bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Study of Proppant Formation Reactions
Authors: Weaver Jim , Rickman Richard , Luo Hongyu , Logrhy Ray 
Published: April 2009

Abstract
Based on long-term API conductivity data, proppants are generally chosen to optimize fracturing cost versus fracture conductivity. This long-term data is acquired by measuring conductivity for two days at simulated conditions of closure stress and reservoir temperature. It is recognized that the majority of the conductivity damage to a proppant pack occurs rapidly during the first day at simulated conditions. It is clear on examination of raw data that conductivity has not reached equilibrium after two days of flow, but rather it is still declining. Investigators who have studied the effect of longer flow-time on fracture conductivity of proppants have all concluded that the decline in conductivity continues for a much longer time.
Much attention has been given to the mechanical properties of proppants to aid in the selection of the best material for a particular fracture treatment. These properties include: size, proppant-size distribution, sphericity, hardness, crush resistance, and acid solubility. Other than acid solubility, little information about the chemical reactivity of the proppants has been noted. Recent work has demonstrated that, at some reservoir conditions, certain proppants become significantly chemically reactive.
This paper presents the proppant as starting material for geochemical reactions with various aqueous fluids saturated in typical formation minerals. Methods have been developed for rapid testing of these interactions, and test results clearly demonstrate how important proppant chemical reactivity is as losses in proppant-pack permeability of 50–90% were obtained, owing to the genesis of cementatious and porosity-filling minerals. In addition, some proppant chemistries were found to be much more susceptible to these types of reactions, losing much of their mechanical strength in a surprisingly short period of time. Results from this study indicate that operators who rely solely on API test methods in evaluating the suitability of proppants for particular downhole conditions might miss significant damage potential from geochemical reactions occurring between the proppant and formation fluids.
Effects of Hydrogen Sulfide on Gel Typed Plugging Agents
Authors: You Qing , Wang Yefei , Zhou Wei , Zhao Fulin , Zhang Jian , Yang Guang 
Published: April 2009

Abstract
In view of the gels applied as plugging agents in drilling plugging and water plugging in oil and gas reservoir containing hydrogen sulfide (H2S), the effects of H2S on widely used gel blocking agents were studied in this article. The gel blocking agents include Na2Cr2O7/Na2SO3/HPAM gel, Na2Cr2O7/(NH2)2CS/HPAM gel, Cr(III)-acetate & Cr(III)-lactate/HPAM gel and phenol formaldehyde resin/HPAM gel. The results show that the effects of H2S on Na2Cr2O7/Na2SO3/HPAM gel and Na2Cr2O7/(NH2)2CS/HPAM gel are significant, while the effects on Cr(III)-acetate & Cr(III)-lactate/HPAM gel and phenol formaldehyde resin/HPAM gel are relatively slight. The mechanisms of H2S affecting the gels were also researched. For Na2Cr2O7/Na2SO3/HPAM gel and Na2Cr2O7/(NH2)2CS/HPAM gel, the H2S as reductant(the reducibility is more than that of Na2SO3 and (NH2)2CS) can reduce Cr(?) into Cr(III) and accelerate crosslinking reaction with HPAM in low concentration of H2S, while it can react with Cr(III) generating Cr2S3 precipitation in high concentration of H2S, for which the bulk gel can not form without Cr(III). For Cr(III)-acetate & Cr(III)-lactate/HPAM gel and phenol formaldehyde resin/HPAM gel, the changes are mainly affected by pH value. Therefore, according to the comprehensive survey of the effects of H2S on gel typed plugging agents, the phenol formaldehyde resin/HPAM gel is recommended as the plugging agents suitable for oil and gas reservoir containing H2S.
Successful Naphthenate Scale and Soap Emulsion Management
Authors: Runham Gerard , Smith Colin 
Published: April 2009

Abstract
Naphthenate scales and carboxylate soap emulsions have become increasingly evident issues as more marginal crudes are sourced and through greater awareness. These issues are not new but the potential severity and increased occurrence highlights the need for successful management and the importance to field development and expansion. This paper provides a comprehensive and up-to-date resource for successful management of naphthenate/carboxylate issues. The paper is aimed at development projects, during flow assurance assessments as well as existing operations trying to manage naphthenate/carboxylate issues, and attempts to bring together all available information to provide a holistic approach to management.
There is a number of different control approaches published in the literature and in the author's experience. No definitive solution has been identified but this paper provides a review of varying strategies for mitigation that if appreciated early or even later in production life, can result in successful management. Previously, operational problems caused by naphthenate/carboxylate have occurred in production facilities, which then require remedial efforts and significant chemical treatment. As more knowledge is available, effort has been applied to the development stage through new innovative system designs. These combine identification and understanding with process design, operational practices, chemical treatment and remedial efforts. No particular approach is more effective but should be tailored to the development and how the problem manifests itself. Equally there is no ‘magic-bullet’ currently to these problems but nevertheless, with good understanding and considered application of different approaches, these naphthenate/carboxylate problems can be successfully managed.
Experimental Methodology to Evaluate DRA: Effect of Water Content and Waxes on Their Efficiency
Authors: Henaut I. , Darbouret M. , Palermo T. , Glenat P. , Hurtevent C. 
Published: April 2009

Abstract
Drag reducing agents are used to reduce significantly the frictional pressure loss under turbulent flow conditions, allowing a substantial increase in pipeline capacity. Their performance is known to depend on their own characteristics (molecular weight, structure, chemical composition) and on external parameters such as turbulence intensity, oil viscosity, etc. The mechanism by which DRAs interfere with turbulence is not fully understood and drag reduction is not easy to predict. Laboratory tests are still required to quantify the potential efficiency of these additives. This paper reports on an original experimental methodology based on the combined use of a classical rheometer and a laboratory loop offering a large range of experimental conditions in terms of temperature, pressure, flow rates and cooling rates. Different commercial oil soluble DRAs have been tested on various fluids including a paraffinic crude oil. The experimental results have shown that either the presence of waxy crystals or emulsified water droplets can alter the DRA efficiency, while they are not affected by waxy deposits or low temperature.
Barite Nucleation and Inhibition at 0-200°C, With and Without Hydrate Inhibitors
Authors: Fan Chunfang , Kan Amy T. , Tomson Mason B. 
Published: April 2009

Abstract
This work is the first detailed and reliable study of barite nucleation kinetics in the presence and absence of scale inhibitors at 0-200°C. In this study, we developed an apparatus to study the nucleation kinetics of barite scale formation at high temperature in the presence and absence of scale inhibitors by monitoring pressure change over a micrometer sized in-line filter, which has been proved to be an easy and accurate method to study mineral scale nucleation kinetics at high temperature conditions. Additionally, we investigated the nucleation kinetics of barite at 0-25°C with and without hydrate inhibitors. By using this newly developed "pressure" method, we successfully measured the nucleation kinetics of barite in 1M NaCl solutions at a temperature range from 100-200°C and at various supersaturation conditions. We also evaluated the inhibition efficiency of barite precipitation at this very high temperature range. Based on the experimental results, the relationship of precipitation kinetics of barite as a function of temperature and saturation index was established. The inhibition efficiency of phosphonate inhibitor (BHPMP) on barite precipitation has been evaluated over the same range of condition. Results of this study have been incorporated into the scale prediction software, ScaleSoftPitzer.
Quantitative Evaluation of Calcium Sulfate Precipitation Kinetics in the Presence and Absence of Scale Inhibitors
Authors: Kan Amy T. , Fu Gongmin , Fan Chunfang , Tomson Mason B. , Shen Dong 
Published: April 2009

Abstract
In this study, the nucleation kinetics of calcium sulfate scale formation in the presence and absence of scale inhibitors has been studied. The nucleation kinetics of calcium sulfates in 0 – 3.2 M NaCl solution was measured from 0 – 200 °C at various supersaturation conditions (SI = 0-1.3). The phase behavior of these various calcium sulfate phases were monitored by X ray diffraction. The inhibition study was done by evaluating the inhibition efficiency of calcium sulfate precipitation at the same supersaturation and temperature ranges as the nucleation study. Several polyphosphonate, polymeric and green inhibitors were found to be effective inhibitors. The study has shown that calcium sulfate scales are very difficult to inhibit at SI &gt; 1. Calcium sulfate scale is most effectively inhibited by HDTMP (hexamethylenediamine tetra(methylene phosphonic acid)) if the saturation index is below ~1.0. In addition, a semi-quantitative model to predict precipitation kinetics of calcium sulfate as a function of temperature, pH, saturation index and HDTMP concentration was established with experimental results from this study. The effect of methanol and methylene glycol on calcium sulfate precipitation kinetics and inhibition is also presented.
Chemistry of Injection Water and its Impact on Oil Recovery in Carbonate and Clastic Formations
Authors: Alotaibi M. B. , Nasr-El-Din H. A. 
Published: April 2009

Abstract
Waterflooding has been used for many decades as a way of recovering more oil. Historically, the salinity of the injection water has not been regarded as a key variable in determining the amount of oil recovered. Crude oil/water/rock chemical interactions can lead to large variations in the microscopic displacement efficiency of waterflood. There is increasing evidence, as reported in the literature, that injecting low salinity brines has a significant impact on the amount of oil displaced, but the exact mechanism by which this occurs is an unsettled issue. The main objective of this paper is to determine the effects, advantages, and practicalities of using low salinity waterflood to displace more oil in both carbonates and clastic formations. Another objective is to understand the main mechanisms in low salinity waterflood, and to determine the effects of salinity level on oil recovery.
An extensive literature review is assembled about fluid/rock interactions, wettability alteration, clay hydration, and multi-component ion exchange (MIE), and waterflood experiments using coreflood setup. Seawater injection in carbonate formations has important effect on oil recovery, especially in fractures. The recovery mechanism is completely different in carbonate than in sandstone formations, due to different rock mineralogy, brine concentration and chemistry. Salt content in connate water also plays a role in increasing oil recovery, especially when decreasing the brine salinity. The effect of high, medium, and low salinity brines on lowering the oil-water interfacial tension and/or alter the wettability characteristics of the reservoir rock is discussed. The effects of various salinity brines on reservoir rocks during waterflooding are necessary to recover more oil and that at the end will increase oil recovery.
Remediation of Naphthenate Stable Emulsion for Malaysian Oilfields
Authors: Salleh Intan Khalida , Nadeem Muhammad , Aziz Khairul Mustaqim A. , Alwi Noraliza , Hamid Pauziyah A. , Azhan Arif 
Published: April 2009

Abstract
Crude oil production from various fields contains large amounts of naphthenic and carboxylic acids. Combination of formation and injection water with these acids has resulted in the production of stable viscous emulsion which affects oil production to a large extent. Due to the unique properties of different crudes, injection and formation waters a better understanding of the chemistry of the naphthenic acids is of great interest. Interaction of naphthenic acids in crude oil with metal ions such as calcium and sodium leads to the formation of naphthenates. Moreover, the release of CO2 from the crude oil at sufficiently low pressures leads to a corresponding increase in pH which then leads to the formation of soaps. The behavior of naphthenates ranges from soft to hard emulsion which depends on the cation composition of the brine and other contributing factors.
This study investigates the effects of a range of parameters on the Naphthenate emulsion formation, including naphthenic acid type, composition of the brine, pH, etc. A pseudo model of synthetic naphthenic acids using commercial mixtures and various types of crude oil and naphthenic acid was utilized to investigate emulsion stability and viscosity. It was concluded that brine chemistry and pH play a major role in the stability and viscosity of the emulsion. Slight variation in the pH with controlled brine composition accelerates the demulsification process.
The Application of Bioassays for Evaluating In-Situ Biocide Efficiency in Offshore Oil Production in the North Sea
Authors: Hansen Lars Hvejsel , Larsen Jan , Jensen Michael , Thomsen Uffe Sognstrup , Sørensen Ketil , Lundgaard Thomas , Skovhus Torben Lund 
Published: April 2009

Abstract
Microbial activity has a severe impact on corrosion of oil production facilities and reservoir souring. Bacterial growth and metabolic products significantly aggravating the corrosion of pipelines, manifolds, and separators which increases the risk of system failure. Microbiologically influenced corrosion (MIC) is caused by the turnover of hydrogen, sulfur and organic carbon driven by sulfate-reducing bacteria (SRB), sulfate-reducing Archaea (SRA) and methanogens.
One important risk management tool is biocide dosage to control microbial activity in offshore oil production systems. To obtain a cost-efficient biocide treatment strategy it is important to determine biocide efficiency using microbiological assays (bioassays) that comprise quantitative measures of:
Bacterial growth. Activity of specific bacterial groups related to MIC and souring. Accumulation rates of carbon dioxide, sulfide and methane.
The bioassays presented in this paper investigate microbial activity in produced waters from an offshore platform where different biocides were tested. Based on molecular microbiology methods (MMM) it was evident that bacterial growth occurred in production water without addition of biocide at growth rates up to 0.46 1/d. Furthermore, active growth of both SRB and Archaea indicated that microorganisms that may be involved in corrosion processes were active in cell numbers of 105 cells/mL. Concurrently, depletion of sulfate and accumulation of total inorganic carbon, sulfide, and methane due to microbial activity was measured and maximum rates were used in combination with MMM to evaluate activity in bioassays with and without biocide. The results showed that addition of biocide in both injection and production waters decrease cell numbers and metabolic activity of SRB and methanogens.
In general bioassay results can be used to evaluate the efficiency of biocides and nitrate at different dosage concentrations. The bioassays are most valuable when implemented in a risk assessment model for MIC and souring of oilfield reservoirs.
New Method for Scale Inhibitor Testing
Authors: Halvorsen Erling Notto , Halvorsen Anne Marie Koren , Reiersølmoen Kristin , Andersen Tore Roberg , Biørnstad Cecilie 
Published: April 2009

Abstract
During qualification of scale inhibitors for the Ormen Lange project, it was discovered that the dynamic tube blocking (DTB) test could not simulate the scaling conditions good enough for gas/condensate subsea fields which will be using pH stabilised MEG for hydrate control.
The pH stabilizer in the lean MEG will be present mainly as carbonate and the pH is &gt;10. After mixing with the well fluids the pH will be reduced to ~7. At the subsea mixing point the carbonate will react with CO2 gas and produce bicarbonate. This process could not be simulated with the DTB equipment since it did not allow CO2 gas to be present at the mixing point and the synthetic formation water could not dissolve enough CO2. The result will be too high pH and too high scaling potential. Presence of particles in the lean and rich MEG is also important for the efficiency of scale inhibitors, which in some cases can be difficult to include in tube blocking tests.
A new test method has been developed that simulates the mixing point subsea and the pipeline downstream the MEG injection point. Cold lean MEG with particles and warm formation water is mixed and flow down a warm glass wall in a double walled cell purged with CO2 or a mix of CO2 and N2 to achieve the correct CO2 partial pressure and temperature. Then the mix of MEG, formation water and gas is pumped through a glass and/or steel coil. Examination of the glass and steel coils are done visually by the eye and by SEM, respectively.
The new test method has been tested and has been used to qualify a scale inhibitor for a subsea development. The use of glass coils showed that the method not only shows presence of scaling if the inhibitors does not work satisfactory, but gunking (in this case separation of components which stics to the surface stemming from scale and/or corrosion inhibitor caused by incompatibility) has also been observed by this method.
Qualification of Scale Inhibitors for Sub Sea Tie Backs with MEG Injection
Authors: Halvorsen Erling Notto , Halvorsen Anne Marie Koren , Reiersølmen Kristin , Andersen Tore Roberg , Biørnstad Cecilie 
Published: April 2009

Abstract
The Ormen Lange field are using continuous injection of MEG to prevent hydrate formation. The MEG is regenerated and reused, and corrosion control of the multiphase pipelines are accommodated by a combination of pH stabilised MEG and corrosion inhibitors. In order to avoid scaling if formation water is produced a scale inhibitor will be added to the lean MEG.
A comprehensive scale inhibitor qualification program was carried out, and the goal was to qualify one or more scale inhibitors for scale prevention downstream the MEG injection point at subsea wellhead for fully and partial pH stabilisation. 5 suppliers were invited to supply inhibitors to be included in the qualification programme and the suppliers submitted a total of 10 inhibitors. The qualification program included environmental properties, solubility in lean MEG, scale inhibitor screening tests, scale inhibitor dynamic tests, compatibility of chemicals, emulsion and foaming, partitioning, effect on particles formation and settling onshore, consumption/loss of scale inhibitor in the MEG process and stability in MEG regeneration reboiler.
The different tests are described and the results are displayed. The results from the qualification program demonstrated that only few inhibitors satisfied all requirements, the chemicals affect the formation and precipitation behaviour of calcium and iron carbonate and that only one combination of scale and corrosion fulfilled all the requirements. If a scale inhibitor has to be used in combination with a corrosion inhibitor compatibility testing is required. Incompatibility between corrosion and scale inhibitor will cause gunking and scaling. A successful combination of corrosion and scale inhibitor will not increase the corrosivity and simultaneously prevent scaling. It has been observed that such combination of chemicals does not prevent formation of particles but prevents the particles to stick to the surface.
The scale qualification program demonstrates the complexity in qualifying chemicals and the need for a good dialogue between the involved disciplines.
Development of a Methodology for the Optimization of Dehydration of Extra-Heavy Oil Emulsions
Authors: Dalmazzone C. , Noïk C. , Glénat P. , Dang F. 
Published: April 2009

Abstract
With the increasing development of heavy and extra-heavy oil fields, separation operations are becoming more and more challenging compared to separation for conventional oil fields. For in situ bitumen Extra Heavy Oils produced thanks to thermal process, dehydration requires solvent addition, injection of large amount of demulsifier additives, relatively high operating temperature, and long retention times inside the separators. So in order to respect specifications on crude oil and water quality at the lower cost, an optimization of the different parameters involved in the whole process of separation becomes necessary.
In the case of extra-heavy oils, the presence of polar heavy components, such as asphaltenes, structured as a rigid film at the water/oil interface, limits the coalescence phenomena and consequently limits the efficiency of separation by gravity or by using conventional electrocoalescence.
The paper presents a methodology that permits the optimization of water and oil separation in the case of an in situ extra-heavy oil (produced by thermal process). The crude oil was first characterized in terms of rheological behavior and interfacial properties. The dilatational viscoelastic properties of the interface were determined from measurements performed with an oscillating oil drop tensiometer. Properties of emulsification were also investigated by using a specific device named "dispersion rig" that allows the reconstitution of crude oil emulsions under controlled hydrodynamic conditions. Then a laboratory procedure based on electrical stability tests was applied in order to optimize the concentration of demulsifier required for effective water separation.
Finally, the optimal electrical parameters were determined in an electrocoalescer device in presence of the selected concentration of additive. The efficiency of coalescence was measured by following the growth of dispersed water droplets inside the emulsion using Differential Scanning Calorimetry (DSC).