bluuebunny/crossref_metadata_2025_split huggingface dataset:
Targeting High Molecular Weight Wax
Authors: Wei Fang , Acosta Erick , Gawas Kiran , Krishnamurthy Pushkala 
Published: April 2015

Abstract
Wax deposition is one of the major problems for onshore and offshore crude oil production. High molecular weight wax (HMWW) is commonly defined as a wax containing more than 40 carbons in its chemical structure. These types of wax are challenging to treat, as they form hard deposits that can be difficult to remove. Most paraffin inhibitors available in the market currently are not effective at inhibiting the formation and deposition of HMWW in oil production systems. This paper discusses extensive work on understanding HMWW characteristics and chemical methods to treat such deposits. A variety of wax characterization techniques, such as cold finger (CF), differential scanning calorimetry (DSC), cross polarized microscopy (CPM), and high-temperature gas chromatography (HTGC), were used to study the impact of inhibitor chemistry on wax characteristics.
Oil from South Texas with high wax content (8%) was evaluated using five different types of inhibitor chemistry. DSC and CPM were used to obtain the wax appearance temperature (WAT), and CF was used to deposit the HMWW and evaluate inhibition efficiency. HTGC results were obtained from the wax collected from CF to determine carbon distribution of the deposit. DSC of the wax was also performed to obtain the crystallization of the wax and estimate the wax content in the deposit.
Of the five chemistries evaluated, one showed good performance, with approximately 30% inhibition, while two polymers reduced the crystallization temperature and softened the wax deposit. The other two chemicals did not show any effects on the HMWW.
Effect of Environmental Parameters on the Stability and Performance of Oil and Gas Biocides
Authors: Williams Terry M. , Schultz Christine M. 
Published: April 2015

Abstract
The interaction of oil and gas biocides with critical environmental factors directly affects their performance in applications where successful water management practices are essential. These include hydraulic fracturing, water flooding, and water storage and disposal. Effective control of microbial contamination in these applications is required for the sustained quality of the production fluids and structural assets. The microbial groups of concern are sulfate reducing bacteria (SRB), acid-producing bacteria (APB), and facultative anaerobes.
In this study, representative oxidizers and non-oxidizers were tested under environmental parameters of importance including elevated temperature, biological organic matter, and individual process additives (xanthan, guar, polyacrylamide). These parameters represent common conditions which may be present and should be considered when selecting a biocide treatment. Results showed that all biocides have inherent antimicrobial activity versus SRB and APB. The stability and compatibility of these biocides varied widely. Oxidizing biocides, in general, showed good efficacy at low concentrations at room temperature. However, the oxidizers showed poor stability and a loss of activity at elevated temperatures (&gt;40° C). By contrast, several non-oxidizing biocides showed very good stability and efficacy at significantly higher temperatures (60-80° C) providing microbial control for weeks to months. The addition of organic matter and process additives had little effect on the non-oxidizing biocides; however, certain oxidizers were rapidly inactivated and showed varying interaction with the additives. Understanding the compatibility and stability of biocides is critical to their performance and essential to define microbial treatment strategies to provide both rapid topside kill with extended downhole control under typical reservoir conditions.
Study on Abnormal Viscosity Development in High-TDS Produced Water
Authors: Sun Hong , Li Leiming , Mayor John , Carman Paul 
Published: April 2015

Abstract
With limited availability of fresh water, more and more stimulation operations turn to produced water. In such operations, polymers must sufficiently hydrate first to enable effective crosslinking and ensure proppant transportation and placement. On the other hand, produced water from unconventional formations (such as Marcellus and Bakken shales) is famous for its high total dissolved solids (TDS) and high divalent cation content. Produced water contents change from time to time, and from location to location, posing a tremendous challenge in stabilizing the performance of the fracturing fluids prepared in such water. Predictable performance of fracturing fluids made with unpredictable produced water is highly desirable in order to utilize produced water.
This paper will present studies of hydration behavior of non-charged polysaccharides, such as, guar, HPG (hydroxypropyl guar) and HEC (hydroxyethyl cellulose), in water with controlled salinity and multivalent cation concentration, including Ca2+, Mg2+, Fe3+, etc., under various temperatures. The results are surprisingly more complicated than most may assume. For example, higher salinity may suppress linear gel viscosity, while multivalent cations do exactly the opposite. Contrary to the common knowledge that viscosity generally decreases with elevated temperatures, in some temperature ranges, an opposite trend is observed instead; and over a wider temperature range, a U-shaped trend is observed. Such counter-intuitional results will be presented and the mechanism will be explored to explain such observations. Semi-empirical equations will be proposed to predict the viscosity response of polymers in real-world produced water. Results generated in laboratory synthetic high-TDS water are then compared to those obtained in field produced water to validate the study. With systematic studies, optimized formulas of fracturing fluids based on various produced water samples have been found for stimulation operations for unconventional formations and conventional formations as well.
This paper will provide in-depth understanding of effects of a number of produced water ingredients on the performance of the fracturing fluids prepared with produced water, with emphases in areas such as polymer hydration, crosslinking, and high-temperature stability.
Magnetic Nanoparticles for Efficient Removal of Oilfield “Contaminants”: Modeling of Magnetic Separation and Validation
Authors: Prigiobbe Valentina , Ko Saebom , Wang Qing , Huh Chun , Bryant Steven L. , Bennetzen Martin V. 
Published: April 2015

Abstract
In this work, we present the study of an efficient method of separating “contaminants” from water produced from oil reservoirs, using magnetic nanoparticles (MNPs). Micron-scale, highly stable oil droplets as well as divalent cations such as Ca2+ can be removed from the produced water through the adsorption onto functionalized MNPs. The method employs MNPs to initially attach to the oil droplets or to the cations, and then to separate them from the liquid phase using a magnetic field. After separating out the “contaminant”-free water, the MNPs can be regenerated and re-used. As the collection of the contaminant-attached MNPs by the application of magnetic field gradient is a critical step for the process, we developed a 1D mathematical model for the description of the dynamics of the MNP collection in the framework of the sedimentation theory. The conservation equation for MNPs is coupled with the flux function, which accounts for not only gravity force but also magnetic force and Brownian interaction. The model describes both the behavior of colloidal particles during settling and the enhancing effects of the magnetic field due to attraction of MNPs towards a magnet. Simulations were compared with measurements from settling tests of a suspension of MNPs.
New Hydrogen Sulfide Scavenger Development for Downhole Mixed Production Applications - Lab and Field Data
Authors: Lehrer S. , Jovancicevic V. , Braman S.C. , Soos L. , Macleod J. , Kurrasch Jason 
Published: April 2015

Abstract
Production of sour crude oil releases hydrogen sulfide (H2S) into production tubing and surface equipment, causing corrosion, flow assurance issues, safety, and environmental concerns for the producer. As a result, increased costs related to metallurgical upgrades, gas sweetening equipment, increased manpower costs for monitoring, and liability from the potential release of H2S can become significant parts of the total operation cost. These issues can be alleviated if the H2S is reliably removed downhole and prevented from reaching the surface.
Conventional hydrogen H2S scavengers such as triazines or glyoxal are commonly applied by direct injection topside to mitigate H2S in oil and gas production facilities. However, when applied in direct-injection applications, these scavengers exhibit slow kinetics that reduce their effectiveness in short residence-time systems, resulting in a much greater amount required than theoretical efficiency would predict. Neither triazines nor glyoxal are suitable for downhole application because of their low thermal stability and, in the case of triazine, its high scaling tendency.
To achieve reliable and cost-effective removal of H2S topside or downhole, the development of a new scavenger and a new delivery system for downhole application was required. As a result, a new non-triazine, organic acid metal complex-based H2S scavenger (OAC) with high-temperature stability, fast kinetics and quantitative H2S removal was developed. The new delivery equipment comprises an injection skid, H2S monitoring equipment, and an automated chemical dosing system to ensure delivery of the precise dosage required to remove H2S downhole.
Field test results for the new OAC scavenger and delivery system will be presented for mixed production applications, demonstrating the ability of this approach to reliably remove H2S both topside and downhole.
An Alternative to the Capillary Suction Time Test
Authors: Sethi Richa , Hinkel Jerald J. , Mackay Bruce 
Published: April 2015

Abstract
The oil and gas industry has adopted several methods to obtain insight as to how a fluid may affect reservoir material. The Capillary Suction Time (CST) test has become a de facto standard test method, largely due to its simplicity and speed. The most obvious shortcoming of the CST test is that it introduces a medium (paper) that is far different from anything found in an actual reservoir; in fact, one may argue that the CST test is essentially a measure of the interaction of the test fluid with the paper. The lack of theoretical foundation of the CST test precludes reproduceable results or proper estimation of errors in measurement. We present a new test method that observes only intrinsic properties of the formation in contact with a test fluid, bolstered by a strong theoretical basis, in stark contrast to the CST test.
Our method preserves the desirable attributes of the CST test, but replaces imbibition into paper with imbibition into reservoir material. The method uses a comminuted sample, and the results from the imbibition step are used to determine formation wettability in the form of the advancing contact angle. The results from a subsequent drainage test are used to determine the receding contact angle, and the capillary pressure versus saturation curve.
Prior to performing the drainage test, test fluid is placed on top of the saturated pack and the permeability of the pack to the test fluid is determined. The permeability of the pack to liquid is then compared to the pretest permeability of the pack determined using nitrogen. Use of this pack as a testing environment allows the technique to be applied to formation samples of virtually any permeability and porosity.
We have found that there is no correlation between CST test data and the permeability data obtained using the new method presented here. We present several cases in which a positive result from a CST test is inconsistent with the results obtained from the new test method. We maintain that the discrepancies cast serious doubts on the general applicability of the CST test as a tool for studying rock/fluid interactions.
In summary, there is a great need to standardize testing that investigates rock/fluid interactions. The widely used CST method introduces a foreign material and it does not offer sufficient resolution, reproducibility, or estimation of error. Even if the CST method were adequate, the lack of standardization in testing and analysis methodologies makes comparisons of published results difficult.
Our method provides superior results. The strong theoretical foundation of the new method allows rigorous analysis making comparisons between treating fluid options far more trustworthy.
The Evaluation of Polycationic, Carbohydrate-Based Surfactants as Viscoelastic (VES) Fracturing Fluids
Authors: Whitlock Laura , Sanders Aaron , Knox Paul 
Published: April 2015

Abstract
Hydraulic fracturing plays an important role in maximizing the recovery of oil and gas in North America. Viscoelastic surfactant based fluids (VES) are an important class of fracturing fluids (Ghaithan, 2014). They are reputed to cause less formation damage during the fracturing process and break cleaner, leaving less material in the formation to impede the flow of hydrocarbons (Brown, 1996). Cationic surfactants are typically used for this application, but do not exhibit good tolerance to or solubility in the salts used to inhibit clay swelling. They are also not particularly biodegradable and have an unfavorable toxicity profile. Cationic surfactants with an improved ecotoxicity profile as well as improved tolerance to salts are needed. Improved temperature tolerance is also desired, in order to apply to a wider range of well types.
Carbohydrates have the ability to react with a variety of substances and can be conveniently cross-linked to form polycationic materials. As such, molecules can be created that mimic the polymer backbones used in fracturing fluids today, potentially eliminating some of the negative side effects of those same polymers. Carbohydrate-based, polycationic molecules are created from bio-renewable resources such as sucrose and vegetable oils. The incorporation of ether links and short-chain components within these molecules imply a better biodegradation profile and lower toxicity than traditional long-chain cationics.
Several new polycationic, carbohydrate molecules were synthesized in the lab in order to demonstrate the flexibility and range of the chemistry and explore structure-activity relationships. When formulated into viscoelastic fluids, smaller polycationics demonstrated excellent tolerance to salts, at times requiring the presence of salts in order to show viscoelasticity with enough viscosity to suspend proppant. In addition, as the number of crosslinkers per molecule increased, the resultant formulated viscosity increased, however the tolerance to salt decreased.
Determination of the Diffusion Coefficient of Methanesulfonic Acid Solutions with Calcite Using the Rotating Disk Apparatus
Authors: Reyath Sajjaat Muhemmed , Nasr-El-Din Hisham A. , Rimassa Shawn 
Published: April 2015

Abstract
Methanesulfonic acid (MSA) has been proven as a scale remover and, more recently, as a stand-alone stimulation fluid in carbonate acidizing. MSA is a strong alkyl sulfonic acid having a pK value of -1.9, and it dissolves carbonate and oxides with its calcium water-soluble salts. Although the acid has many promising results for acidizing, little is known in relation to its detailed kinetics. This study aims to understand the reaction profile of MSA to provide relevant information to scientists and engineers to design acidizing jobs with this improved fluid.
The dissolution of calcite in MSA was studied with the aid of a rotating disk system at 1000 psig in the temperature range 73-250°F. As a result of this study dissolution rate parameters for this system are reported for the first time. Details of the approach for this study include using marble disks of 1.5-in. diameter and 0.7-in. thickness. The dissolution rate was found by measuring the calcium concentration in the effluent as a function of time using inductively coupled plasma (ICP). The effects of MSA concentrations (5 to 20 wt%), disk rotational speeds (100 to 1500 rpm), and temperatures on the rate of dissolution were also investigated.
Experimental results showed that, within the range of temperatures tested, the dissolution rate of MSA with calcite was mass-transfer limited even at high disk rotation speeds. The diffusion coefficient of a 5 wt% MSA fluid at 150°F was found to be 5.29 × 10−5 cm2/s and at 250°F diffusion coefficient was found to be 3.03 × 10−4 cm2/s. The acid diffusivity increased with increasing system temperature.
Determination of the dissolution rate of MSA will increase the understanding of its performance as a stand-alone stimulation fluid. Its high acidity, high solubility of its calcium salts, and good thermal stability, along with its low corrosivity and readily biodegradable composition makes this acid an attractive alternative to HC1 in designing high temperature acidizing applications.
The Impact of Clay Type on the Asphaltene Deposition during Bitumen Extraction with Steam Assisted Gravity Drainage
Authors: Unal Yasin , Kar Taniya , Mukhametshina Albina , Hascakir Berna 
Published: April 2015

Abstract
The interactions of bitumen with clays are known to cause asphaltene deposition. However, the role of clay type on this interaction remains uncertain. We study this interaction for two clay types at steam temperature. Two Steam Assisted Gravity Drainage (SAGD) experiments at identical experimental conditions are conducted. The reservoir rock for the first experiment (SAGD1) is prepared with sand (85 wt%) and kaolinite (15 wt%) mixture and the second experiment (SAGD2) with sand (85 wt%), kaolinite (13.5 wt%), and illite (1.5 wt%). The effectiveness of the steam chamber growth does not change with the clay type, however, 15 wt% less oil is recovered with SAGD2. The possible reasons are investigated through the contact angle, particle size, zeta potential, and interfacial tension measurements on produced oil, produced water, and spent rock. The spent rock samples are analyzed by X-Ray Diffraction (XRD) and Scanning Electron Microscope (SEM) analyses. The contact angle measurements on the spent rock sample display the higher oil-wetness for SAGD2 than SAGD1. However, the water-wetness of illite is known to be higher than kaolinite. This unexpected result is explained by the interaction of illite and the asphaltenes from SAGD2. The asphaltenes both from produced oil and residual oil separated and qualitative analyses are conducted with Fourier Transform InfraRed (FTIR). FTIR results confirm the presence of clay in the produced oil asphaltenes of SAGD2. The particle size measurements along with SEM images on postmortem samples reveal that illite containing clay exhibits cementation behavior at steam temperature, hence, reduces the permeability of the system. According to the experimental results, we developed hypotheses to understand the bitumen-illite and bitumen-kaolinite interactions for SAGD. Due to the high water-wetness of illite, illite particles first interact with steam. This interaction results in cementation and forms illite lumps with sand. And then, illite lumps continue to interact more vigorously with the polar molecules (water, asphaltenes, and resins). Clay migration and production occur in both clay types, however, while kaolinite is produced in the water phase, illite containing clay due to its interaction with asphaltenes produced in the oil phase.
Surfactant-Enhanced Oil Recovery from Fractured Oil-wet Carbonates: Effects of Low IFT and Wettability Alteration
Authors: Chen Peila , Mohanty Kishore K. 
Published: April 2015

Abstract
The performance of surfactant-enhanced oil recovery (EOR) in fractured carbonates relies on spontaneous imbibition or low IFT-aided gravity drainage. This work investigated the synergism between wettability effects and IFT reduction mediated by a variety of surfactants through experiments and numerical simulation studies. Experiments have shown that oil can be recovered from oil-wet Silurian dolomite fracture blocks either by capillarity driven imbibition, gravity-driven imbibition or low tension-aided gravity drainage. The mixture of wettability alteration (WA) surfacant with IFT reduction surfactant exhibits the synergistic effect on the imbibition oil recovery from oil-wet carbonate rocks. It was found that divalent ion scavengers help the wettability altertion capability of some sulfonate surfactants in hard brine, which leads to the high oil recovery up to 70% OOIP (IFT+WA), compared with oil recovery of 30-50% OOIP by sulfonate surfactant only (only IFT reduction). We proposed a mechanism that the presence of a sufficient amount of divalent ion scavengers in the anionic surfactant formulation reduces the free divalent cations in hard brine, which then promotes the release of surfactant monomers from the micelles and enhances wettability alteration by surfactant adsorption. The UTCHEM simulation results confirmed the existence of synergism between IFT reduction and WA in spontaneous imbibition processes. According to the capillary desaturation curve (CDC), that residual oil saturation after gravity drainage is approximately 10% to 20% higher than gravity-driven spontaneous imbibition when two processes have the similar trapping numbers, confirming that the wettability alteration contributes to the ultimate oil recovery.
High Active Aqueous-Based Pour Point Depressants and Wax Inhibitors
Authors: Potisek Stephanie , Capaldo Kevin , Dermody Dan , Moglia Robert , Ender Kacee 
Published: April 2015

Abstract
Paraffins are linear and branched aliphatic molecules (&gt;C18) present within crude oil. As crude oil cools upon exiting a well, the paraffins can gel or precipitate and ultimately cause pipelines to plug. The result is costly downtime in production as the pipelines are cleaned or repaired. One solution to address this challenge is chemical prevention, namely the use of wax inhibitors and pour point depressants.
Traditionally wax inhibitors and pour point depressants are organic solvent-based materials that contain a low concentration of active inhibitor (approximately 5% active in a solvent such as toluene). In this work, newly developed high concentration (&gt;30% active) aqueous-based wax inhibitors and pour point depressants will be discussed.
These formulations are stable dispersions of active copolymers in water and can be freeze-protected to −40°C, enabling their use in arctic environments. There is also an advantage of reduced logistics costs, decreased storage space and the absence of flammable solvents. Additionally, the replacement of organic solvent with water makes these materials more environmentally friendly and less expensive to dilute during application. The physical properties and stability of these materials throughout a broad temperature range from −40°C to 125°C will be discussed. The performance of these innovative materials on various crude oils will also be presented. Up to a 30°C reduction in the pour point temperature was observed. This unique combination of properties and significant reduction in pour point temperatures is a novel advancement in flow assurance technology.