bluuebunny/crossref_metadata_2025_split huggingface dataset:
Laboratory and Pilot Tests of Enhanced Oil Recovery through Wettability Alteration by Diluted Microemulsions
Authors: Zhao Xurong , Liang Tianbo , Zan Jingge , Zhang Mengchuan , Zhou Fujian , Chen Zhiming 
Published: November 2021

Abstract
Replacing oil from small pores of tight oil-wet rocks relies on altering the rock wettability with the injected fracturing fluid. Among different types of wettability-alteration surfactants, the liquid nanofluid has less adsorption loss during transport in the porous media, and can efficiently alter the rock wettability; meanwhile, it can also maintain a certain oil-water interfacial tension driving the water imbibition. In the previous study, the main properties of a Nonionic nanofluid-diluted microemulsion (DME) were evaluated, and the dispersion coefficient and adsorption rate of DME in tight rock under different conditions were quantified.
In this study, to more intuitively show the change of wettability of DME to oil-wet rocks in the process of core flooding experiments and the changes of the water invasion front, CT is used to carry out on-line core flooding experiments, scan and calculate the water saturation in time, and compare it with the pressure drop in this process. Besides, the heterogeneity of rock samples is quantified in this paper. The results show that when the DME is used as the fracturing fluid additive, fingering of the water phase is observed at the beginning of the invasion; compared with brine, the fracturing fluid with DME has deeper invasion depth at the same time; the water invasion front gradually becomes uniform when the DME alters the rock wettability and triggers the imbibition; for tight rocks, DME can enter deeper pores and replace more oil because of its dominance. Finally, the selected nanofluids of DME were tested in two horizontal wells in the field, and their flowback fluids were collected and analyzed. The results show that the average droplet size of the flowback fluids in the wells using DME decreases with production time, and the altered wetting ability gradually returns to the level of the injected fracturing fluid. It can be confirmed that DME can migrate within the tight rock, make the rock surface more water-wet and enhance the imbibition capacity of the fracturing fluid, to reduce the reservoir pressure decline rate and increase production.
Adaptation of Test Methodology and the Evolution of a Demulsifier Formulation for a Heavy Oil Start-Up
Authors: White A. , Miller R. , Bellu E. , Wylde J. J. 
Published: November 2021

Objectives/Scope
Selection of "first fill" demulsifiers for new, undeveloped, oil fields has significant limitations, typically relying on data from test work with synthetic emulsion created in a laboratory using highly contaminated drilling samples of crude oil. Additional separation challenges related to offshore production of high viscosity, low API crude oil, from a low temperature reservoir results in a low probability of success in selecting a suitable first fill demulsifier using the traditional bottle test alone.

Methods, Procedures, Process
To give improved speed of oil/water separation, water quality, interface quality and top oil dehydration, samples of chemical free oil and produced water were used to screen alternative existing products against the base case demulsifier via bottle testing. The emulsions were created using a high shear stirrer to mimic the system conditions of the wells coming online and water droplet size within the emulsion was determined via cross polarizing thermal microscopy. For the purposes of these tests, demulsifier performance was ranked on speed and completeness of separation, interface quality, water quality and grind out (BS&W) characteristics.

Results, Observations, Conclusions
Several differences were observed between the initial and subsequent test work. The low shear emulsion created in the early work was found to be very unstable, separating easily with no residual emulsion in the crude oil. The emulsion created under high shear conditions gave a much closer correlation in terms of water droplet distribution to that measured during the field test and resulted in a much more stable emulsion that was more difficult to separate and typically left unresolved emulsion in the oil after the bulk of the water had separated. Whilst the original demulsifier recommendation was still able to facilitate separation it was found that it was no longer the optimum product, with other previously disregarded products able to provide a higher level of performance on the high shear emulsion.

Novel/Additive Information
This paper demonstrates that a higher level of performance was achieved with an enhanced screening process, namely through high shear stirring and confirmation of water droplet size within the emulsion. When added to the standard bottle testing conditions, the development of demulsifiers can better ensure an optimum result, fit for purpose for the application.
A Supramolecular Thickener Based on Non-Covalent Enhancement Mechanism
Authors: Ma Yingxian , Huang Liqiang , Zhu Zhi , Du Yurou , Lai Jie , Guo Jianchun 
Published: November 2021

Abstract
Inspired by non-covalent enhancement mechanism, we introduced glycinamide-conjugated monomer (NAGA) with dual-amide in one side group to amplify the hydrogen bonding interactions. Via one-step free radical polymerization strategy, we prepared a type of supramolecular thickener based on binary polymer. With NMR, FT-IR and SEM results’ help, we determined that PNAGA-AM system had unique bis-amide structure of glycinamide-conjugated monomer. As a result, the synthesized polymer could generate a much denser structure based on the high-ordered multiple hydrogen bonding with lower molecular weight (Mn = 778,400 g/mol), increasing the strength and stability of the chains. PNAGA-AM system had good thickening and temperature-resistant properties. The thickener viscosity of PNAGA-AM(3.0wt%) had twice as much as that of corresponding PAM system. And the viscosity of the 1.5 wt% solution prepared by PNAGA-AM could maintain 74 mPa·s at 150 °C. Meanwhile, the supramolecular system showed excellent salt resistance and self-healing performance with the non-covalent/hydrogen bonding interactions and physical entanglements. The viscosity of the PNAGA-AM system did not drop but increase in high salinity (≤ 300,000 mg/L salinity), and the maximum viscosity could increase nearly 44 % compared with the initial situation. In addition, the self-healing efficiency was over 100 % at 120 °C. Overall, the fracturing fluid system based on PNAGA-AM system could maintain outstanding rheological properties under extreme conditions and showed brilliant recovery performance, to make up the disadvantages of currently used fracturing fluid. It is expected to mitigate potential fluid issues caused by low water quality, harsh downhole temperatures and high-speed shearing.
Evaluation of Lignosulfonate Based Retarders for Thickening Time as a Function of Dosage and Temperature
Authors: Montgomery Justin , McNally Timothy , Hunger Jay , Subramanian Sreedhar 
Published: November 2021

Abstract
The retardation of class H Portland cement using lignosulfonates was investigated in the temperature range between 54°C and 153°C. Lignosulfonates with varying extent of modification was used in the study, and the optimum retarder dosage and temperature range to achieve desired thickening time was identified for different lignosulfonate types (non-modified, modified and highly modified). In general, a linear thickening response was observed at low retarder dosage, while a near exponential increase in thickening time response was observed at higher dosages.
Defining the retarder dosage temperature relationship is essential for proper cement slurry design for securing desired placement of cement slurry. A significant finding is that the thickening time responses trend from near linear at low dosages, transitioning to near exponential at higher dosages. The observed results varied depending on the extent of modification performed on the lignosulfonate retarder.
Pure lignosulfonate retarders produce optimal dosage response from 54°C to 97°C. Modified retarders work best in the range of 97°C to 118°C. While highly modified retarders perform best in the range of 118°C to 153°C. Defining the retarder dosage temperature relationship is essential for proper cement slurry design for securing desired placement of cement slurry.
Theories and Work Towards Understanding a Mysterious Case of Severe Bakken Brine Incompatibility
Authors: Spicka Kevin , Holding Eagle Lisa , Longie Chris , Dahlgren Kyle , Gerbino AJ , Koerner Alex , Loder Greg 
Published: November 2021

Abstract
The Bakken formation is well known for producing brine very high in total dissolved solids (TDS). Halite, calcium carbonate, and barium sulfate scales all can pose substantial production challenges. Trademarks of Bakken produced brine include elevated concentrations of sodium (&gt;90,000 mg/L), chloride (&gt;200,000 mg/L), and calcium (&gt;30,000 mg/L), contrasted against low concentration of bicarbonate (50-500 mg/L).
In the past 3 years, operators have experienced unexpected instances of severe calcium carbonate scale on surface where produced fluids from the production tubing commingled with the gas produced up the casing. Initially treated as one-off scale deposits despite the application of scale inhibitor, acid remediation jobs or surface line replacement were typical solutions. As time has passed, this issue has become more and more prevalent across the Bakken. Investigation of this surface issue discovered a most unexpected culprit: a low TDS, high alkalinity brine (up to 92,000 mg/L alkalinity measured to date) produced up the casing with the gas. When mixing with the high calcium brine typically produced in the Bakken, the resulting incompatibility posed remarkable scale control challenges.
The uniqueness of this challenge required thorough analytical work to confirm the species and concentrations of the dissolved ions in the brine produced with the gas. Scale control products were tested to evaluate their abilities and limitations regarding adequate control of this massive incompatibility. The theory that corrosion contributed to this situation has been supported by a unique modelling approach. Once corrosion was identified as the likely source of the high alkalinity brine, corrosion programs were instituted to help address the surface scaling. This paper highlights the evaluations conducted to fully grasp the severity of the incompatibility, the theories put forth to date, work conducted to try to replicate the phenomena in the lab and in models, and chemical programs used in the field to address corrosion and scale.
While not known to exist in other oilfield basins, conventional or unconventional, this discovery may have implications for the broader industry if similar situations occur. The possible explanations for why this may be happening may have implications for scale control, asset integrity, and potentially even the methods by which wells are produced.
Online Cleaning of Carbonate Deposits. The Potential and Limitations of a Novel Cleaning Method
Authors: Jordan Myles Martin , Sutherland Louise , Johnston Clare Jennifer 
Published: November 2021

Abstract
The formation of calcium carbonate scale within produced brine as it passes through topside heaters is a very common flow assurance challenge. Normally this scale risk is predicted and chemically controlled via scale inhibitors deployed upstream of the point of brine supersaturation. In some operations chemical application is not fully effective due to under treating of the chemical or carbonate from the reservoir (fines) builds up within the heaters. In cases of reduced fluid throughput cleaning of the inorganic scale is required. The most common method of cleaning is to take the heater offline and batch clean with acids (mineral or organic) to remove the deposits.
This paper outlines an investigation into the performance of conventional batch cleaning vs a more novel application method of online cleaning the heater while operating with application of organic acid into the produced fluid upstream of the heaters. The online cleaning process was evaluated via laboratory tests where packed column of field scale were flushed with organic acid within the produced water, and for comparison mineral acid, to understand the potential for online cleaning vs batch cleaning and what factors influenced the effectiveness of these application methods. Factors evaluated included flow rate/contact time, acid strength and acid type. During these online cleaning tests, the effluent of each column was evaluated for pH and finally weight loss at the end of the tests. The online cleaning results were compared to conventional batch cleaning assessment of the same scale samples via static bottle tests
The observations from the tests show that online cleaning using both organic and mineral acids result in the development of preferential flow paths within the scale packed columns that reduces the effectiveness of the cleaning chemicals. Improvements to the cleaning program were investigated such as the scale thickness when cleaning is first started to improve cleaning performance and fluid flow rate, increased acid concentration and liquid to solid ratio changes. Field application data from the initial cleaning programs and improvements to the cleaning programs will be shared as part of this publication
The factors that need to be assessed to determine if this method is suitable for a specific process system and likelihood of effective scale removal are presented. This method does present the possibility for some production systems that cleaning of carbonate scale can be carried out without the need to take the heater offline for chemical batch or mechanical cleaning.
Effective Treatment of Humic Acid Foulants in SAGD Produced Water
Authors: Li Chunli , Yue Zhiwei David , Tian Xiaohong , Hazlewood John 
Published: November 2021

Abstract
Humic acids, one major type of organic foulants in steam assisted gravity drainage (SAGD) produced water, can precipitate on surface and downhole equipment in SAGD facilities, resulting in high cleaning costs, potential equipment damage and decrease of injectivity of disposal wells. In this paper, a cost-effective chemical solution is presented where an alcohol ethoxylate surfactant/chelating agent package can efficiently disperse the organic fouling molecules in SAGD produced water; therefore, the approach is expected to significantly mitigate the humic acid related fouling issues in the SAGD system.
In this study, a variety of commercially available surfactant products were evaluated for their aids in well injectivity on humic acid molecules in the freshly obtained SAGD produced water. The lab testing filtration apparatus was specially designed to simulate the sandstone formation geology of SAGD disposal wells. An "efficiency factor" was defined to grade the dispersing performance of the surfactant and/or surfactant/chelating agent package in the lab filtration tests. The efficiency factor provides a reasonable estimation regarding how well the chemical can reduce the plugging risk in a disposal well as compared to the untreated produced water.
Among all the surfactant products tested, an alcohol ethoxylate surfactant with the appropriate molecular structure shows distinguished dispersing performance on humic acids in SAGD produced water. However, the surfactant alone was found inconsistent in the dispersing performance when different batches of the produced water were involved. Inclusion of the specific metal chelating agents to the above surfactant formulation improved the dispersing performance consistency. The chelator molecules presumably help destroy the intermolecular bridges among humic acid molecules in the SAGD produced water; thereby, increasing the dispersing effectiveness of the alcohol ethyoxylate surfactants. Tests show that the efficiency factor of the surfactant/chelating agent package is higher than 8, which implies that the formulation could lead to eight times extension of the interval between workovers on SAGD disposal wells, a significant reduction for the operational downtime and costs.
This study presented a cost-effective chemical solution to help disperse the humic acid molecules in SAGD produced water, which can help significantly reduce the fouling risk caused by organic foulants, improve injectivity and extend the intervals between workovers of SAGD disposal wells.
Novel Mineral Scale Deposition Model Under Different Flow Conditions with or Without Scale Inhibitors
Authors: Dai Zhaoyi Joey , Kan Amy , Lu Yi-Tsung Alex , Leschied Cianna , Zhao Yue , Dai Chong , Wang Xin , Paudyal Samridhdi , Ko Saebom , Tomson Mason 
Published: November 2021

Abstract
Mineral scale formation causes billions of dollars’ loss every year due to production losses and facility damages in the oil and gas industry. Accurate predictions of when, where, how much, and how fast scale will deposit in the production system and how much scale inhibitor is needed are critical for scale management. Unfortunately, there is not a sophisticated scale deposition model available, potentially due to the challenges below. First, an accurate thermodynamic model is not widely available to predict scale potential at extensive ranges of temperature, pressure, and brine compositions occurring in the oilfield. Second, due to the complex oilfield operation conditions with large variations of water, oil and gas flow rates, tubing size, surface roughness, etc., wide ranges of flow patterns and regimes can occur in the field and need to be covered in the deposition model. Third, how scale inhibitors impact the mineral deposition process is not fully understood. The objective of this study is to overcome these challenges and develop a model to predict mineral deposition at different flow conditions with or without scale inhibitors. Specifically, after decades of efforts, our group has developed one of the most accurate and widely used thermodynamic model, which was adopted in this new deposition model to predict scale potential up to 250 °C, 1,500 bars, and 6 mol/kg H2O ionic strength. In addition, the mass transfer coefficients were simulated from laminar (Re &lt; 2300) to turbulent (Re &gt; 3,100) flow regimes, as well as the transitional flow regimes (2300 &lt; Re &lt; 3,100) which occur occasionally in the oilfield using sophisticated flow dynamics models. More importantly, the new deposition model also incorporates the impacts of scale inhibitors on scale deposition which was tested and quantified with Langmuir-type kink site adsorption isotherm. The minimum inhibitor dosage required can be predicted at required protection time or maximum deposition thickness rate. This model also includes the impacts of entry-region flow regime in laminar flow, surface roughness, and laminar sublayer stability under turbulent flow. The new mineral scale deposition model was validated by our laminar tubing flow deposition experiments for barite and calcite with or without scale inhibitors and laminar-to-turbulent flow experiments in literature. The good match between experimental result and model predictions show the validity of our new model. This new mineral scale deposition model is the first sophisticated model available in the oil and gas industry that can predict mineral scale deposition in the complex oilfield conditions with and without scale inhibitors. This new mineral scale deposition model will be a useful and practical tool for oilfield scale control.
Development of Dynamic Tube Blocking Test Method to Study Halite Scale Deposition and Inhibition
Authors: Paudyal Samridhdi , Ruan Gedeng , Lee Ji-young , Wang Xin , Lu Alex , Dai Zhaoyi , Dai Chong , Ko Saebom , Zhao Yue , Yao Xuanzhu , Leschied Cianna 
Published: November 2021

Abstract
Halite scaling has been observed in the oil/gas field with high TDS and low water cut. Due to its higher solubility, slight changes in temperature (T) and pressure (P) and evaporative effect could yield a large amount of scale, causing significant operational problems. Accurate prediction and control of halite scaling in the oil and gas production system have been a challenge. Therefore, this study aims to shed light on the prediction of halite scale formation, deposition behavior, and inhibition at close to oil field conditions. We have designed and developed a dynamic scale loop (DSL) test methodology that can be used at various T and P. The test method utilizes a change in temperature (ΔT) as a driving force to create halite supersaturation and follow with the scale precipitation/deposition. The tube blocking experiments suggest that the tube blockage can be caused by bulk precipitation and or deposition of halite precipitate. SEM analysis of the tube cross-sections indicated that tube blockage, presumably by bulk precipitation, could be seen at the beginning of the reaction tube, but deposition was observed towards the exit end of the tube. Similarly, various experimentation to simulate the water dilution at constant pressure and ΔT were conducted. The effect of the addition of water to prevent halite deposition was analyzed computationally by using ScaleSoftPitzer (SSP) software. Brine compatibility of several inhibitors were tested via bottle tests and autoclave tests and qualified inhibitors were tested in the tube blocking experiments to identify the performance of the inhibitor to treat the halite precipitation at high temperature and pressure. Overall, a robust test method was designed and developed for halite scaling under high temperature and pressure that can simulate the oil and gas production in the field.
New Kinetic Turbidity Test Method and Prediction Model for Calcite Inhibition
Authors: Dai Chong , Dai Zhaoyi , Paudyal Samiridhdi , Ko Saebom , Zhao Yue , Wang Xin , Yao Xuanzhu , Kan Amy , Tomson Mason 
Published: November 2021

Abstract
Calcite, as one of the most common scales in oilfield can be inhibited by common scale inhibitors. The measurement of calcite nucleation and inhibition is a challenge, because of the difficulty to control pH as a result of CO2 partitioning in and out of the aqueous phase. A new kinetic turbidity test method was developed so that the partial pressure of CO2, pH, and SI can be precisely controlled. Calcite nucleation and inhibition batch tests were conducted under various conditions (SI = 0.24-2.41, T = 4-175 °C, and pH = 5.5-7.5) in the presence of common phosphonate and polymeric inhibitors. Based on experimental results, calcite nucleation and inhibition semi-empirical models are proposed, and the logarithm of the predicted induction time is in good agreement with the measured induction time. The models are also validated with laboratory and field observations. Furthermore, a new BCC CSTR Inhibition (BCIn) test method that applied the Continuous Stirred Tank Reactor (CSTR) theory has been developed, for the first time. This BCIn method was used for calcite inhibitor screening tests and minimum inhibitor concentration (MIC) estimation. By only running one experiment (&lt; 1 hour) for each inhibitor, BCIn method selected the effective inhibitors among 18 common inhibitors under the conditions of SI = 1.23 at 90 °C and pH = 6. It was also found that the critical concentration (Ccrit) from BCIn method has a correlation with the MIC from batch tests. This study provided a simple and reliable solution for conducting calcite scale inhibition tests in an efficient and low-cost way. Furthermore, the newly developed prediction models can be used as guidance for laboratory tests and field applications, potentially saving enormous amounts of time and money.