bluuebunny/crossref_metadata_2025_split huggingface dataset:
Tag Retention and Effects of Tagging on Movement of the Giant Red Sea Cucumber Parastichopus californicus
Authors: Cieciel Kristin , Pyper Brian J. , Eckert Ginny L. 
Published: April 2009

Abstract
We examined tag retention and the effects of tagging on short-term movements of the giant red sea cucumber Parastichopus californicus. Retention rates were monitored for six different tag types (Floy banner FTSL-73, cinch FT-4C, fingerling FTF-69, garment, single T-bar FD-94, and the coded wire tag), which were applied to 30 individuals under laboratory conditions. The single T-bar and coded wire tag had the highest retention rates: 70% and 60% after 16 weeks, and 40% and 37% after 32 weeks. To assess the effects of tagging and handling on movement, a field study was conducted in Amalga Harbor, Alaska, in which giant red sea cucumbers were tagged with T-bar tags and monitored for 24 h. Tagged and handled animals moved significantly farther than control animals. The median (linear) distance moved by control animals over 24 h was 1.8 m (range, 0.2–4.2 m), whereas the median distance for tagged animals was 4.2 m (range, 0.4–22.7 m). Short-term behavior was affected by both tagging and handling; therefore, we recommend that researchers minimize handling and wait at least 24 h after tagging before monitoring giant red sea cucumber movements.
Development and Evaluation of Methods for Osmotic Induction Marking of Golden Perch Macquaria ambigua with Calcein and Alizarin Red S
Authors: Crook David A. , O'Mahony Damien J. , Sanger Andrew C. , Munro Andrew R. , Gillanders Bronwyn M. , Thurstan Stephen 
Published: April 2009

Abstract
We conducted a series of osmotic induction procedures for marking golden perch Macquaria ambigua with calcein and alizarin red S (ARS), evaluated the factors that influenced mark quality, and tested for any effects on fish growth and mortality. Three aspects of the marking protocols were considered: immersion time in a 5% salt solution (0, 5, or 10 min), immersion time in the fluorescent dye (5 or 10 min), and concentration of the dye (low or high). Quantitative estimates of mark intensity using photographs of marked fish were made with image analysis software. Although there were some significant interactions between factors, salt immersion was generally the primary determinant of mark intensity, followed by dye concentration and dye immersion time. Fish marked with calcein did not have higher mortality rates than unmarked fish and had significantly higher growth rates. The highest-exposure ARS treatments resulted in higher mortality and lower growth rates than for unmarked fish. Following this result, a lower-exposure ARS marking protocol was tested, which resulted in no detectable effects on mortality or growth rates while still producing high-quality marks. Although further study of the long-term retention of marks under field conditions is required to understand the limitations of the chemical marking methods examined in this study, our results suggest that the methods would greatly enhance our knowledge of the outcomes of fish stocking.
Use of Parentage Assignment and DNA Genotyping to Validate Scale Analysis for Estimating Steelhead Age and Spawning History
Authors: Seamons Todd R. , Dauer Michael B. , Sneva John , Quinn Thomas P. 
Published: April 2009

Abstract
Sound fisheries management depends on understanding life history characteristics, such as age at maturity, migration, and spawning history; hard parts, such as scales and otoliths, are commonly used to estimate values for these traits. Validation of these techniques is often difficult but critical because errors in mean values for a population can result in erroneous estimates of sustainable exploitation rates. In this study, we compared information on age and spawning history derived from genetic analysis with information from scale analysis for 1,836 individual steelhead Oncorhynchus mykiss representing two life history stages (smolt and mature adult); these fish were of hatchery and wild origin and were sampled from two rivers in Washington State over a period of 19 years. Aging error rates were less than 5% for both wild smolts and hatchery adults, but the error rate for wild adults was much higher (13%; 95% confidence interval [CI] = 1.82–29.22%). Adult scale ages were biased; scale readers typically overestimated the ages of younger fish and underestimated the ages of older fish. In addition to the errors in age estimation, repeat spawners were misclassified as virgin spawners 6.5% of the time (95% CI = 0.79–20.26%). The higher error rates obtained in using scales for aging and identifying repeat spawning in wild adults may partly stem from the more complex life history relative to that of smolts or hatchery-origin adults; these results highlight the need for verification of scale analysis, especially for wild steelhead populations.
Sandstone Cores as Reaction Vessels: Synthesis of Calcium Carbonate Particles for Artificial Formation Damage in the Qualification of Matrix Acidizing Solutions
Authors: Fuller Michael J. 
Published: April 2009

AbstractGenerally, matrix acidizing fluids for sandstone are executed in the field only after core tests qualify their ability to remove damage. However, most cores that are used come from sandstone quarries and the cores are largely clean and undamaged (and not representative of the sandstone conditions in actual producing wells). This study proposes novel applications of straightforward chemistry to synthesize calcium carbonate particles that damage the porosity of clean sandstone cores (in core flow tests); the study includes reactions carried out under controlled conditions as well as within the pore space of sandstone cores. In the controlled reactions, solutions of calcium chloride are mixed with solutions containing one of a variety of soluble inorganic or organic carbonates, and the reaction generates calcium carbonate particles. The resulting particles were characterized using both light scattering and scanning electron microscopy (SEM). The reaction rate and size distribution of calcium carbonate particles varies depending on the temperature, stir rate, chemistry of the carbonate species, and the concentrations (and concentration ratio) of calcium brine and carbonate species. This technique is also applied in actual core tests, where a sandstone core saturated in calcium brine is exposed to a solution of the soluble carbonate species and generates calcium carbonate solid (damage) throughout the length of the core from the injection face. The final permeabilities of cores subjected to this treatment exhibit damage compared to before the treatment, which is likely due to the precipitation of calcium carbonate solids. This method for damage generation has ramifications in the screening of a variety of stimulation fluids, including acids and scale inhibitors.
Impact of Successive Squeezes on Treatment Lifetime and Well Productivity: Comparative Assessment of Viscosified and Non-Viscosified Treatments
Authors: Fleming Niall , Ramstad Kari , Kidd Sam , Hoeth Laurien Wichers 
Published: April 2009

Abstract
Over the lifetime of a well it is possible that several squeeze operations will be performed depending on scaling severity. Downhole squeeze operations have been performed for many years and have on the whole been an effective scale management tool. However, the long term impact that successive squeezing has on treatment lifetime and well productivity has received little attention. SPE 113656 detailed the results of a unique sequence of long term corefloods that were designed to replicate five successive treatments on the kaolinite rich, Middle Tarbert core from Oseberg S⊘r. Relatively few squeeze treatments have been performed on this field, and the coreflood results were up-scaled to provide a potential prediction of the effects of long term squeezing and well productivity on Oseberg S⊘r. Furthermore, the laboratory results were cross-checked by comparing with the Heidrun field that has been squeezed for many years. Heidrun is an analog of Oseberg S⊘r with kaolinite rich producing intervals and similar productivity issues related to kaolinite mobilization.
In recent years viscosified squeeze treatments have become popular for improved inhibitor placement within horizontal wells and have been used on Heidrun and Norne. However, the long term impact that such squeezing has on treatment lifetime and well productivity has not until now been examined. The paper will give details of an identical sequence of long term corefloods as described above but in which the inhibitor was viscosified. All testing parameters have been kept identical between viscosified and non-viscosified treatments including the core material and scale inhibitor. The impact on squeeze lifetimes will be demonstrated along with potential formation damage mechanisms.
Sorel Cement for HPHT Downhole Applications
Authors: Santra Ashok Kumar , Liang Feng , Fitzgerald Rocky 
Published: April 2009

Abstract
Magnesium-based Sorel cement was discovered in 1867 and since then it has been used extensively for industrial flooring, fire protection, grinding wheels, and wall insulation because of its superior mechanical and thermal properties. In general, Sorel cement is extremely fast-setting and reaches very high compressive-strength (close to 10,000 psi) within a few hours. However, in terms of downhole applications, especially higher temperature, made it almost impossible to achieve acceptable placement time. In the last decade or so, advances in a retarder system made them pumpable only up to a bottomhole circulating temperature (BHCT) of 200°F with a relatively short pump time (approximately 2 hrs). Advantages of Sorel cement when applied downhole can include shortened waiting on cement (WOC) time, complete acid solubility, lean rheology to access narrow annulus, and lower thermal conductivity to name a few. The main impetus of this paper is the new retarder system that has been developed to achieve pump time for several hours at BHCT of close to 400°F. This new technology will also potentially make Sorel cement based systems useful for HPHT, SAGD and geothermal wells because these are already proven to be stable at extremely hot conditions.
The Modelling, Application and Monitoring of Scale Squeeze Treatments in Heterogeneous Reservoirs, North Sea
Authors: Jordan M. M. 
Published: April 2009

Abstract
Scale control within produced fluids as water follows the cycle of injection, production, processing and reinjection in oil/gas production facilities is critical to the effective production of hydrocarbons in a safe, economic and environmentally acceptable manner.
This paper will focus on the scale challenges associated with seawater injection into two North Sea reservoirs with a moderate Barium Sulphate scale challenge (80 to 220 ppm Barium, seawater injection) and will describe the impact of scale ion reduction from injection to production wells and the lower minimum inhibitor concentration that results
The paper will outline the selection of the inhibitor chemical for squeeze application, initially via bullhead application of the squeeze treatment without diversion then development of a diversion methodology in conjunction with production logging tool data. The paper outlines the application of the diversion treatment applied via bull heading and the improvement in treatment life as well as treatment economics that resulted in the heterogeneous formation.
The paper will clearly demonstrate using the four squeeze treatments to a single well how squeeze treatments can be enhanced without the need for coil tubing to allow selective placement. The design methods for this diversion technology will presented along with the methods of monitoring such treatment to ensure effective placement was achieved with the use of inert tracer, produced water analysis, evaluation of type/amount of suspended solids and inhibitor residuals.
Development of High-Performance Water-Based Mud Formulation Based on Amine Derivatives
Authors: Gholizadeh-Doonechaly Nima , Tahmasbi Kourosh , Davani Ehsan 
Published: April 2009

Abstract
Many benefits by use of Oil-Based Mud (OBM) in drilling oil and gas wells have been identified in the oil industries worldwide. However the current ever increasing environmental legislations in preventing OBM application in the industries have dictated the use of water-based drilling fluid as the most environmentally acceptable alternative. On the other hand, drilling with water-based systems in shaly formations may cause many problems such as wellbore instability and high torque and drag. Therefore the most optimum alternatives would be different kinds of inhibited water-based systems in which adverse effects of shaly formations can also be controlled. These water-based alternatives are called High-Performance Water-Based Mud (HPWBM). Also the OBM properties is the final goal of the researchers to reach in their investigations to design a suitable HPWBM since OBM is the ideal drilling fluid to drill problematic formations.
In this investigation attempts have been made to develop and formulate a water-based drilling fluid in which a suitable amine derivative has been successfully added to the system as a strong shale inhibitor agent instead of other conventional alternatives. Besides shale inhibition, an important challenge when using amine compounds in HPWBM is to overcome the thermal instability. Such a system must be formulated to achieve the right concentration of each mud additive to satisfy the necessity of a system that provides proper thermal stability during the drilling operation in high temperature sections. The newly HPWBM that was developed in this study comprises a specific concentration of a unique poly-ethoxylated alkyl diamine compound for shale inhibition, an amphoteric/polymeric shale encapsulator, a high-performance lubricant/deflocculating agent and special fluid loss additive to reach thermal stability up to 200°F. The designed system has exhibited optimum rheological properties and shale recovery in laboratory testing that was very close to that of OBM. The designed system has optimally improved the performance of previously formulated HPWBMs.
New Polymer Technology for Sand Control Treatments of Gas Storage Wells
Authors: Zaitoun Alain , Pichery Thierry 
Published: April 2009

Abstract
A new polymer technology has been successfully implemented in two Gaz-de-France Underground Gas Storage (UGS) facilities. The technique uses water-soluble polymers and microgels having a strong tendency to adsorb on the surface of the rock, thus forming a protective film to prevent the erosion process. All products have RPM properties (Relative Permeability Modifiers), i.e. they affect little gas relative permeability while reducing strongly the relative permeability to water. They can thus be injected into the whole open interval (bullhead injection) without specific tools for placement. A long post-flush of gas is injected after the polymer treatment to re-saturate the formation around the wellbore and check gas injectivity. Seven wells have been treated so far with the following results: All treatments were successful in stopping sand productionThe first treatment lasted about four years, after which it had to be renewed. All other treatments show long-term efficiency.Only one well suffered from a loss in Gas Productivity Index (around 20%), for all the others, gas injectivity and productivity remained unaffected by the treatment.The well treated with microgel has been producing much less water than before, in addition to the stopping of sand production
An Experimental Study of the Pore-Blocking Mechanisms of Aphron Drilling Fluids Using Micromodels
Authors: Bjorndalen N. , Alvarez J. M. , Jossy W. E. , Kuru E. 
Published: April 2009

Abstract
Drilling fluid containing colloidal gas aphron (CGA) microbubbles can bridge the pores of the reservoir rock in the near wellbore region and reduce the risks of lost circulation and formation damage. The advantage of using CGA systems is that the CGA's can be easily removed during the initial stages of production thereby reducing the costs associated with stimulation processes such as acidizing.
Although there has been some work done on the flow of the microbubbles through porous media, little is known about the optimal conditions for blocking the pores. Specifically, the effect of the interaction between microbubbles and reservoir fluid on the microbubble stability and pore blocking ability has not been determined.
This study is focused on determining the pressure at which the microbubbles invade the porous medium and the CGA/reservoir fluid interaction for pore blocking. The pore blocking ability of various CGA compositions and flow rates is also discussed.
In order to determine the effect of reservoir fluid interaction, experiments were carried out by injecting the microbubbles into a micromodel cell saturated with various fluids. The effect of water, brine, mineral oil and crude oil on the microbubble stability and pore blocking ability are investigated.
Chemistry and Mechanisms of Completion/Packer Fluids: Annular Environmentally Assisted Cracking (AEAC) of Martensitic Stainless Steel Tubing: Misconceptions Regarding the Chemical Role of Completion/Packer Fluids
Authors: McKennis Jeffrey S. , Bae Nam , Termine Enrico J. , Shimamoto Ken , Kimura Mitsuo 
Published: April 2009

Abstract
The increased use of corrosion resistant alloys (CRAs) in deep HPHT wells has led to production-tubing cracking failures throughout the industry. Many of these failures have occurred from the outside (annulus side) and been attributed to Environmentally Assisted Cracking (EAC) and hence, best described as Annular EAC (AEAC). Examination of these failures points to a serious incompatibility of the production tubing metallurgy with the packer fluid under stress.
In 2003, combining expertise in fluid chemistry and metallurgy, the authors formed a research alliance to address the AEAC problem by examining the compatibility of a wide spectrum of completion fluids with various martensitic stainless steel (MSS) metallurgies. This unique research collaboration involving extensive stress cracking testing performed with different metallurgies and different fluids under simulated well conditions has resulted in an extensive database (&gt; 4000 test entries for 27 fluids and 6 MSS metallurgies) and new body of knowledge regarding the causes behind AEAC failures.
Conventional wisdom holds that chloride ion and oxygen play major causative roles. The authors' findings, however, identify other contaminants in completion/packer fluids that play the dominant role in the chemical mechanism of the crack failures. Such contaminants include sulfur-containing species, oxidants other than oxygen, and select basic ionic species. This paper addresses the impact of the new information and identifies serious misconceptions regarding the role of completion & packer fluids in the tubular failures.
The authors' comprehensive study has advanced the industry's knowledge of the causes of AEAC by detailing the previously unrecognized importance of various contaminants present in the fluids. As a consequence, the need for quality assurance and best-practice fluid management throughout the life cycle of the fluids is now recognized. Misconceptions with respect to the chemical mechanisms and causative factors of AEAC failures are discussed. Such information should expand the industry's AEAC knowledge base and minimize the risk of tubular failure.
Stability of Partially Hydrolyzed Polyacrylamides at Elevated Temperatures in the Absence of Divalent Cations
Authors: Seright R. S. , Campbell A. R. , Mozley P. S. 
Published: April 2009

Abstract
At elevated temperatures in aqueous solution, partially hydrolyzed polyacrylamides (HPAM) experience hydrolysis of amide side groups. However, in the absence of dissolved oxygen and divalent cations, the polymer backbone can remain stable so that HPAM solutions were projected to maintain at least half their original viscosity for over 7 years at 100°C and about 2 years at 120°C. Within our experimental error, HPAM stability was the same with/without oil (decane). An acrylamide-AMPS copolymer (with 25% AMPS) showed similar stability to that for HPAM. Stability results were similar in brines with 0.3% NaCl, 3% NaCl, or 0.2% NaCl + 0.1% NaHCO3. At temperatures of 160°C and above, the polymers were more stable in brine with 2% NaCl + 1% NaHCO3 than in the other brines. Even though no chemical oxygen scavengers or antioxidants were used in our study, we observed the highest level of thermal stability reported to date for these polymers. Our results provide considerable hope for the use of HPAM polymers in enhanced oil recovery at temperatures up to 120°C if contact with dissolved oxygen and divalent cations can be minimized.
Calculations performed considering oxygen reaction with oil and pyrite revealed that dissolved oxygen will be removed quickly from injected waters and will not propagate very far into porous reservoir rock. These findings have two positive implications with respect to polymer floods in high-temperature reservoirs. First, dissolved oxygen that entered the reservoir prior to polymer injection will have been consumed and will not aggravate polymer degradation. Second, if an oxygen leak (in the surface facilities or piping) develops during the course of polymer injection, that oxygen will not compromise the stability of the polymer that was injected before the leak developed or the polymer that is injected after the leak is fixed. Of course, the polymer that is injected while the leak is active will be susceptible to oxidative degradation. Maintaining dissolved oxygen at undetectable levels is necessary to maximize polymer stability. This can readily be accomplished without the use of chemical oxygen scavengers or antioxidants.
The Corrosiveness of Nitrite in a Produced Water System
Authors: Jenneman Gary , Achour Mohsen , Joosten Mike 
Published: April 2009

Abstract
Increasing concentrations of sodium nitrite were added to synthetic North Sea produced water in the presence of either 1 bar CO2 or N2 to determine its effect on corrosion. These tests were run at 80°C in the presence of sulfide and at a sheer stress up to 25 Pa. The test materials were either A106 carbon steel or duplex stainless steel, representing the range of materials typical of upstream production equipment.
Nitrite is an effective inhibitor of sulfate reducing bacteria activity as well as an enhancing agent for biocides. Because it is a green chemical it is desirable for controlling Microbiologically Influenced Corrosion (MIC) in oilfield brines. Although known to be an effective anodic corrosion inhibitor in fresh water systems its inhibitory effects in oilfield brines are less understood.
Duplex stainless steel did not show any enhanced corrosion in an inert or CO2 environment in presence of nitrite. In the case of carbon steel, nitrite displayed an inhibiting role when exposed to 1 bar CO2 at 80°C. Increases of chlorides or sulfates had only a small effect on increasing corrosion rates in the presence of nitrite and CO2. However, in the presence of an inert gas, increases in nitrite above 2 mM significantly increased corrosion rates of carbon steel. The addition of small amounts of sulfide in the presence of 2 mM nitrite resulted in a small increase in corrosion rates of carbon steel as did the impact of 25 Pa of sheer stress. The presence of 2 mM nitrite interfered with the corrosion inhibiting activity of a commercial inhibitor in the presence of CO2.
This paper presents results of testing performed to determine the corrosiveness of nitrite in synthetic North Sea produced water.