS) gas fields. Historically, sand-control completion decisions have often been based on the assumption that sand control will occur and have been constrained by the restrictions imposed upon sand entering the gas transport pipeline. The inherent conservatism of this approach leads to significant increases in completion costs and misses potential productivity gains.
A holistic sand management strategy has been developed for the southern North Sea to challenge the conservative paradigm. This is based on a complete understanding of SNS reservoir rock properties and sand control completion performance in gas wells and has been tuned by learnings from SNS and analogous fields. It combines sand failure prediction, methodical and structured selection of sand control approach (including consideration of production performance, longevity, and risks), and novel solids lifting and erosion assessment models to achieve better quantification of the risk and consequences of sand production for wells and facilities. Key selection criteria are used instead of arbitrary decisions based on limited and often unaudited data. The role of an asset focal point with clear ownership of all relevant sand production data and issues is fundamental to the success of this integrated strategy.
Tools are available to predict when, where, and even how much sand will be produced, how much sand will be lifted to surface, and how much erosion it will cause. Methodologies are also available to evaluate and rank the available sand-control techniques in a consistent and systematic manner.
This systematic and integrated approach to sand management has enhanced well productivity and reduced completion costs without compromising sand management or exceeding sand production constraints. Challenging sand management convention in the demanding environment of the SNS compels operators to use these methodologies to much greater effect.
Development of a Correlation Between Performance of CO2 Flooding and the Past Performance of Waterflooding in Weyburn Oil Field
Authors: Asghari Koorosh , Dong Mingzhe , Shire Jessie , Coleridge Tom , Nagrampa Janelle , Grassick Jessie 
Published: December 2007

SummaryWeyburn oil field, located in southeast Saskatchewan, has been the site of one of the largest carbon dioxide (CO2) flooding projects in the world since September 2000.In this paper, data of the past performance of waterflooding in the Weyburn field was used to develop empirical correlations to predict the performance of CO2 flooding. Two different correlations were developed based on CO2-injection schemes in Wey-burn. The first correlation is based on a water-alternating-gas (WAG) process through vertical wells, and the second correlation is based on the cases in which CO2 is injected through horizontal wells and water is injected separately through vertical wells. The first step was to collect and analyze production data from 1958 to 2004. Oil-production rates for both waterflooding and CO2 flooding periods, water-injection rates, and CO2-injection rates were used in developing the correlations. The empirical model for injecting CO2 and water through vertical wells was verified using the Kinder Morgan CO2 flood-scoping model (this is not a trademark product) and actual field production data. The comparative analysis showed 12% error between our simple correlation and the Kinder Morgan model. For injecting CO2 in horizontal wells, the correlation could not be verified against the Kinder Morgan model, but the correlation followed the actual oil production in the field very closely.This new model can be used effectively as a screening tool for predicting the performance of CO2 flooding in various locations in the Weyburn reservoir based on the data obtained from past waterflooding performance and the rate of CO2 injection. Therefore, it can contribute significant savings in time and expense to the operating oil company. Also, this approach can be used for other potential CO2-flooding processes in reservoirs with histories and properties similar to those of the Weyburn field.
Postnatal Programming of Glucocorticoid Metabolism in Rats Modulates High-Fat Diet–Induced Regulation of Visceral Adipose Tissue Glucocorticoid Exposure and Sensitivity and Adiponectin and Proinflammatory Adipokines Gene Expression in Adulthood
Authors: Boullu-Ciocca Sandrine , Achard Vincent , Tassistro Virginie , Dutour Anne , Grino Michel 
Published: December 2007

OBJECTIVE—Alterations of the perinatal environment, which lead to increased prevalence of the metabolic syndrome in adulthood, program an upregulation of systemic and/or adipose tissue glucocorticoid metabolism (11β-hydroxysteroid dehydrogenase type 1 [11β-HSD-1]-induced corticosterone reactivation). We hypothesized that postnatal programming could modulate high-fat diet–induced adipose tissue dysregulation in adulthood.
RESEARCH DESIGN AND METHODS—We compared the effects of chronic (since weaning) high- or low-fat diet in postnatally normofed (control) or overfed (programmed) rats.
RESULTS—Postnatal programming accentuated high-fat diet–induced overweight, insulin resistance, glucose intolerance, and decrease in circulating and epididymal adipose tissue adiponectin. Neither manipulation altered liver function. Postnatal programming or high-fat diet increased systemic corticosterone production, which was not further modified when both manipulations were associated. Postnatal programming suppressed high-fat diet–induced decrease in mesenteric adipose tissue (MAT) glucocorticoid sensitivity and triggered high-fat diet–induced increase in MAT glucocorticoid exposure, subsequent to enhanced MAT 11β-HSD-1 gene expression. MAT tumor necrosis factor (TNF)-α, TNF-receptor 1, interleukin (IL)-6, resistin, and plasminogen activator inhibitor-1 mRNAs were not changed by high-fat feeding in control rats and showed a large increase in programmed animals, with this effect further enhanced by high-fat diet for TNF-α and IL-6.
CONCLUSIONS—Our data show for the first time that postnatal manipulation programs high-fat diet–induced upregulation of MAT glucocorticoid exposure, sensitivity, and inflammatory status and therefore reveal the pivotal role of the environment during the perinatal period on the development of diet-induced adipose tissue dysregulation in adulthood. They also urge the need for clinical trials with specific 11β-HSD-1 inhibitors.
Component‐Based Software Engineering
Authors: Cao Fei , Gray Jeff , Bryant Barrett R. 
Published: December 2007

AbstractComponent‐based software engineering (CBSE) is becoming an accepted engineering discipline for promoting software reuse throughout the software engineering lifecycle. Beyond software reuse, CBSE also offers a promising way to manage the complexity and evolution of the development process through a unique means of encapsulation and separation of concerns at different abstraction levels.This article begins with a description of the key characteristics of a software component and then provides a survey of the major component models based on those key characteristics. The latter part of this article discusses the existing engineering issues in CBSE and examines the major research projects that are addressing the challenges. Finally, this article explores recent software engineering technology toward automation in CBSE, which promises to offer yet another channel for boosting the productivity of software development.
Software Module Risk Analysis
Authors: Khoshgoftaar Taghi M. , Seliya Naeem 
Published: December 2007

AbstractEstimating the quality of software modules provides a practical way to assess their potential risk. A software quality estimation can be used to provide a targeted software quality improvement initiative. The aim is to provide the management team with a practical quality assessment of software modules for a cost‐effective utilization of software quality improvement resources. In our previous and ongoing research, we have empirically investigated three different kinds of software quality models that are built using software measurement data—software quality classification, software fault prediction, and module‐order modeling. The classification model predicts the class membership of software modules into the fault‐prone and not fault‐prone classes. The fault prediction model estimates the number of faults expected in the modules. A module‐order model predicts the ranking of the modules with respect to their relative software quality. The preference among the three software quality models depends on the software quality improvement goals of the given software project team. We present the useful principles and a detailed overview of the three software quality estimation models, using a case study of a large‐scale telecommunications software system. The classification model is built using the logistic regression technique, whereas the fault prediction model is built using the multiple linear regression technique. The module‐order model is built using the estimations of the fault prediction model for ranking the software modules. We summarize our work with suggestions for software tools that can be used to build software quality estimation models.