bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effects of Monoethylene Glycol on Carbonate Equilibrium and Calcite Solubility in Gas/Monoethylene Glycol/Water/Salt Mixed Systems
Authors: Lu Haiping , Kan Amy T. , Tomson Mason B. 
Published: April 2009

Abstract
Monoethylene Glycol (MEG), HOCH2CH2OH, is an important raw material with numerous industry applications, which include polyester synthesis, automobile antifreeze, coolant, and aircraft anti-icer. In oil and gas industry, MEG is commonly used as a gas hydrate inhibitor, which can prevent the formation of gas hydrate during the production of oil and gas in oil wells. However, MEG has the adverse effects on the solubility of minerals. The lowering solubility of minerals will result in the precipitation of mineral scales, which is another serious problem in the production of oil and gas and also causes scaling problems during glycol regeneration.
Despite the importance of scale problems with MEG in oil production, there are few investigations on the solubility of mineral salt in the co-solvent of MEG and brine solutions due to the complexities of this mixed-solvent system. In this research, experiments have been conducted on the carbonate equilibrium and the solubility of calcite at 2°C- 70°C, 0-6.5 m ionic strengths, and 0-100% MEG. MEG activity coefficients with respect to dissolved CO2, bicarbonate, carbonate, and calcium are determined as a function of temperature, ionic strength, and mole fraction MEG in mixed solvent.
A self-consistent activity model is proposed based on the data obtained from this study. Pitzer theory was used to calculate the effect of salt and a Born type equation was applied to analyze the effects of MEG. This model can predict mineral scales solubility in the presence of MEG and brine solutions, provide a better understand of effects of MEG on solubility of scales, and gain an insight into the scale inhibitor studies.
Testing Gas Well Deliquification Chemicals at Real Downhole Conditions
Authors: Pakulski Marek 
Published: April 2009

Abstract
Continuous or batch treatment of low-pressure gas producing wells with foaming agents is a common and cost-effective method to sustain production from such wells. The foam additives convert gas and brines into foams lowering the bottomhole hydrostatic pressure and increasing liquids unloading from the well; thus, preventing wells from filling with water and "drowning". The process can utilize existing formation gas or lift-gas injected into the well. Water to be unloaded can be from nearly drinking quality to supersaturated brine. Selection of a proper foaming agent for foam assisted well deliquification at downhole conditions becomes more complicated in deeper hot wells and with influx of various amounts of oil and condensate in well liquids. Common and standard bench foam testing methods are insufficient to assess foaming agents efficiency at extreme environments.
Answering the need for more realistic testing methodology of foaming agents an automated heated and pressurized foam testing column was constructed. The device is capable of injecting gas, brines, condensate and foaming agents at high pressure and bottomhole temperatures encountered in even deepest wells. Foaming agents' effectiveness is measured at true well conditions. The paper describes design, testing procedures and compares results against older testing methods.
We describe here first laboratory obtained data on foams vertical movement at high pressure and high temperature wellbore conditions. Measurements of foaming agents well deliquification abilities at temperatures above 100°C (212°F) are impossible to obtain with any other existing instrument. The results validate the original scientific idea behind constructing of a device measuring foaming agent's effectiveness at below critical velocity gas flows based on brine retention in the column. The foam column is becoming an indispensable tool for development of foaming agents to be used in challenging environments. This apparatus allowed moving the ultimate new product testing from the field back to the lab and avoiding costly mistakes.
Troubleshooting Nitrate Field Injections for Control of Reservoir Souring
Authors: Jack T. R. , Grigoryan A. , Lambo A. , Voordouw G. , Granli T. 
Published: April 2009

Abstract
Nitrate addition to injection water has been used to control the development of reservoir souring through microbial production of hydrogen sulfide particularly in seawater floods offshore. Current interest is in the application of this technology to produced water recycle injection (PWRI) systems in onshore fields. Long term field observations and analyses for PWRI operations in both high and low temperature oil reservoirs have provided insight into issues and potential challenges that can arise in the application of nitrate as a control treatment for souring. This paper will describe the rudiments of a trouble shooting scheme that is being developed to assist in the optimization of field programs.
Viscometer for Opaque, Sealed Microemulsion Samples
Authors: Salinas Jose Lopez , Miller Clarence A. , Koh Yoo Kuy Hun , Puerto Maura , Hirasaki George J. 
Published: April 2009

Abstract
Formulation of surfactant EOR systems usually involves multiple salinity scans of the phase behavior of crude oil, surfactant, and brine systems. Usually, the measurements are made in sealed pipettes for accurate volume measurements without fluid loss. The volumes of oil and water solubilized into the microemulsion phase are observed to determine the optimal salinity and estimate the interfacial tension. Viscous emulsions and surfactant-rich condensed phases are not desirable. However, the only estimate of viscosity from the salinity scans is the movement (or lack of movement) of the interfaces upon tilting of the tube.
A falling-sphere viscometer with multiple, ring-shaped, inductive proximity sensors is described. The device uses 0.78 mm, gold-coated, paramagnetic, 440 stainless steel spheres. With this size sphere, it is possible to accurately estimate the viscosity of fluids from 1 to 1,200 cp. The spheres are paramagnetic, so they can be lifted to the top of the tube with a magnet, and meet the constraints of a Reynolds number less than 800 for low viscosity fluids, and a velocity fast enough to be detected for a high viscosity fluid. A data acquisition system control a set of four sensors for signal conditioning and time recording. When the same phase spans the space between a pair of sensors, its viscosity can be estimated directly from the transit time of the sphere. When two or three phases span the space between a pair of sensors, the viscosity of the undetermined phase can be estimated from the transit time across it after correcting for the transit times across the upper and/or lower phases. Thus the viscosity of a middle-phase microemulsion can be estimated even if it spans only a small fraction of the distance between sensors.
The system has been used to measure viscosities of lower-, middle-, and upper-phase microemulsions at ambient temperature. Also, apparent viscosities of macroemulsions and of the "colloidal dispersion" layer at the top of a lower-phase microemulsion have been measured.
Fractional-Flow Theory of Foam Displacements with Oil
Authors: Ashoori E. , van der Heijden T. L. M. , Rossen W. R. 
Published: April 2009

Abstract
Fractional-flow theory provides key insights into complex foam EOR displacements and acts as a benchmark for foam simulators. In some cases with mobile oil present the process can be represented as a two-phase displacement. We examine three such cases.
A first-contact-miscible gas flood with foam injection includes a chemical shock defining the surfactant front and a miscible shock defining the gas front. The optimal water fraction for the foam, that gives the fastest oil recovery, maintains the gas front slightly ahead of the foam (surfactant) front.
The success of a foam process with first-contact-miscible CO2 and surfactant dissolved in the (supercritical) CO2 depends on the strength of foam at very low water fractional flow, as for a surfactant-alternating-gas (SAG) process with surfactant dissolved in water. The speed of propagation of the foam front depends on surfactant adsorption on rock and also on the partitioning of surfactant between water and CO2, but is always less than the velocity of the foam front in a SAG flood with surfactant ahead of the gas. A foam with surfactant that is much more soluble in water than in CO2 would propagate slowly, regardless of surfactant's absolute solubility or the level of adsorption on rock. An aqueous surfactant preflush can speed the advance of foam, however.
An idealized model of a surfactant flood pushed by foam suggests that it is best to inject a relatively high water content in the foam to ensure that the gas front remains behind the surfactant front as the flood proceeds. Any gas that passes ahead of the surfactant front would finger through the oil and be wasted.
We present simulations to verify the solutions obtained with fractional flow methods and illustrate the challenges of accurate simulation of these processes.
Chromatographic Separation of Chemicals in Alkaline Surfactant Polymer Flooding in Reservoir Rocks in the Daqing Oilfield
Authors: Li Daoshan , Shi Mingyi , Wang Demin , Li Zhao 
Published: April 2009

Abstract
Alkaline-surfactant-polymer (ASP) flooding have been studied and applied in Daqing oil field for more than 15 years, where eight ASP pilot tests of different scales had been conducted and five ASP foods have been pilot tested. Incremental recoveries are from 19.4 to 25%(OOIP). Since the adsorption of each chemical component would have significant impact on the cost-effective and recovery efficiency of the ASP flooding process, laboratory experiments were conducted to investigate the adsorption of each component in reservoir rocks as well as the analysis of the mineral contents and the clay compositions in the reservoir rock taking from the ASP test area in the Daqing Oilfield.
In the adsorption study, four chemicals; a surfactant, an alkaline agent, polymers, and a sacrificial agent were used. The results showed that the adsorption of surfactant does not obey the Langmuir adsorption isotherm and has a maximum value of 0.6 mg/m2, but adsorptions of alkali and polymer chemicals do obey the Langmuir adsorption isotherm. Adsorption tests also indicated that the adsorption of surfactant could be reduced by 30% with the addition of 0.15wt% of a bio-surfactant as a sacrificial agent into the key surfactant, ORS-41, solution. In addition to adsorption tests, retention (dynamic adsorption) tests were conducted using reservoir core plugs. The results showed that the sequences and peaks of relative concentration (C/C0) of chemicals in effluent are polymer, alkali, and then surfactant. The results also showed that the adsorption of the surfactant is the greatest among all chemicals. This phenomenon indicates the chromatographic separation of three chemicals transport process in cores. The chemical analysis and the chromatographic separation of these chemicals in produced fluids the previous three pilot tests showed consistent results with laboratory studies, and the degree of retention of the surfactant is proportional to the clay content in field tests.
Based on these findings, an ASP flooding pilot test was conducted in the Daqing Oilfield in 1994 with the combination of a bio-surfactant and the key surfactant, ORS-41. Since the adsorption of the bio-surfactant is stronger than ORS-41, the bio-surfactant was used in the ASP pilot test to lower the amount of the more expensive ORS-41. However, the effect of bio-surfactant as sacrificial agent on chromatographic separation of chemicals in ASP flooding (or surfactant lag) is not obvious.
Spectroscopic Determination of Naphthenic Acid Composition from Various Calcium Naphthenates Field Deposits
Authors: Ahmed Mohammed Murtala , Sorbie K. S. 
Published: April 2009

Abstract
Naphthenate formation in oil production systems has been recognised for some times as a troublesome and potentially expensive flow assurance problem. The production of biodegraded or higher TAN (total acid number) crude oils together with the changes in both chemical and physical properties during production operations may trigger naphthenate formation. These naphthenate deposits may form as either a soft emulsion type sodium naphthenate or as a hard solid deposit of calcium naphthenate.
Within the Flow Assurance and Scale Team (FAST) at Heriot-Watt, we have carried out an extensive series of naphthenic acid extraction and characterization experiments on a range of field sodium and calcium naphthenates samples from around the world. In particular, we have analysed these samples using the negative ion mass spectroscopic techniques, ESMS and APCI-MS. In this paper, we present results of naphthenate extract analyses for calcium naphthenate field deposits from the North Sea and Asia. Some of the samples analysed show the presence of both lower and higher molecular weight naphthenic acids in the spectra, whilst others showed mostly the presence of higher molecular weight naphthenic acids with minor traces of lower molecular weight species. Results from this work have now shed more light on the naphthenic acid composition in different field calcium naphthenates, which has been a topic of debate for some time. Results are also presented from novel re-precipitation experiments using the naphthenic acid extract and synthetic brine. Both APCI-MS and ESEM/EDAX data are presented for these laboratory formed precipitates. These results lead to some clear conclusions on the final composition of calcium naphthenate deposits.
Completion Fluids Challenges in Maximum Reservoir Contact Wells
Authors: Al-Yami A. S. , Nasr-El-Din H. A. 
Published: April 2009

AbstractMost drill-in fluids contain weighting solids. The overbalance required between the drill-in fluid and reservoir to keep the well under control will force the weighting solids to enter the formation and cause damage, Bailey et al. (1999). Horizontal wells are intended to maximize reservoir drainage and minimize water production due to water conning, Beal et al (1996). However, unlike vertical wells, poor acid distribution occurs during matrix acidizing. Coiled tubing cannot reach the total depth of the well because of some limitations such as large washouts, length of the reel and diameter of the coil, which makes acidizing horizontal wells non-effective, (Nasr-El-Din et al., 2004b). In addition, conventional weighting solids used in drill-in fluids when entered the reservoir formation will not easily flow back into the wellbore when production resumes, Bailey et al. (1999). Format drill-in fluids with low solids content can then be used in horizontal wells, Simpson et al. (2005). However, they are expensive and require close monitoring of the pH, Nasr-El-Din et al. (2004a). Formation damage from all drilling fluids are still a concern and they are more problematic in horizontal and maximum reservoir contact wells and their damage require chemical and mechanical removal methods.Cleanup of drilling-fluid filter cake in long horizontal and multilateral wells is a difficult task. Both mechanical water jetting and/or circulating new volumes of low solids drilling fluids have certain limitations. Other methods of removing filter cake such as using chemical means for example mineral acids, esters, oxidizers, chelating agents, viscoelastic surfactants and enzymes are also limited at certain conditions.Intensive lab work has been done to evaluate mechanical and chemical methods in removing formation damage induced from drilling fluids. However, no work was done before to the best of author's knowledge in comparing these removal methods (mechanical and chemical) for different drill-in fluids supported with field cases to provide guidelines on when to use or avoid.The paper will review chemical means used to remove filter cake. Limitations of each method are highlighted. Implications to the field are discussed.
A New Look at the Viscoelastic Fluid Flow in Porous Media—A Possible Mechanism of Internal Cake Formation and Formation Damage Conrol
Authors: Dehghanpour H. , Kuru E. 
Published: April 2009

Abstract
Fluid loss control is generally achieved by increasing the shear viscosity of the fluid and developing internal/external filter cake using fluid loss control additives. If the viscosifiers and fluid loss control additives are not selected properly, both mechanisms may lead to significant reduction of permeability. Moreover, increasing fluid shear viscosity may not be desirable all the time due to the high annular pressure losses (i.e., ECD limit), in particular, when drilling long horizontal and extended reach wells.
In this paper, a new methodology is presented to formulate an "ideal well fluid", which effectively reduces fluid loss into formation without causing additional frictional pressure losses in the well. Blends of a water-soluble resin (Polyox) with different molecular weight distribution (MWD) and similar average molecular weight (Mw) were prepared. The Polyox blends were then used to prepare aqueous polymer solutions, which had similar shear viscosity but significantly different elastic characteristics (i.e., normal stress difference and relaxation time).
Core flow experiments have been conducted to investigate the effects of viscoelastic fluid rheology on the formation of "internal cake" (i.e., frictional pressure drop). Since both fluids have the same shear viscosity but different elastic properties, it was possible to see the effect of fluid elasticity on the frictional pressure losses alone. The fluid with higher elasticity exhibited significantly higher resistance to flow through porous media than that of the fluid with lower elasticity.
Experimental results indicated that filtration of a polymer based fluid into porous media could be considerably reduced by controlling the MWD of the polymer at constant shear viscosity and concentration of the polymer. Furthermore, formation damage risk of polymer based well fluids could be minimized without inducing additional pressure drop due to fluid flow inside the well.
Improved Oil Recovery with Chemicals in Carbonate Formations
Authors: Tabary René , Fornari Antoine , Bazin Brigitte , Bourbiaux Bernard , Dalmazzone Christine 
Published: April 2009

Abstract
A large quantity of world's oil reserves is contained in carbonate reservoirs. Most of them are naturally fractured and mixed-wet to preferentially oil-wet which are unfavourable conditions for spontaneous water imbibition. This research proposes a combination of experimental methods for the evaluation of the efficiency of chemicals to recover oil from mixed-wet to oil-wet cores. The study is oriented towards the acquisition of data required for modelling chemically-assisted imbibition mechanisms.
Both spontaneous and forced imbibition experiments were performed on outcrop carbonate cores, following specific procedures for establishing given wettability indices. Alkalis were used with and without surfactants as chemical additives of the imbibing aqueous phase. Spontaneous imbibition tests were carried out with reactive and non-reactive oils, in order to dissociate/investigate the effects of alkali and surfactants on the water-oil InterFacial Tension and on the rock wettability. The alkalis exhibited a striking imbibition enhancement with a reactive oil. With a non-reactive oil, imbibition was moderate in the presence of alkali without surfactant. Formulations including a surfactant and an alkaline agent were evaluated and the results are discussed in relation with the InterFacial Tension. Moreover, the wettability index determined through centrifugation and relative permeability data were found to be consistent with the results of spontaneous imbibition tests. Finally, the generic experimental methodology proposed herein delivers a consistent set of relevant parameters for assessing and modelling the recovery efficiency of alkali-surfactant solutions in many fractured carbonate reservoirs with unfavourable recovery prognosis.
Development of Fourier Transform-Ion Cyclotron Resonance Mass Spectrometry Protocol for the Analysis of Asphaltene Field Samples and Solubility Fractions
Authors: Schrader W. , Panda S. K. , Andersson J. T. , Salisbury M. , Grutters M. , Shepherd A. G. 
Published: April 2009

Abstract
One of the most important issues in oilfield chemistry is the troublesome occurrence of organic and inorganic solids which may form downhole in the reservoir, wellbore, topsides and/or in pipelines. Asphaltenes are a class of compounds in crude oils, defined in solubility terms that under certain conditions are known to precipitate and deposit. This may lead to very expensive remediation and treatment operations. Over the years much research has been carried out on asphaltenes. Yet the exact chemical nature of these species still remains unknown. The determination of asphaltene molecular weight distributions in conjunction with the identification of compound classes is a major challenge in the prediction of asphaltene problems with petroleum fluids. Fourier-Transform Ion Cyclotron Resonance Mass Spectrometry (FT-ICR MS) is a technique well-suited for this purpose, due to its unmatched resolution and the possibility of providing information otherwise not available from more traditional bulk elemental analysis methods. We have designed a preliminary analytical protocol with this objective in mind. It involves the sample preparation (e.g. sulfur selective chromatography and derivatization) in combination with FT-ICR MS. Initial data show that the predominant compounds in the asphaltene samples investigated were species in the mass range of 200-1100 Daltons containing various functionalities, including nitrogen-, sulfur- and oxygen-heterocycles. It was possible to see clear differences between asphaltene field samples and solubility fractions. Further work should target the correlation of this information with the precipitation of asphaltenes from problematic fluid samples.
An Improved Oil-Based Chemical Gel System for Wellbore Stabilization
Authors: Scorsone Jason T. , Sanders Mark W. , Patel Arvind D. 
Published: April 2009

Abstract
Historically, water-based chemistries, such as epoxy resins, latex polymers and transition metal crosslinked polymers have been used to mitigate many of the operational problems associated with formation fractures. However, these approaches have found limited success for various reasons such as temperature limitations, complicated mixing and placement issues, weak gel strengths, health & safety concerns, and compatibility with various types of drilling fluids. A new oil-based chemical gel system which addresses many of the issues associated with current systems has been developed. The thermal stability, curing time, compressive strength, and adhesion properties of the new system depend on the manipulation of the composition and chemistry of the components. This newly developed chemical gel is more controllable over a wide range of temperature and time, and is compatible with many invert-emulsion drilling fluids.
This paper will detail the innovative chemistry of this oil-based gel system. The gel is formed by the crosslinking reaction of a modified polyurethane resin and a uniquely modified siloxane mechanism. Systematic development and evaluation, including temperature stability, controllable curing times, compressive strength and adhesion strength to formation of the system will be included.