bluuebunny/crossref_metadata_2025_split huggingface dataset:
Enhanced Carbonate Scale Inhibition in a Challenging Environment via Synergistic Inhibitor Molecule Blends
Authors: Jordan Myles , Johnston Michael 
Published: May 2022

Abstract
Control of inorganic sulphate and carbonate scales with polymer, phosphonate and phosphate ester scale inhibitors is well established within the oilfield service industry. The environments in which these chemicals work best have been published, i.e., vinyl sulphonates are very effective for sulphate scale control in low temperatures (Laing and Graham 2003) whereas phosphonates are much less effective under these same conditions but improve at higher temperatures (Jordan et al., 2016). Less well understood is the potential for synergistic interactions with blends of polymers/phosphonates/phosphate esters to give reduced treatment rates, lower chemical discharge volumes and potentially lower treatment cost specifically for carbonate scale control
In this paper evaluation of a North Sea produced water (1,500ppm Bicarbonate, 30ppm Iron and 3,550ppm Calcium ions) will be outlined where a very high carbonate saturation ratio exists within a produced fluids heater resulting in very high inhibitor treatment rates of a MEA phosphonate type scale inhibitor). Dynamic tube blocking tests were carried out to evaluate nucleation inhibition of a range of single component inhibitors before blends of these chemicals including biopolymer/phosphonate and poly aspartic acid/phosphonate where evaluated try to reduce the inhibitor concentration required to control scale formation.
For this challenging carbonate scale environment at a temperature (105°C), it was observed that a biopolymer/currently applied MEA phosphonate blend was more effective than either of the components by themselves, suggesting synergistic interaction. Environmental properties of the inhibitors evaluated played a key role in their selection and has resulted in trial of polymer/currently applied phosphonate being planned for this field. Qualification test results for the incumbent, potential replacement single inhibitor actives and blended inhibitor are presented.
The current regulatory challenges with REACH mean that the methods outlined in this study offer the potential to reduce chemical treatment rate, cost and environmental impact by evaluating the synergistic interaction of the current range of commercially available environmentally suitable scale inhibitors and therefore eliminating the very high registration costs/ time delays to the market associated with new molecule development.
Development of a Green, F22 Compatible Scale Inhibitor for Application in West Africa
Authors: Williams Helen , Adamson Ben , De Subhasis , Bhandari Manoj , Johnston Clare 
Published: May 2022

Abstract
An operator in West Africa required a scale inhibitor for an application with several technical challenges. The scale inhibitor was required to meet the Angolan decree on environmental acceptability, had to be compatible with F22 alloy present in the wellhead, and had to be suitable for application via umbilical. The scale in question was a reasonably harsh barium sulphate condition. A number of chemical formulations were suitable for use with F22, however, these chemicals did not meet the performance requirements set for barium sulphate inhibition.
Testing was conducted starting with corrosion tendency screening, whilst several potential raw materials were checked for their environmental credentials. It was possible to meet the corrosion screening conditions set by the operator with one raw material; however, this did not meet the scale inhibition criteria. Several chemicals were examined in dynamic scale loop testing, with none achieving the required performance. It was decided to evaluate blends of generic scale inhibitors, to assess whether a synergy between two different chemicals could offer improved inhibition performance, whilst still meeting the corrosion rates.
The chemicals selected were known to have lower corrosivity – one a polymer which had been used successfully with F22 alloy, plus another polymer widely used in the North Sea where low corrosivity generally is required along with good environmental properties. This blend was successful in meeting the scale inhibition performance target and was found to offer good compatibility with F22 alloy under application conditions. Furthermore, both chemicals were suitable to meet Angolan decree on environmental acceptability.
The paper describes in detail the development test work carried out for corrosion assessment, inhibitor performance, formulation stability, brine compatibility to select this formulation and highlight the importance of synergistic blends for meeting particularly challenging scaling environments.
Scaling Up: Evaluation of Scale Deposition and Inhibition Under Turbulent Flow Conditions Using a Large Pilot-Scale Test System
Authors: Fyfe Andrew , Nichols David , May Mark , Goodwin Neil , Simpson Caroline , Graham Gardon 
Published: May 2022

Abstract
A pilot-scale test system has been developed to evaluate scale deposition and inhibition under flow conditions that are more representative of the field than conventional laboratory methods. This system has been used to investigate an example of strontium sulphate scaling and the effect of hydrodynamics on the location and the quantity of scale deposit formed.
The approach used in this study involved flowing a large quantity of heated brine through a 1" diameter steel test piece at 5 L/min for several hours in a single-pass system. The test piece consisted of short sections allowing the configuration to be altered and allowing the scale deposited in each section to be quantified. Tests were run with configurations simulating a straight pipe, an ICD nozzle, and a gas lift system to investigate the effect of turbulence and shear stress on scale location and mass. The effect that injection of a chemical inhibitor had on preventing scale deposition in this system was also tested.
The results obtained demonstrated that the flow regime in the test piece had a significant effect on the mass and location of strontium sulphate scale deposits. A much greater quantity of scale was observed when the fluid experienced the increased shear stress and turbulence generated by passing through a narrow restriction, or by the injection of gas into the flow, compared with straight pipe flow. Successful chemical inhibition of surface deposits was demonstrated in this system. The use of smaller scale benchtop tests to demonstrate the effect of saturation ratio on obtaining sufficient deposition in single-pass tests compared with a recirculating approach are also discussed.
Design and implementation of large-scale tests is an important industry tool for laboratory evaluation of scaling in circumstances where conventional test methods do not give sufficient confidence to develop a scale management strategy and a more field-representative method is required. This paper describes an approach for successfully carrying out such tests and demonstrates the breadth of results that can be obtained from them. It also adds to industry knowledge of the effect that regions of high turbulence and shear have on promoting greater scale formation.
Hydrodynamic Simulation Supports Scale Formation in Technical Specification for Downhole Equipment
Authors: Poletto Vinicius Gustavo , Mazuroski Marina Elizabeth , Pereira Fabio Ressel de Assis , Palharini Schwalbert Mateus , Duarte Ferreira Marcus Vinicius , Eduardo Tiago Handerson Torres , De Lai Fernando Cesar , Junqueira Silvio Luiz de Mello , Martins André Leibsohn 
Published: May 2022

Abstract
The huge carbonate reservoirs of the Brazilian pre-salt layer are likely to experience inorganic scale formation, mainly due to calcium carbonate. Emerging wellbore configurations, designed to reduce cost and increase reliability, show some drawbacks as the inability of injecting chemical inhibitors in the open-hole full-electric intelligent completion schemes. Traditionally, scale prediction relies on thermodynamic modeling, having a glimpse on the precipitation potential under static conditions, but neglecting the constructive details of the tools’ geometry and the fluid dynamic influence over the precipitated crystals. This paper details a Euler-Lagrange approach for the modeling of the liquid-solid flow applied to the simulation of scale formation in Internal Control Valves (ICVs). Numerical simulation is performed by the means of the Finite Volume method coupled to the Discrete Element Method (CFD-DEM), obtaining results as the accumulated mass in specific parts of the equipment (fouling hotspots) and the transient pressure uptrend as a consequence of flow blockage. The fouling forms as the particulate agglomerates adhere to the walls under the effects of turbulence and the adhesion force set up between particle-particle and particle-wall, hindering the flow due to the four-way-coupling between phases. Thus, the results compute the solids deposition that depends on the valve geometry, rather just the precipitation rate. Additionally, the simulation may be run by the Finite Volume Method coupled to the Discrete Phase Method (CFD-DPM) with an associated operation of remeshing. The fouling consists in computing the accumulated mass over the equipment surface and deforming the geometry to represent the obstruction. The numerical results are useful for the equipment technical specification, specifying the level of scale the valve has to withstand in a time window and also quantify acceptance criteria in terms of the pressure increase and the adhered mass. It is also possible to compare concurrent geometries in terms of reliability and propose design upgrades.
How Squeeze Management Differs during Field Redevelopment
Authors: Wang Xu , Mackay Eric James , Jordan Myles Martin 
Published: May 2022

Abstract
Scaling risk may be insignificant during the early stages of well life due to delayed seawater breakthrough; however, during the latter stages of production inhibitor chemical application by squeezes may be required to prevent scale deposition (Chen et al., 2013). This raises the question of what behaviour should be expected during the redevelopment of a previously seawater flooded reservoir. Should the planning and design of squeeze treatments in a brown field project be the same or different to a green field development?
This paper discusses this issue by reference to a case study in a field located in the Norwegian Sector of the North Sea. The field in question is produced by horizontal wells, and these wells will require scale inhibitor placement via bullhead squeezes deployed at appropriate pump rates to ensure effective placement to provide adequate protection. The timing and extent of seawater breakthrough have been calculated using a reservoir simulation model that accounts for the original development phase, a multi-year period during which the field was shut in - but during which fluid redistribution could still occur - and then the redevelopment phase.
These calculations have been used to identify the required timing for squeeze treatments, and to investigate what bullhead pump rates are required for adequate placement during both phases of field life. Two wells are considered during the first production period and six wells are studied during the redevelopment stage. In each case four pump rates are assessed: 2.5, 5, 7.5 and 10 barrels per minute. The main finding is that while adequate placement can be achieved using the same pump rates in both phases of field life, during the redevelopment stage the treatments will need to be deployed earlier in the redeveloped wells life, since there may not be a long time period between (formation) water breakthrough and seawater breakthrough, as there generally is during conventional green field developments.
This paper delivers a comprehensive water breakthrough and squeeze placement profile comparison between early and redevelopment stages. It presents an assessment of the scaling risk in different production wells, the timing of the first and later squeeze treatments in each production well, and the ability to mitigate that scaling risk by bullhead squeeze treatments.
New Halite Testing Methods for High Temperature and from Low to Very High Calcium Content Brine
Authors: Paudyal Samridhdi , Wang Xin , Ko Saebom , Li Wei , Yao Xuanzhu , Leschied Cianna , Shen Roy , Pimentel Daniel , Kan Amy T. , Tomson Mason B. 
Published: May 2022

Abstract
Halite scaling has caused serious issues in oil/gas field with high TDS and low water cut due to temperature drop and evaporation of the produced water. Simulation of such field condition is very hard. Analytical error for high concentrations of Na+and Cl- is large in the brine making accurate assessment of solubility and Saturation Index (SI) calculation difficult. We have developed the testing capability and methods to understand and control halite problems. We have developed testing methods that can create halite super saturation by incorporating (i) additional chloride from CaCl2 to the reaction mix at equilibrium and/or (ii) utilizing the change in temperature (∆T) as a driving force. These methods are optimized to assess the halite problem from 25-150 °C using mass analyses techniques, mixing of incompatible brines and temperature drop. The composition of salt, dilution volume and saturation index have been calculated using BCC ScaleSoftPitzer software. The induction time (tind) and mass of precipitated salts are considered for data analyses. Various experimentations to simulate the water dilution at ∆T were conducted and data suggest that in some cases 5 % dilution of the brine could drop halite saturation index (SI) to the equilibrium. Similarly, solubility of halite was analyzed in the presence of high calcium concentration in the brine up to 80,000 mg/L. Inhibitors with different functionalities were tested at various ranges of brine condition at saturation index of up to 0.15. Some inhibitors like polymers were found to prolong the induction time for several hours and reduce the halite precipitation mass up to 95%. Overall, the methods are robust yet simple and economic that can simulate field conditions in oil/gas production system to assess the halite scaling risk at higher extremes.
Heat Exchanger Fouling Incident Following A Scale-Inhibitor Squeeze – A Chemical Incompatibility Whodunnit
Authors: Goodwin Neil , Frigo Dario 
Published: May 2022

Abstract
This paper describes an investigation into a heat-exchanger fouling incident in an offshore installation that followed the flowback from a scale squeeze treatment. The phosphonate inhibitor used is well known to be incompatible with high concentrations of calcium at typical oilfield pH values, but the formation water in the field contained a very low calcium concentration and had been shown to be completely compatible even with high concentrations of inhibitor. Nevertheless, the solids recovered from the heat exchanger were found largely to consist of a calcium-phosphorus species, implying that incompatibility between dissolved calcium and the inhibitor was the cause; only traces were found of calcium carbonate, the scale mineral against which the squeeze treatment had been performed.
The paper presents a review of the timeline of events that led up to the incident and describes key observations that point to its cause, including the treatment design, well-performance, flowback practices, etc. Finding the most likely cause was primarily about determining how a stream had been created in the facilities containing elevated concentrations of calcium and the phosphonate inhibitor that would then be preferentially deposited in the heat exchanger due to its high skin temperature (the Ca·P complex is less soluble at high temperature). The plausibility of these mechanisms was then examined by a laboratory programme that attempted to reproduce conditions that could have occurred in the facilities.
The most likely origin of the high concentration of scale inhibitor was the squeeze flowback; that of the calcium-rich stream could not be conclusively assigned to a single cause, but was either (i) delayed flowback of spent acid-stimulation fluid from the intervention of a well 2 months before the fouling incident, or (ii) dissolution of previously deposited calcium carbonate scale (and/or conceivably, traces of this mineral in the formation) by the acid phosphonate inhibitor (most likely the well squeezed just before the incident), followed by re-precipitation of the Ca-P complex when the resulting solution was subject to the high skin temperatures of the heat exchanger.
Although it was not possible to distinguish conclusively between these possibilities, the understanding gained enabled preventative actions to be identified for future operations in this field.
The Role of Mutual Solvents in Scale Inhibitor Squeeze Treatments
Authors: Sanchez Hugo Antonio , Mackay Eric James , Singleton Michael Andrew 
Published: May 2022

Abstract
The first stage of a squeeze treatment entails a pre-flush, usually containing a mutual solvent that prepares the surface of the rock and allows greater retention of scale inhibitor that is injected during the main part of the treatment. We use experimental studies to tackle the issue of mutual solvent propagation and its impact on oil displacement and inhibitor retention. Clashach cores were used in this study, and the propagation of mutual solvent and subsequent scale inhibitors through the core were studied, along with any influences on rock properties such as permeability and on residual phase saturations. It was evident that during waterflooding a high residual oil saturation affects squeeze lifetime, and that mutual solvent can partially compensate for this, although the effect could not be definitively identified. Thus, further corefloods were conducted to understand how long it takes to remove residual mutual solvent from the core plug during the main treatment injection stage, and what is the influence of mutual solvent concentration in the pre-flush on this process.
The corefloods conducted were thus: i. Three floods with different concentrations (100%, 75% and 50%) of mutual solvent, using the injection of tracers at various stages, to identify how the residual phase saturation changes with main treatment aqueous phase volume throughput, and ii. Three scale inhibitor floods at residual oil saturation (using Multipar H). One with no mutual solvent pre-flush and two with a mutual solvent pre-flush (100% EGMBE). The difference between the latter two mutual solvent pre-flush floods was the amount of residual oil in the core prior to mutual solvent injection.
The results are discussed in detail, to understand the effect of the mutual solvent during a squeeze treatment under typical field conditions. According to the results it is proposed that using mutual solvent as a pre-flush enhances scale inhibitor squeeze lifetime, by increasing scale inhibitor adsorption/retention, due to a wettability change towards more water-wet – as evidenced by the reduction in residual oil saturation. Furthermore, more pore volumes of aqueous phase main treatment (up to seven) were required to displace the residual phase when lower mutual solvent concentrations were used in the coreflood pre-flush stage.
The results of this work indicate that mutual solvent concentration, and the ratio of main treatment volume to pre-flush volume should be carefully considered when designing squeeze treatments, since the contact between the aqueous scale inhibitor solution and the rock will be affected by the ability of the mutual solvent to displace oil, and by the volume of main treatment required to displace the mutual solvent rich pre-flush. Finally, modelling work was undertaken using the isotherms generated from the corefloods to demonstrate the impact on squeeze life of various mutual solvent applications.
Application of ScaleSoftPitzer in Big Data Era: Evaluations of Water Source, Scale, and Corrosion Risk – A Permian Basin study
Authors: Wang Xin , Dai Zhaoyi Joey , Li Wei , Ko Saebom , Paudyal Samridhdi , Yao Xuanzhu , Leschied Cianna , Shen Yu-Yi Roy , Pimentel Daniel , Kan Amy , Tomson Mason 
Published: May 2022

Abstract
Oil and gas industry would generate a large volume of produced water during the exploration and production. The geochemistry of the produced water can provide valuable information for the analysis of formation water source evolution and the scale and corrosion risk of the production. In past decades, the water sample and the correlated condition have been collected during the production, which accumulate extensive amount of data. The successful analysis of such database would be very helpful for the scale and corrosion management. In this study, the ScaleSoftPitzer (SSP) software is used to proceed the analysis of produced water evolution and scale and corrosion risk. A Permian Basin example is selected based on USGS produced water database V2.3. The formation information from the database was critically reviewed, cleaned and standardized into 13 major formation groups related to the oil and gas production area. The missing depth, temperature and pressure were calculated, and the CO2% and downhole pH were calculated by assuming the downhole brine was in equilibrium with calcite. The saturation indices of various scale are calculated and statistically analyzed. According to our analyzing result, it is found that usually the saturation index of gypsum and barite are close to zero, which suggest that the produced water is in equilibrium with barite and gypsum mineral in the formation. The calculated calcite scale SI are generally larger than 1.0, suggested potential calcite scale risk. 1 mg/L of NTMP is recommended for all Permian Basin well for preventive scale control. The CO2 corrosion risk was also calculated using the corrosion model in SSP, a preventive action is suggested for Permian Basin. Furthermore, a good agreement between the calculated corrosion rate and the measured Mn2+ concentration is observed. This study provided a template to use the produced water database to improve the scale and corrosion management at the field level in this big-data era.
Lattice Boltzmann Model for Oil/Water Two-Phase Flow in Nanoporous Media Considering Heterogeneous Viscosity, Liquid/Solid, and Liquid/Liquid Slip
Authors: Wang Han , Wang Wendong , Su Yuliang , Jin Zhehui 
Published: May 2022

Summary
Due to intermolecular interactions, the oil/water two-phase flow behaviors in shale nanoporous media are complex and diverse, which cannot be characterized by a conventional continuum flow equation. In this work, we propose a nanoscale multirelaxation-time multicomponent and multiphase lattice Boltzmann method (MRT-MCMP-LBM) based on pseudopotential format to simulate oil/water two-phase flow at the pore scale. The nanoscale effect of liquid/solid slip, liquid/liquid slip, and heterogeneous viscosity due to liquid/solid and liquid/liquid molecular interactions is fully taken into account. We use the Laplace test, contact angle, and phase separation to calibrate the desired interfacial tension (IFT) and wettability. Then, the proposed model is verified by comparing to molecular simulation and theoretical results. Although the liquid/solid slip can increase the oil/water flow capacity, it can reduce the relative permeability due to the increased intrinsic permeability. The oil/water interfacial slip can increase the relative permeability of the nonwetting phase, which can be greater than unity because the effect of oil/water interfacial slip is greater than that of nonwetting-phase/wall slip. We also calibrate the microscopic parameters of oil and water flow in inorganic and organic pores by comparing their velocity profiles to those from molecular dynamics (MD) simulations. The oil/water two-phase flow in shale nanoporous media indicates that with a higher total organic carbon (TOC) content, oil relative permeability is lower due to the more significant adverse nanoscale effect. The proposed model can be potentially applied to simulate shale oil/gas/water multicomponent and multiphase (MCMP) flow, imbibition, CO2 huff ‘n’ puff, and geological sequestration.