bluuebunny/crossref_metadata_2025_split huggingface dataset:
Insight of New Eco-Friendly Acidizing Corrosion Inhibitor: Structure and Inhibition of the Indolizine Derivatives
Authors: Yang Zhen , Wang Yefei , Wang Renzhuo , Chen Wuhua , Ding Mingchen , Zhan Fengtao , Hou Baofeng 
Published: March 2019

Abstract
Propargyl alcohol, at great expense and with high toxicity, is often used as an essential synergistic component of corrosion inhibitors for acidizing; however, in our recent work, a novel indolizine derivative was found to exhibit effective protection performance without the synergism of propargyl alcohol. These indolizine derivatives were easily prepared from quinoline, pyridine, and several halide compounds via 1,3-dipolar cycloaddition reaction. The derivative could prohibit the corrosion of metal at an extremely low concentration and fulfills the requirements of increasingly stringent environmental standards. The inhibition performance of the indolizine derivatives to N80 steel was investigated in 15 wt.% HCl and 20 wt.% HCl by weight loss measurements, potentiodynamic polarization method (Tafel curves), and electrochemical impedance spectroscopy (EIS).
In the absence of propargyl alcohol, when the dosage of indolizine derivatives in 15 wt.% HCl is 0.1 wt.%, the inhibition efficiency of N80 steel increases to approximately 99% at 90 °C. The indolizine derivative shows a superior anti-corrosion performance at a much lower concentration than that of benzyl quinolinium chloride (BQC, a commonly used compound in current acidizing corrosion inhibitors), which serves as the precursor to indolizine derivatives. More importantly, these protective indolizine compounds behave better than the synergistic inhibitor propargyl alcohol. The reinforced active adsorption groups in indolizine derivatives could provide extra adsorption sites and fasten the inhibitive molecule to the steel surface, thus augmenting the protective effect. Here, a new inhibitive indolizine derivative is presented as an acidizing inhibitor that may also offer a low-pollution technique for corrosion prevention.
Novel Laser-Hydrothermal Apparatus for Nucleation and Inhibition Study of Scale Minerals at Temperatures up to 250°C
Authors: Deng Guannan , Kan Amy T. , Zhang Fangfu , Lu Alex Y. , Tomson Mason B. 
Published: March 2019

Abstract
In this work a new laser-hydrothermal apparatus is designed to evaluate nucleation of scale minerals at temperature up to 250°C, its reliability is proven by measuring induction time data of barite from 90°C to 250°C at various Saturation index (SI) values, with the objective that such a design would contribute to the scale-related research at extreme temperature.
Background solution (e.g. 1m NaCl) in a borosilicate glass bottle was placed inside a hydrothermal reactor. GC oven was used for temperature control and a modified Nd-Fe-B magnetic stirrer under the oven was used for stirring. A PFA tubing was selected to be the part with contact with solution for corrosion control. Using a 0.5 ml sample loop in two separate 6-ways switch valves, Ba2+ and SO42-concentrated solutions were simultaneously injected into a background solution. After supersaturation was initiated, a laser beam penetrated through the sight glasses installed on the both sides of the reactor to record the turbidity change during the nucleation process.
Induction time (tind) of Saturation index (SI) values from 0.34 to 1.02 was measured at temperatures from 90°C to 250°C. Data correlates well with data from previous laser test at 90°C in a regular beaker experiment. The induction time (tind), that is, how fast a supersaturated solution induces nucleation and crystal growth to form detectable turbidity, decrease with temperature at a fixed SI value. For example, tind of 93 minutes at 150°C decreases to about 2 minutes at 250°C under the the same SI value of 0.65, indicating that increasing temperature facilitates the nucleation process at certain supersaturation levels. This temperature impact can be attributed both by thermodynamics and kinectic aspects.
Impact of Temperature on Fluid-Rock Interactions During CO2 Injection in Depleted Limestone Aquifers: Laboratory and Modelling Studies
Authors: Azuddin Farhana Jaafar , Davis Ivan , Singleton Mike , Geiger Sebastian , Mackay Eric , Silva Duarte 
Published: March 2019

Abstract
When CO2 is injected into an aquifer, the injected CO2 is generally colder than the reservoir rock; this results in thermal gradients along the flow path. The temperature variation has an impact on CO2 solubility and the kinetics of any mineral reactions. Core flood experiments and associated reactive transport simulations were conducted to analyse thermal effects during CO2 injection in a dolomitic limestone aquifer and to quantify how CO2 solubility and mineral reactivity are affected.
The experiments were conducted by injecting acidified brine into an Edwards Limestone core sample. A back pressure of 400 psi and injection rates of 30 mL/hr and 300 mL/hr were used. A range of temperatures from 21 °C to 70 °C were examined. Changes in the outlet fluid composition and changes in porosity and permeability were analysed. A compositional simulation model was used to further analyse the experiments. The simulations were history-matched to the experimental data by changing the reactive surface area and the kinetic rate parameter. The calibrated model was then used to test the sensitivity to CO2 injection rate and temperature.
The impact of temperature on CO2-induced mineral reactions was observed from changes in mineral volume, porosity and permeability. The reaction rate constants estimated from the outlet solution concentrations are much lower than existing data for individual minerals. The estimated specific surface areas for carbonate minerals are in reasonable agreement with published values. The numerical investigations showed that at the lower temperatures, despite the reaction rates being slower, the solubility of the minerals was higher, and so as a result of these competing effects, moderately elevated calcium and magnesium concentrations were observed in the effluent. At higher temperatures, the solubilities of the minerals were lower, but now the reactions rates were higher, so similar effluent concentrations could be achieved. However, at higher flow rates, characterized by a lower Damköhler number, the residence times were shorter, and so lower effluent concentrations were observed. Additionally, the solubilities of calcite and dolomite varied to different extents with temperature, and so the calcium to magnesium molar ratio in the effluent brine increased with increasing temperature.
The change in mineral composition during CO2 injection varies between the near well zone and the deeper reservoir. Near the well where the temperatures will be lower, solubilities are elevated, but the kinetic reaction rates and residence times will be lower, somewhat limiting dissolution. Deeper in the aquifer the solubilities will be reduced and residence times will be longer, enabling an equilibrium to be established. Modelling is thus required to connect these flow regimes.
Scale Prediction and Mineral Solubility Under HPHT Conditions
Authors: Nichols David , Goodwin Neil , Graham Gordon , Frigo Dario 
Published: March 2019

Abstract
Accurate scale prediction modelling is only possible when reliable mineral solubility data are available under the required conditions. It is recognised that the relative paucity of high pressure, high temperature (HPHT) solubility data can result in inaccurate predictions as current models extrapolate from data obtained under more conventional conditions. This paper describes the generation of additional fundamental solubility data under HPHT conditions and comparison of the obtained values with several existing models.
A purpose-built laboratory test rig capable of making mineral solubility measurements up to 250 °C (480 °F) and up to 30,000 psi has been used in this work. Experimental solubility data have been generated for calcium sulphate at different temperatures and the methodology has been investigated to ensure that equilibrium conditions have been reached. In this work, barium sulphate solubility data have also been generated at conditions up to 200 °C (390 °F) and 19,000 psi. Notably, the solubilities have been determined in the presence of relatively high concentrations of additional ions, e.g., calcium, as it was recognised that available data were limited for more oilfield-representative brine compositions from HPHT reservoirs. The data generated were also compared against solubility predictions for a range of industry models to assess their accuracy in these circumstances.
The results obtained for calcium sulphate solubility indicate the importance of validating the test methodology, not just for each mineral, but also under the required temperature and pressure conditions, to verify that equilibrium solubility conditions have been achieved. Barium sulphate solubility increases with the addition of other divalent ions but the extent of the increase is at present not accurately predicted by existing scale prediction models at HPHT conditions. In some cases, the predicted barium sulphate solubility was up to three times greater than the experimentally determined value. It is apparent that there is considerable scope for improvement of scale prediction models under HPHT conditions particularly in complex brine systems and that further fundamental solubility data are required to facilitate this.
This paper provides additional data for mineral solubility under HPHT conditions but, more importantly, shows data for complex brines that are more representative of those produced in oilfields. The work further demonstrates the limitations of existing scale prediction modelling software under HPHT conditions, particularly in the presence of other divalent ions, and illustrates areas where additional data and model development is critical to enable more accurate modelling of scale risk under these conditions.
Experimental Investigation of Particulate Polylactic Acid Diversion in Matrix Acidizing
Authors: Shirley Robert Mark , Hill A. D. 
Published: March 2019

Abstract
Polylactic Acid (PLA) is increasingly used in the oil industry and specifically for diversion in matrix acidizing as evidenced by a number of field cases recently published. The solid polyester is particularly attractive due to its ability to degrade in the presence of water and heat, negating the need for cleanup fluids or complicated procedures. A majority of the analysis on the effectiveness of PLA thus far comprises experiments on artificially created slots, filter cake analysis, and field trials. This paper demonstrates the effect of PLA in wormholes developed by acidizing outcrop cores.
In these experiments, a wormhole is generated in a portion of the core by limiting the amount of acid injected. Next, the PLA is injected into the core using a heavy brine suspension. Finally, more acid is injected until a wormhole breaks through the core. Computer Tomography (CT) scans are taken, and the pressure drop across the core is recorded at each stage. Experiments were conducted for a variety of initial wormhole lengths.
It can be difficult to suspend PLA while injecting it through a core in a way that is benign to the core, acid, and PLA; and in a way that does not add any pressure drop or diversion due to viscosity changes. This paper describes and justifies a suitable method of keeping PLA suspended to allow its use in core flood experiments. The CT scans show that even when the PLA plugs the wormhole, additional acid tends to continue to develop the dominant wormhole. The pressure drop profiles show that the pressure drop due to PLA injection is proportional to the mass of PLA, both in the wormhole and on the core surface. The pressure profiles also show that there is an increased pressure drop due to PLA in the wormhole versus in a filter cake on the surface.
This paper details a new method of visualizing and analyzing the effect of PLA in a multistage acidizing treatment. Empirical correlations are presented for estimating the pressure drop caused by PLA, both as a filter cake on the formation surface and as a filling inside wormholes. The correlations were incorporated in a comprehensive carbonate acidizing model to predict the diversion efficiency of PLA particles. The simulation is verified using published field trials of diversion treatments.
Simulation Study of Scale Management During Hydraulic Fracturing in Unconventional Reservoirs
Authors: Abouie Ali , Sanaei Alireza , Sepehrnoori Kamy 
Published: March 2019

Abstract
Geochemical scale formation and deposition in reservoir is a common problem in upstream oil and gas industry, which results in equipment corrosion, wellbore plugging, and production decline. In unconventional reservoirs, the negative effect of scale formation becomes more pronounced as it can severely damage the conductivity of hydraulic fractures. Hence, it is necessary to predict the effect of scale deposition on fracture conductivity and production performance.
In this work, an integrated reactive-transport simulator is utilized to model geochemical reactions along with transport equations in conventional and unconventional reservoirs considering the damage to the fracture and formation matrix. Hence, a compositional reservoir simulator (UTCOMP), which is integrated with IPhreeqc, is utilized to predict geochemical scale formation in formation matrix and hydraulic fractures. IPhreeqc offers extensive capabilities for modeling geochemical reactions including local thermodynamic equilibrium and kinetics. Based on the amount of scale formation, porosity, permeability, and fracture aperture are modified to determine the production loss. The results suggested that interaction of the formation water/brine and injection water/hydraulic fracturing fluid is the primary cause for scale formation. The physicochemical properties such as pressure, temperature, and pH are the secondary cause affecting scale formation in the reservoir.
During hydraulic fracturing, precipitation of barite and dissolution of calcite are identified to be the main reactions, which occur as a result of interaction between the formation brine, formation mineral composition, and injection water/hydraulic fracturing fluid. Calcite dissolution can increase the matrix porosity and permeability while barite precipitation has an opposite effect. Therefore, the overall effect and final results depend on several parameters such as HFF composition, HFF injection rate, and formation mineral/brine. Based on the fracturing fluid composition and its invasion depth in this study, the effect of barite precipitation was dominant with negative impact on cumulative gas production. The outcome of this study is a comprehensive tool for prediction of scale deposition in the reservoir which can help operators to select optimum fracturing fluid and operating conditions.
The Development and Field Test of High Efficient Foam Unloading Agent Based on Gemini Surfactant and Nanomaterials
Authors: Junwen Wu , Wenfeng Jia , Rusheng Zhang , Xueqi Cen , Haibo Wang , Jun Niu 
Published: March 2019

Abstract
The high efficient foam unloading agent was developed to solve the problem of unloading of liquid loading gas well with high gas temperature, salinity and high concentration of H2S gas and gas condensate. The Gemini anionic surfactant with special comb structure was synthesized as foaming agent molecule, the modified nanoparticles with certain size and degree of hydrophobicity was adopted as solid foam stabilizer, and the fluorocarbon surfactant was designed and synthesised as gas condensate resistance components. The indoor experiment results show that the foam unloading agent showed good foaming and foam stabilizing ability when the temperature is as high as 150°C, salinity is up to 250000 ppm and H2S concentration up to 2000 ppm. Besides, the foam unloading agent present good liquid carrying ability when the volume fraction of gas condensate is as high as 50%. The field test of this foam unloading agent in Longfengshan north 201-XY well shows that, the average gas production increased from 7256 m3/day to 11329 m3/day, increased by 56%, the average differential pressure between tubing and casing dropped from 2.66 MPa to 2.38 MPa, fell by 10.5%, both liquid yield and gas production are obvious, which prove that the foam unloading agent can meet the demand of drainage gas recovery for high content gas condensate gas field.
Surfactant-Inhibited Barium Sulphate Nanoparticles for Use in Drilling or Completion Fluids
Authors: Whyte John Morrison 
Published: March 2019

Abstract
The benefits of a nanoparticle-weighted fluid are numerous, allowing the possibility of high-density drilling fluids, a true alternative to expensive heavy brines, barite-weighted reservoir drill-in fluids and the virtual elimination of barite sag. By using a branched carboxylic acid, rather than a linear molecule as a crystal growth inhibitor during precipitation, true nano-scale dispersions have been achieved that are stable in water, with no detectable agglomeration and that are self-dispersing after drying. This paper proposes that greater steric hindrance and smaller particle sizes are achieved by utilising branched, or chair-like carboxylic acids, rather than the long-chain molecules more commonly used. The use of FTIR, XRD, DLS and SSNRM have been combined to demonstrate that inhibitor concentration is the dominant effect in preventing crystal growth but does not account for particle growth retardation alone.
Spherical nanoparticles with a dispersed ZAvg of 16nm and low contact areas have been created. They produce dispersions with a density of 2.27g/cm3. These dispersions display no detectable ‘sag’ after 428 days in suspension suggesting that colloidal stabilisation has been achieved. This paper also demonstrates that further decreases in particle diameter are possible through a combination of mechanical shear during precipitation and pH modification after precipitation has ceased. An optimum pH post-precipitation of 10.4 is close to that targeted by many water-based reservoir drill-in fluids, further highlighting the possibility of surfactant-inhibited barium sulphate nanoparticles as a density agent for drilling fluids. Using pH to modify the PSD of the nanoparticle dispersions strongly suggests that the dispersions can be tuned to one suitable for the intended operation. The growth inhibitors used during precipitation are low-cost and non-toxic and enable the dry particles to disperse to comparable PSDs after drying to their precipitated values. The technology allows the creation of a high-density brine replacement fluid, presenting a significant cost saving over an alternative such as caesium formate in some applications
Previous research on barium sulphate nanoparticles [3] succeeded via the adsorption of long-chain carboxylic acids. We have shown that shorter, branched carboxylic acids - a new approach - are more effective and in significantly lower concentrations. This paper has found that a rigid, chair-like molecule provides an equivalent particle size distribution at an ultra-low adsorption level.
The Impact of H2S on Carbonate Scaling Risk. A Field Case Study
Authors: Ness Giulia , Sorbie Ken , Lugo Nancy , Kelly Caroline 
Published: March 2019

Abstract
The effects of H2S on system integrity, sulphide scaling potential and health and safety in oil and gas production is well recognized and understood. However, as part of a wider study on pH dependent scale predictions, the authors have identified an additional challenge associated with the presence and/or development of H2S in reservoirs containing carbonates: higher H2S concentration reflects in higher calcium carbonate scaling potential. The intention of this work is to demonstrate the impact of H2S using a real field case scenario and investigate how the variability in water cut, aqueous phase composition, CO2 and H2S concentration can impact the well carbonate scaling potential and ultimately its productivity.
To model pH dependent scales correctly, it is necessary to integrate PVT calculations with the aqueous phase thermodynamic mineral scaling calculations. This has been extensively discussed in previous publications by the authors. For this work, a commercial integrated PVT and scale prediction software package was used to determine the scale prediction profile from reservoir to the first stage of topside separation. In addition, to investigate the impact of PVT on the final results, a second PVT software employing a different equation of state (EOS) is used and the results obtained from this calculations are coupled with the same aqueous phase model using the Heriot-Watt scale prediction workflow.
The well selected for this study shows productivity issues as well as signs of presence of calcium carbonate scale. However, scale prediction calculations carried out in the past did not show any potential for carbonate scale formation at the given conditions. After rigorously accounting for variations in water cut over time, as well as for increased H2S due to reservoir souring, our work clearly shows a correlation between a gradual loss of well productivity and carbonate scaling potential.
This work clearly demonstrates the impact of H2S on calcium carbonate scaling potential and highlights the importance of correctly modelling CO2 and H2S partitioning in gas/oil/water at the different stages of production, from reservoir to topside separation. Following this study, it has also been possible to offer specific well treatment and testing recommendations to verify the results and try to obtain improvements in production efficiency.
Moreover, the application of our approach to a real field scenario shows how some field findings associated with carbonate scale problems can be explained only by correctly modelling the full three phase system (oil, gas and water). Some aspects of this approach are frequently overlooked and not linked correctly to carbonate scale formation.