bluuebunny/crossref_metadata_2025_split huggingface dataset:
Cloud Point and Wax Deposition Measurement Techniques
Authors: Leontaritis Kosta J. , Leontaritis John D. 
Published: December 2007

Abstract
Paraffin-waxes present in crude oils, at some thermodynamic states, exhibit the phenomenon of crystallization. The onset of wax crystallization temperature of stock tank oil at atmospheric pressure is known as the cloud point. In this paper, cloud point data are presented for several synthetic mixtures and crude oils. The cloud point data have been obtained via three different techniques: Near-Infra-Red (NIR) light attenuation, Dynamic Filtration Cloud Point (DFCP), and ASTM-D2500. For the transparent mixtures, the ASTM-D2500 method is being used as the standard against which the other two techniques are compared to. The data show that all three techniques are consistent with each other, although their precision is different. Because of its simplicity, higher precision, and wide applicability to all kinds of fluids and thermodynamic conditions, the NIR light attenuation technique is recommended.
Furthermore, cloud point and wax deposition data from a variation of the DFCP technique are presented from various crude oils from around the world. Some of these oils contain natural asphaltene dispersants and wax crystal modifiers and as a result, although these oils contain substantial amounts of asphaltene and wax molecules, they remain stable at most thermodynamic conditions encountered during their production. Two cases of these "special" oils are presented here.
Application of Nonionic Tenside Homologues in IOR/EOR and Oilfield Chemistry: Fundamental and Engineering Aspects
Authors: Lakatos I. , Lakatos-Szabó J. , Bedo Zs. 
Published: December 2007

Abstract
The paper gives an overview on the application of Nonionic surfactants in hydrocarbon industry, particularly oil production. Advantages and disadvantages are critically analyzed in field of recovery and well treatment methods, drilling and well completion, surface technology and pipe line transportation. On the basis of the literature survey it is concluded that the practice oriented R&Ds performed during the past half century were not sufficiently supported by fundamental physico chemical and colloid chemical research. In the second part of the paper the authors give a concise summary of their studies aimed at forming a theoretical basis of wide range applications of ethoxylated nonyl-phenols in oilfield chemistry. The research program comprised the thermodynamic characterization of micellization, determination of micelle and solution structure, effect of different additives, interfacial properties in gas(water and oil(water systems and the effect of tensides on interfacial rheological properties. The microscopic approach and molecular interpretation of the observed phenomena allowed the authors to recommend more precisely where, when and which of the tensides have the highest potential in different oilfield applications.
Identification of Mechanisms and Parameters of Formation Damage Associated with Chemical Flooding
Authors: Patino Omar , Civan Faruk , Shah Subhash N. , Zornes David R. , Spinler Eugene A. 
Published: December 2007

Abstract
This paper presents a practical methodology and its verification for determination of the mechanisms and parameters of chemically induced formation damage. It is based on interpretation of laboratory core flood tests by diagnostic straight-line plotting schemes. Laboratory tests were conducted to measure the permeability impairment and effluent conditions as a function of time by flooding sandstone and limestone outcrop rock samples with various alkaline solutions (NaOH, KOH, NaSiO4) and alcohol (ethanol) as might be used for improved oil recovery. The single-phase permeability variation data were plotted according to prescribed diagnostic straight-line plotting schemes proposed by Wojtanowicz et al. and Civan. Plots that result in satisfactory straight-line trends reveal the predominate mechanisms of the formation damage. Further, the values of the parameters of the governing formation damage processes are determined from the intercept and slope of the straight-lines. Higher pH solutions were observed to have caused greater reductions in rock permeability. Civan's model better described the permeability variation due to scale dissolution and precipitation processes. The Wojtanowicz et al. model identified the formation damage mechanisms as pore surface deposition and sweeping. Different rock damage conditions were observed for the initial and the later test periods, indicating that more than one formation damage mechanism was involved. The analysis of the same experimental data reveals that a numerical model such as UTCHEM will require significantly more information to perform a similar analysis of the laboratory flood results. However, the diagnostic equations provide a practical and rapid means for the determination of the formation damage mechanisms.
The methodology developed in this paper can be used for rapid detection and quantification of the formation damage mechanisms from core tests. The technique can be useful in the design of alkaline-surfactant-polymer (ASP) and/or micellar flooding chemical systems for field applications.
Effect of Brine Dilution and Surfactant Concentration on Spreading and Wettability
Authors: Vijapurapu Chandra S. , Rao Dandina N. 
Published: December 2007

Abstract
The interfacial phenomena of spreading and adhesion of fluids on rock surfaces have serious implications because of their impact on production strategy and oil recovery. The present study reports new experimental data on the effect of brine dilution and surfactant addition on spreading and adhesion behavior of Yates crude oil on dolomite surfaces. Spreading and adhesion have been characterized through measurements of oil-water interfacial tension (IFT) and dynamic (water-advancing and receding) contact angles. The interfacial tension was measured using Computerized Axisymmetric Drop Shape Analysis (CADSA) Technique, which was calibrated against the well-known du Nuoy Ring Technique. The Dual-Drop-Dual-Crystal (DDDC) Technique has been used to measure dynamic contact angles.
In order to study the effect of brine dilution, Yates reservoir brine was mixed with deionized water (DIW) in various proportions. For each diluted brine, crude oil-water IFT, water-advancing and receding contact angles were measured. The oil-water IFT initially decreased as the volume percent of brine in the mixture decreased. However, the IFT increased with further dilution of reservoir brine with DIW. A decreasing trend was observed in the behavior of water-advancing contact angle with brine dilution. This indicated that the initial oil-wet nature of the system was changed to intermediate-wettability simply by diluting the reservoir brine. However, a strange behavior of spreading of crude oil drop against brine on the dolomite surface (with large water-receding contact angles) was observed at certain brine dilutions. This spreading of crude oil appears to be related to interfacial tension in a manner similar to Zisman's observations in solid-liquid-vapor systems.
The use of surfactants to enhance oil recovery through reduction in IFT is well known in the industry. However, this study examines the capability of certain surfactants to alter wettability in addition to reducing IFT. For the Yates reservoir rock-fluids system, an Ethoxy Alcohol surfactant altered the strongly oil-wet nature (advancing angle of 158°) to water-wet (advancing angle of 39°) at a concentration of 3500 ppm. While the DDDC technique yielded significant changes in wettability due to surfactant addition, the Wilhelmy Plate Technique remained insensitive throughout the range of surfactant concentrations. The practical significance of this study is that it identifies two simple modes through surfactant addition and brine dilution to alter wettability to minimize capillary trapping of oil.
A Way Beyond Scale Inhibitors – Extending Scale Inhibitor Squeeze Life through Bridging
Authors: Selle Olav M. , Wat Rex M. S. , Vikane Olav , Nasvik Haavard , Chen Ping , Hagen Thomas , Montgomerie Harry , Bourne Hugh 
Published: December 2007

Abstract
The Heidrun Field is located in the Haltenbanken area offshore Mid-Norway. The reservoir temperature is 85 – 88 °C and the reservoir pressure is close to hydrostatic pressure, around 250 bar. Seawater injection is utilized to increase recovery and for pressure support. With Ba2+ levels averaging about 200ppm, downhole sulphate scale deposition caused by seawater injection has been identified. The field came on stream in 1995. Heidrun presents a particular challenging scaling environment due to the combination of high Ba2+ content, demand for environmental friendly chemicals, strong top-side emulsion tendency, limited hydrostatics and at times high draw down within the gravel packs. In addition, the high kaolinite content (20–30 %) in the reservoirs introduces the risk of fines mobilization leading to plugging within the gravel packs especially with the development of overflush fluids volumes used during squeeze treatments. Scale control started in November 1999 with regular squeeze treatments. However, initial squeezes suffered from short treatment life and evidence of fines related productivity decline.
Under a joint R&D program, a multi-functional additive was developed that enhanced inhibitor adsorption, provided clay stabilisation and a certain level of scale inhibition.
This paper presents both laboratory and field data to elucidate the mechanisms involved in extending squeeze life and clay fines stabilization with this additive.
Application of a Thermo-Kinetic Model to the Prediction of Scale in Angola Block 3 Field
Authors: Rousseau G. , Hurtevent C. , Azaroual M. , Kervévan C. , Durance M. -V. 
Published: December 2007

Abstract
Block 3 reservoirs in Angola are dolomitic reservoirs with temperatures ranging from 150 to 164 °C with a nearly constant pressure (320 bar). They are all affected by scale precipitation that forms into the tubings and the topsides.
Modeling was applied to find quick correlations between physical measurements and the predicted risk of scaling. Information from wire line reports, maintenance operations and gamma campaigns were gathered in order to draw up a list of risky wells, and to validate the found correlations. The water cut, the composition of the produced water, the well head temperature and the drawdown can be used to determine the risk of scaling and roughly the location of the deposits. In this paper, on one hand, we present the relation between drawdown, water cut and Calcium carbonate precipitation and on the other hand between salinity and barium sulphate scaling.
The kinetic module of the SCALE2000 software was used to explain why the injected seawater does not produce any Calcium carbonate inside the tubing even if it is supersaturated at surface conditions. Finally, a new version of this software has been tested; it includes a model that uses simplified hydrodynamic approach based on a scheme of chemical reactors connected in series.
The model thus takes into account the cumulated effects of water flow in terms of Pressure and Temperature variations, and changes in dynamic water composition due to the mixing. It is then possible to estimate both the thickness of the scale deposits and their location along a production or injection well.
Optimization of a Novel Emulsified Scale Inhibitor System to Mitigate Calcium Carbonate Scale in a Sandstone Reservoir in Saudi Arabia
Authors: Nasr-El-Din H. A. , Saiari H. A. , Hashem M. K. , Bitar G. 
Published: December 2007

Abstract

Description of Paper
Calcium carbonate scale was detected in several vertical wells in a sandstone reservoir in Saudi Arabia. The scale was detected downhole, plugging gravel packing screens and the intake of submersible pumps. Scale build up caused significant decline in oil production from this field. The sandstone reservoir is water-sensitive and has a bottom hole temperature of 160°F.
An emulsified scale inhibitor (phosphonate-type) treatment was designed to mitigate scale in this field. Recently, Nasr-El-Din et al.1 discussed the development of this new treatment and reported initial field results. So far the treatment was successfully applied in more than twenty wells. Some of these wells were de-scaled before the treatment, while other wells were treated before scale detection.
The objectives of the present paper are to assess the outcome of this treatment based on field data and to optimize the scale squeeze treatment based on the analysis of well flow back samples. Samples of produced water from these wells were collected and analyzed for nearly three years.
Naphthenate Scale Formation – Examination of Molecular Controls in Idealised Systems
Authors: Dyer S. J. , Graham G. M. , Arnott C. 
Published: December 2007

Abstract
The formation of calcium naphthenate precipitates and emulsions during oil production is becoming an increasing problem to the oil industry. Naphthenic acids, R-CO2H, are present in many crude oils and the hydrophilic nature of the carboxylic acid group means that they congregate at the oil-water interface. As the pressure drops during production and carbon dioxide is lost from solution, the pH of the brine increases, which in turn leads to dissociation of the naphthenic acid (RCO2H –&gt; RCO2–). The naphthenates can then act as natural surfactants leading either to stabilised emulsions or solid deposits following complexation with calcium cations present in the aqueous phase. The naphthenate deposits collect predominantly in oil / water separators and de-salters but can also deposit in the tubing and pipelines.
This study has looked at a variety of conditions to determine when certain carboxylic acids will form naphthenate deposits under idealised laboratory conditions. A range of naphthenic acids of different molecular structure were dissolved in an organic phase (toluene) and mixed with synthetic brines containing a range of calcium concentrations typical of oilfield production waters. These tests have determined that as the size of straight chain carboxylic acids increases so does the amount of naphthenate deposit. Increases in brine pH also increased the amount of deposit. However, the effects of changes in calcium concentration and molecular structure on the formation of naphthenate deposits were more difficult to quantify. The work assists in increasing our understanding of the factors controlling the precipitation of naphthenate solids under controlled conditions and forms the basis for future studies in real oilfield fluids.
Scale Inhibitor Squeeze Treatment in a Tight Carbonate Reservoir - Problems and Solutions
Authors: Al-Qahtani A. M. , Nasr-El-Din H. A. , Raju K. U. 
Published: December 2007

Abstract
Calcium carbonate scale was detected in the majority of wet producers in a tight carbonate reservoir in the northern part of Saudi Arabia. Extensive lab work indicated that a phosphonate-type scale inhibitor was effective in mitigating carbonate scale, as well as sulfate scale that were found in a few wells. Field application of conventional scale squeeze treatment in this field is not an easy task for the following reasons: The formation is tight and water blockage is a serious concern.Formation brine contains high Ca concentrations (up to 19,930 mg/L).The formation contains high TDS (up to 231,262 mg/L); therefore measuring low concentrations of the phosphonate inhibitor is a real problem.Nearly 70% of the field is offshore, which imposes limitation on the volume of fluids that can be used.
As a result of these challenges, several modifications were introduced to conventional scale squeeze treatments, where a large amount of aqueous phase is typically introduced into the formation. Coreflood experiments were used to evaluate various available options to reduce the amount of aqueous phase introduced into the formation and associated problems. Based on the results obtained from these tests, significant changes were introduced to the preflush, main treatment, postflush, and soaking time.
The new modifications were applied at two wet producers in this field. Well Z-C is a vertical well with 70 vol% water cut, 218°F bottom hole temperature, and 78,540 mg/L TDS. Well B is a horizontal well with 5 vol% water cut, 235°F bottom hole temperature and 209,828 mg/L TDS. An extensive wellhead-sampling program was conducted to measure residual scale inhibitor in the produced brines.
Both wells responded positively to the treatment. The new modifications have resulted in better well response. Analysis of phosphonate in the wellhead samples was used to determine the MIC for this field.
The Acid-IER Method – a Method for Selective Isolation of Carboxylic Acids from Crude Oils and Other Organic Solvents
Authors: Mediaas Heidi , Grande Knut V. , Hustad Britt M. , Rasch Anita , Rueslåtten Håkon G. , Vindstad Jens Emil 
Published: December 2007

Abstract
The amount of acidic crude oils produced worldwide is increasing. These oils introduce problems throughout the hydrocarbon value chain due to their high content of carboxylic acids, examples of which are naphthenate deposition in production facilities and refinery corrosion. In order to deal with these problems, it is often necessary to isolate the carboxylic acids in different fluid streams or solids to allow further analysis without interference from other compounds.
This paper presents and verifies an ion-exchange method that can be used for selective isolation of carboxylic acids from crude oils, distillate fractions and other organic solvent. The efficiency and selectivity of the method have been demonstrated as &gt;98 mol-% using two synthetic carboxylic acids. Its usefulness for isolation of carboxylic acids from solids and non-organic solvents has also been demonstrated, exemplified by calcium naphthenate deposits and water.
Steerable Hole Enlargement Technology in Complex 3D Directional Wells
Authors: Rodman Dave , Wong Thomas , Chong Adrian C. 
Published: December 2007

Abstract
The paper describes application of steerable, hole-enlargement technology in a complex 3D directional application. Following repeated failure of Bi-Center bit technology to meet demanding requirements in a number of offshore East Malaysia wells, the Near Bit Reamer (NBR) was used in a variety of BHA configurations to drill six wells for Shell Malaysia-EP. Cuttings Bed Impeller (CBI) tools were also included in the drill string to facilitate hole cleaning and maintain hole quality. The resultant hole profiles enabled good cement bonds to be achieved for the 7⅝" "SMART" liners, and excellent gravel pack results for the 4½" production liners.
In addition to achieving hole enlargement in a single run, compared to multiple-trips for reaming, use of the NBR and CBI tools provided a fast, clean hole that allowed good casing runs. To date, the NBR tool has been utilized on more than 11 highly deviated wells with no stuck BHA occurrences, where prior experience without the NBR/CBI tools produced at least one stuck BHA per well.
Furthermore, efficient hole enlargement operations in this application allows for SMART completion options, with 7⅝" liner instead of 7" liner for multiple completions that allow selective production, an option that was not possible prior to this.
Mercury in U.S. Crude Oil: A Study by U.S. EPA, API and NPRA
Authors: Wilhelm S. Mark , Kirchgessner David 
Published: December 2007

Abstract
The United States Environmental Protection Agency (U.S. EPA), in cooperation with the American Petroleum Institute (API) and the National Petrochemical and Refiners Association (NPRA), has initiated a project to determine the mercury content of crude oil processed in the United States. The focus of the project is to determine the mean concentration and range of concentrations of mercury (total) in crude oil in a statistical fashion. Data generated in the course of the project will be used to estimate an upper limit to the contribution of mercury in crude oil to anthropogenic mercury emissions in the United States. Portions of the project are examining analytical issues, determining concentration variance in crude oil streams and building a database on total mercury concentrations in crude oils processed in the United States.
Limited data are reported that compare three analytical methods used to measure total mercury content in crude oils. The data demonstrate expected analytical method variance, detection limits and mercury species sensitivities. Aspects of the work in progress address questions concerning sampling methods, sample stability and mercury concentration variability in crude oils having a generic market identity. The plan for statistical sampling of crude oils processed in the U.S. is described in general terms.
In addition to the environmental issues, mercury in crude oil has an impact on its market quality (price). Measuring mercury concentrations in crude oil is now becoming more important as mercury's impact on production and processing systems becomes better understood. The EPA/API/NPRA project should assist development of sampling and analysis methods for crude oil and also will assist researchers to study the distribution of mercury in produced fluids throughout production and processing systems.
Hydrocarbon Impacted Soil and Waste Remediation
Authors: Deuel Lloyd E. , Holliday George H. 
Published: December 2007

Abstract
Improper remediation of hydrocarbon releases to soil or hydrocarbon impacted oil and gas field wastes results in conditions that, at the least, cause tension between lessors and surface owners and the operator. Further, unsatisfactory remediation may lead to legal conflicts, which wastes both natural and capital resources. Fortunately, agricultural techniques are available by which most hydrocarbon releases and adverse environmental impacts can be corrected.
The available petroleum hydrocarbons [TPH] remediation methods include biotreating, composting, dilution, dilution burial, road spreading, reuseable resource technology and ultra-violet ray treatment. This paper discusses land treatment and dilution only, because of the authors' desire to provide an in-depth presentation. Other remediation techniques will be discussed in subsequent papers. Typically, acceptable residual TPH concentrations are attained with land treatment within six months. Dilution is even faster.
Most remediation papers provide case histories describing the results of a particular remediation project. Seldom do these papers provide the technology by which the reader can apply the method to another situation. This paper discusses the theory and design aspects of land treatment TPH remediation. The authors conclude remediation to acceptable residual concentrations can be accomplished at most locations. This conclusion is based on the assumption, oil and gas regulators accept time-tested residual concentrations for TPH, e.g., 10,000 to 30,000 mg/kg. Lower concentration can be achieved, but generally are not warranted on an environmental risk basis.