bluuebunny/crossref_metadata_2025_split huggingface dataset:
Formate Brines and their Crystallization Temperatures - New Insight into Fluid Behavior and Measuring Methodology
Authors: Howard Siv , Chrenowski Marcin 
Published: April 2015

Abstract
Ever since formate brines were introduced in the oilfield in the 90's, test laboratories have struggled to determine their True Crystallization Temperature (TCT). The standard API procedure for measuring TCT in oilfield brines simply does not work in formate brines, and it is quite common to see TCT values reported as “too low to measure” even in cases where reference to other studies suggests that the TCT should be well within the measureable limit of the equipment. Factors that complicate the TCT measurements in formate brines are: a) the TCT values can be very low, and may be lower than the cooling capabilities of the measuring equipment, b) an enormous amount of supercooling, and c) the existence of metastable potassium formate crystals that form in formate brines that are rich in potassium formate.
A long-term research program has been aimed at understanding the unusual TCT behavior of potassium formate brine and developing a method to measure the TCT of all formate brines. This research program has delivered an accurate TCT determination procedure for formate brines that is simple, efficient, and involves no specialized equipment. The researchers found that special crystal seeding procedures were needed to get accurate TCT measurements in formate brines. Intelligent crystal seeding eliminates the TCT measurement problems caused by the formation of metastable phase crystals and supercooling.
In addition to full description of an accurate TCT measurement method for formate brines, this paper presents a complete set of TCT values for sodium, potassium, and cesium formate single salt brines and some cesium/potassium formate blends.
Improved Fluid Technology for Stimulation of Ultrahigh-Temperature Sandstone Formation
Authors: Rignol Joel , Ounsakul Thanawit , Kharrat Wassim , Fu Dan , Teng Ling Kong , Lomovskaya Irina , Boonjai Pimterra 
Published: April 2015

Abstract
Acid stimulation is one of the production enhancement methodologies applicable in both development and exploration fields. Sandstone acidizing requires a sophisticated and well-studied approach to avoid formation damage caused by acid precipitation. Although the industry has made significant technical advancements in treatment fluids over the past decades, high bottomhole temperature still presents one of the biggest challenges.
A new chelant-based fluid system was tailored to stimulate sandstone formation effectively under ultrahigh-temperature conditions. The new system has been evaluated extensively in the laboratory.
Laboratory work included sequential dissolution, chemical analysis, and core flow tests. Both dissolution and core flow tests were conducted up to 400°F with reservoir core samples to simulate the actual reservoir condition and treatment design.
Sequential dissolution results indicated that the new chelant-based system dissolved clay minerals in each sequence without causing silica precipitation due to secondary and tertiary reactions. The increase in the permeability of the reservoir core after core flow tests further demonstrated that the new fluid system is indeed highly effective in removing the damaging clay particles. The major advantage of the new chelant-based system is that it can be pumped in a single stage, which has greatly simplified the field operation and diversion requirement. In addition, because of its mild pH, the new system has low corrosion rate and less tendency to emulsion and sludge formation. This new system is HCl acid free, and therefore it eliminates the high risk of silica precipitation due to reaction with sensitive clays at high temperature. Last, but not least, the chelant fluid is consists of a retarded HF system which enables deeper radial penetration with less near-wellbore deconsolidation and which doubles the effect of clay dissolution and stabilization.
How to Monitor Scale Inhibitor Squeeze Using Simple TRF Tracers
Authors: Martini Matteo , Brichart Thomas , Marais Arthur , Moussaron Albert , Tillement Olivier , Baraka-Lokmane Salima 
Published: April 2015

Abstract
Mineral scale deposition in oilfield reservoirs has caused millions of dollars in damage every year. The most common remedy to the build-up of scale inside well bores and the surrounding reservoir is the periodical “squeeze” treatment by inhibitor additives. The real-time and on-site control of inhibitor concentration during production remains one of the big challenges. Indeed, current techniques of inhibitor monitoring that use elemental analysis appear too complex for an efficient long-term industrial solution. With this in mind, we have developed a simple and accurate method for scale inhibitor quantification in production waters based on the use of time-resolved fluorescence (TRF) tracers. The characteristic luminescence signature (lifetime value, emission and excitation spectra) of TRF tracers allows the reliable tracking of inhibitors additives. Moreover, their long-lifetime luminescence signal can significantly increase the signal to noise ratio thanks to the suppression of organic oil residual background emission. Our experimental tests on produced water collected from different sites confirm the detection of a larger variety of inhibitors i.e. for carboxylates, phosphonates and sulphonates by simple post-chelation with TRF tracers at low concentration. Indeed, the non-fluorescent inhibitor species have been switched to fluorescent compound by the addition of few amounts of tracer in order to be detectable and quantified at sub-ppm concentrations. The coupling between TRF tracers and specific TRF spectrofluorometer apparatus then open new and accurate ways for the online and/or on-site monitoring of scale inhibitors for better risk management of flow assurance during production.
Crosslinking of Guar and HPG Based Fracturing Fluids Using ZrO2 Nanoparticles
Authors: Hurnaus Thomas , Plank Johann 
Published: April 2015

Abstract
Hydraulic fracturing requires the use of highly viscous gels which are achieved by crosslinking guar gum or its derivatives with boron, zirconium and titanium compounds. Commonly used zirconium complexes contain chelate ligands such as e.g. triethanolamine or lactate. While many different Zr crosslinkers have been developed, their working mechanism has not received much attention. In our study, we focused on the crosslinking of guar and hydroxypropyl guar gum (HPG) with Zr(IV) triethanolamine and lactate complexes. Their interaction with the polysaccharides was studied via particle size measurements, spectroscopic methods and transmission electron microscopy (TEM).
It is commonly perceived by the industry that the crosslinking effect of Zr complexes is based on a ligand exchange reaction involving the cis-hydroxyl groups present in guar and HPG. To investigate on this concept, HPG and zirconium lactate were chosen as model system. The polysaccharide and the crosslinker were mixed at low pH where no crosslinking occurred and at higher pH values (&gt; 7) where crosslinking took place. When crosslinking had occurred, IR spectroscopy confirmed that the Zr complexes had hydrolyzed and the lactate ligand had been released suggesting that potentially a ligand exchange reaction had taken place. However, TEM images clearly evidenced the formation of almost monodisperse ZrO2 nanoparticles. Numerous such nanoparticles were found within the gelled HPG. In contrast, when no crosslinking had occurred, almost no ZrO2 nanoparticles could be detected.
Based on the observation that the nanoparticles are responsible for the crosslinking of guar, zirconia nanoparticles were synthesized separately and added to guar solutions. Their crosslinking performance was comparable to that of the Zr lactate complex, thus proving that the nanoparticles induce the crosslinking effect. Additional tests revealed that the size of the ZrO2 nanoparticles is a key factor for their crosslinking effectiveness. Particularly small particles (d ~ 3 nm) are most effective while larger particles (d ≥ 10 nm) no longer can crosslink guar.
Application of a Novel Method for Real-Time Monitoring of Scale Control Products at the Site of Use
Authors: Johnstone James , Peltokoski Brita , Toivonen Susanna , Griffin Rick , Hurd Michael , O'Brien Ashleigh , Fournier Frances , Siivonen Joonas , Väisänen Pave , Tittanen Satu , Lehmusto Mirva , Mäkinen Piia , Wahrman Jonas , Mundill Paul 
Published: April 2015

Abstract
Operators in the oil and gas industry make extensive use of scale inhibitors to provide the level of flow assurance required to maximise safe and economic hydrocarbon production. For continuous and scale squeeze treatments, field operators need to verify the residual inhibitor concentrations regularly to ensure that the implemented scale management program remains effective. Sulfonated polymers are effective and widely used sulphate (barium, strontium, calcium) scale inhibitors, however detection of residual (less than 15 ppm) amounts has been problematic, leading to the use of an overdose on continuous applications or resqueezing before reaching the minimum effective dosage (MED) level.
The authors have developed a testing protocol that enables measurement of the residual concentration of polymeric scale inhibitors at the point of use and directly in produced water, providing a timely and accurate scale inhibitor concentration to the facility operator. Field operators with minimal training use sample preparation protocols that are minimized and standardized to determine polymer concentrations within 15 minutes down to 1 ppm active polymer. The testing protocol uses an aqueous liquid fingerprinting technology platform to detect a range of scale inhibitor products and provides direct field analysis for either continuous or scale squeeze application programs. Operators determine the residual scale inhibitor level at the point of use, eliminating the cost and time delay of shipping samples to a remote analytical laboratory.
We previously presented laboratory results of this technology (Johnstone et al. 2014). In this paper, we present the results of the performance of this system in actual field operation which was completed late 2014 at oil and gas production locations and validated at an analytical laboratory. The results demonstrate the benefits of the protocol in field applications in monitoring residual levels to a level of accuracy for polymeric scale inhibitors previously only achievable in fully equipped analytical laboratories.
This technology has been demonstrated to the oil and gas industry and has generated significant interest in a number of communities for which monitoring polymeric scale inhibitors at concentrations less than 5 ppm active is a business-critical activity. The validity of the protocol has been confirmed by ongoing work across a number of application areas, supporting the global industry challenge of scale control.
Propagation of Carbon Nanotube Hybrids through Porous Media for Advancing Oilfield Technology
Authors: Kadhum Mohannad J. , Swatske Daniel P. , Chen Changlong , Resasco Daniel E. , Harwell Jeffrey H. , Shiau Ben 
Published: April 2015

Abstract
Carbon nanotube hybrids (CNTs) have attracted research interest due to their interfacial activity. CNTs can stabilize emulsions and foams and can be used as contrast agents or tracers in rock matrix. In addition, catalytic functionalities can be attached to the nanotubes making them delivery vehicles for catalyst into zones deep inside the reservoir.
Generating stable dispersion of CNTs in harsh reservoir conditions has been the main challenge for utilizing the tubes in in-situ reservoir applications. This is because the dispersed tubes tend to form aggregates that settle down in the presence of high ionic strength (high salinity) brines. In this work, stable dispersion of carbon nanotubes prepared in reservoir fluids is realized by successfully separating individual tubes using such additives as polymers and surfactants. For example, the CNTs would be well dispersed via sonication with highly polarizable polymer such as polyvinyl pyrrolidone (PVP) or Gum Arabic (GA). To mitigating their agglomeration, a secondary additive such as hydroxyethyl cellulose (HEC) polymer is also added to provide adequate steric repulsion for their propagation in porous media at high salinity brines. The nanotube dispersion generated using these dual polymer system is able to deliver successfully through both consolidated cores (200mD permeability of Berea sandstone) and sand pack experiments (4D permeability) with minimal retention at mimic reservoir conditions (65°C and brine compositions of 8% NaCl and 2% CaCl2). Results of the eluted nanoparticles indicate that greater than 80% recovery of injected concentration observed in both consolidated and non-consolidated porous media. Small adsorbed amount of nanotubes is capable of saturating the adsorption sites inside porous media resulting in complete propagation of subsequent injections; this is corroborated by nanotube concentrations approaching 100% of the injected concentration after few pore volumes of injection.
Experiments also demonstrated that in the presence of residual oil inside crushed Berea sandstone sand columns, the extent of nanotubes adsorption to the oil/water interface is a function of the level of oil saturation.
This work is providing insight about the full potential of using carbon nanotubes in oilfield development applications.
First 100% Reuse of Bakken Produced Water in Hybrid Treatments Using Inexpensive Polysaccharide Gelling Agents
Authors: McMahon Blake , MacKay Bruce , Mirakyan Andrey 
Published: April 2015

Abstract
The modern horizontal multistage well is a main contributor to the recent transformation of North American oil and gas production. The large fracturing stage volume that defines unconventional wells, crossed against the increasing numbers of stages and laterals per pad, has dramatically increased the demand for fracturing materials such as sand, friction reducers, and gelling agents, and most especially water. At the same time, operators face increasing accumulations of produced water, which presents as water cut from more mature assets. It is therefore natural to propose using produced water as mixwater for fracturing fluids in new completions, but in practice this plan has met with two major barriers: first, regulatory and logistical hurdles concerning the storage, handling, and potential environmental impacts of the volume of produced water required to complete a modern well (millions of gallons per lateral), and second, technology gaps in the applied chemistry of completion fluids, particularly in crosslinked gels.
This paper reports the completion of a two-lateral well in the Williston Basin where produced water, filtered but otherwise untreated, was used throughout the slickwater and crosslinked components of about sixty hydraulic fracturing stages.
Proppant was successfully placed in all perforated zones in the Bakken and Three Forks formations, using a “hybrid” design that employed seven million gallons of water (of which 2.2 million gallons were crosslinked). Production figures for the well are satisfactory, and this is discussed in the context of fluid-related completion quality. This paper will concentrate on the development and implementation of a metal crosslinked fracturing fluid that shows excellent stability at typical Bakken conditions. We will present a comparison to conventional guar-borate systems.
The promise of this approach has many potential benefits. First, completion costs are decreased as freshwater sourcing and produced water disposal charges cancel each other. Second, far fewer truck trips are necessary to transport water. Third, the industry no longer requires fresh water sources or disposal wells where this technique is employed.
Low Salinity Surfactant Flooding – A Multi-Mechanistic Enhanced Oil Recovery Method
Authors: Tavassoli Shayan , Korrani Aboulghasem Kazemi , Pope Gary A. , Sepehrnoori Kamy 
Published: April 2015

Abstract
We have applied UTCHEM-IPhreeqc to investigate low salinity waterflooding and low salinity surfactant flooding. Numerical simulation results have been compared with laboratory experiments reported by Alagic and Skauge (2010). UTCHEM-IPhreeqc combines the UTCHEM numerical chemical flooding simulator with IPhreeqc, the United States Geological Survey geochemical model. The IPhreeqc model was coupled to UTCHEM to model low salinity waterflooding as a function of geochemical reactions. The surfactant coreflood experiments were done in vertical cores without using polymer or other mobility control agents. These experiments were done at a velocity greater than the critical velocity for a gravity-stable flood. After history matching the experiments, additional numerical simulations of surfactant floods at the critical velocity were run to estimate the performance under stable conditions. We also simulated a surfactant flood at higher salinity with lower IFT and compared the results with the low salinity surfactant flood. These results provide new insights into low salinity waterflooding and surfactant flooding.
Scale Prediction and Control at Ultra HTHP
Authors: Kan A.T. , Dai Z. , Zhang F. , Bhandari N. , Yan F. , Zhang Z. , Liu Y. , Tomson M.B. 
Published: April 2015

Abstract
Production from deepwater environment often encounter ultra high temperature, pressure (ultra HTHP) and with more exotic fluid compositions. Most scale prediction programs were developed by semiempirically modeling the thermodynamic parameters using experimentally measured mineral solubilities and other chemical properties. However, the experimental data were limited at temperature, pressure, and ionic strength that were clearly below that typically encountered in deepwater production. Therefore, extending the existing thermodynamic models to HTHP applications is of questionable accuracy. Furthermore, the partitioning of H2O, CO2, and H2S in and out of the gas/oil phases during production can have a significant impact on scaling tendency. The authors have published papers on experimental solubility measurements and thermodynamic modeling to extend the solubility data to HTHP condition. The new thermodynamic parameters and a flash calculator that integrate the latest development of Equation of State (EOS) to model the partition of H2O, CO2, and H2S in hydrocarbon/aqueous phases at temperature and pressure have been incorporated into a scale prediction software that is specifically tailored for oil and gas production application.
The objective of this paper is to validate the software's application range with a set of critically evaluated peer-reviewed mineral solubility data for general oilfield produced water and deepwater HTHP application. A total of 73 selected papers and more than 2,500 individual experimental data points were included in this evaluation. Our model has been shown to be applicable to greater than 95% of produced water compositions with SI prediction of better than ±0.03 for halite, ±0.05 for gypsum, ±0.1 for calcite and anhydrite, and ±0.2 for barite at temperature between 32 - 500 °F, and and pressure between 14.7 to 22,000 psia. The newly incorporated flash calculator is capable of predicting how CO2, H2S, and H2O partition in and out of the gas phase during production. The partitioning of CO2, H2S, and H2O between the hydrocarbon and aqueous phases has significantly changed the ion composition and pH and therefore, impacted the scaling tendency of the fluids at the production temperature and pressure. This is a particularly important issue for newer wells with high volumes of gas and low water cuts and for CO2 flooding.
Development of a Novel Biofilm Testing Method.
Authors: Keller-Schultz Carrie , Barron-Aldana Jesus , Peter Cruz St. , De Paula Renato M. , Keasler Victor V. , Grieme Linda , Nguyen Duc 
Published: April 2015

Abstract
Several issues associated with microorganisms found throughout the petroleum industry include microbial influenced corrosion (MIC), biotic souring, and biofouling. Traditional methods for evaluating biocide efficacy within the petroleum industry have been focused specifically toward the planktonic, or free-floating, microorganisms. The sessile population, or the community of microorganisms contained within the biofilms that adhere to each other on a surface are not adequately assessed. Since microorganisms contained within biofilms can contribute to all three major microbial issues in the oilfield and the complexity of the microbial community effects the chemical treatment strategy, there is an increased importance associated with the ability to develop a representative, mature biofilm in a lab setting in order to evaluate the efficacy of the chemical treatments prior to implementation in the field. Currently, there are a variety of laboratory methods designed to grow biofilms. However, these methods suffer from many drawbacks. This includes large quantity of fluid required to achieve a once-through system, the number of samples available to test, and the reproducibility of the biofilm growth itself. The purpose of this paper will be to introduce a novel method that will allow for an increased scalability, reproducibility, and utility in laboratory biofilm studies. This knowledge will help in a better understanding of biofilms and facilitate the development of treatment strategies targeting biofilms.
Advances in Tools to Monitor Souring and Corrosion in Oil and Gas Fields
Authors: An Annie , An Dongshan , Elliott Alexander , Menon Priyesh , Shen Yin , Voordouw Gerrit , Cote Dominic E. , Miner Kirk 
Published: April 2015

Abstract
Microorganisms contribute to souring and corrosion in oil and gas field systems. Biocides and/or nitrate can be used to mitigate the negative effects associated with these microbial activities. In order to determine the success of or the need for these measures we use a number of analytical tools on aqueous or solid field samples: (i) spectrophotometric and HPLC assays are used to monitor key analytes (sulfate, sulfide, nitrate, nitrite and others), (ii) microbial assays are used to determine numbers and activities of key microbes and (iii) sequencing of PCR amplicons, typically of a portion of the 16S rRNA genes is used to determine microbial community compositions in field samples. The trick is to combine the information to arrive at a comprehensive view of what is happening and what action may be needed. For instance, a shale gas and a shale oil field in North West Canada, appear to have similar water chemistry. Both are highly saline but halophilic (salt loving) SRB were only found in samples from the shale oil not in those from the shale gas field, which appears related to the different temperatures in these fields of 30-35°C and 75-100°C, respectively. Hence, mitigation measures aimed at killing bacteria downhole may be appropriate for these shale oil but not for these shale gas environments.