bluuebunny/crossref_metadata_2025_split huggingface dataset:
Exposing Islamic Character Values at English for Islamic Studies (EIS) Class
Authors: Muzammil Sa'dulloh 
Published: June 2020

This descriptive qualitative research aims to describe the selection and usage of English for Islamic studies material based on Islamic character values. It was conducted at English for Islamic studies class followed by the students of Akhwal As Syakhsiyyah Department, IAIN Pontianak. The results showed that the lecturer chose internet authentic material regarding Islamic character values, and he administered an online readability test to gain a reading passage that fits students' abilities. According to interviews with several students, after reading and discussing passages containing Islamic character values, students felt that such reading materials were beneficial information, and they attempted to behave according to Islamic characters mentioned in the reading passages.
A New Object-Based Algorithm To Simulate Geometrical and Petrophysical Turbidite Channel Properties
Authors: Grajales Viviana Vargas , Pinto da Silva Tamires Pereira , Barreto Abelardo Borges , Pesco Sinésio 
Published: June 2020

SummaryAn object-based algorithm that models turbidite channels using training images, called skeleton-based simulation or SKESIM, is proposed in this study. These images are interpreted as a graph and used to extract the statistical distribution of parameters selected from the graph. From this information, a 3D model of turbidite channel systems was built. These channels were generated within the turbidite lobe, creating a simulated depositional system. After the geometry of the channels were simulated by SKESIM, the petrophysical properties were mapped by Gaussian-like distributions. Numerical simulations were used to fit the simulated permeability field to a reference case through an objective function. A commercial finite difference simulator was used to compare the reference data to the simulated data, and comparable results were obtained.
Development of Scale Inhibitor for High Salinity High Iron Containing Brines
Authors: Daniels J. Katrina , Feasey Neil 
Published: June 2020

Abstract
The production of high salinity brines (Total Dissolved Solids (TDS) &gt; 250,000 ppm) during oil and gas production is known to cause severe scaling issues. When high TDS conditions are coupled with high concentrations of dissolved iron in a produced water, the challenges for controlling scale deposition increase significantly. The formation of the more common mineral scales (barium/strontium sulfate, calcium carbonate, and calcium) is expected in these produced waters and often other challenges associated with high TDS brines include the propensity for halite (sodium chloride) deposition to also occur in these environments as well. The elevated iron content present in these brines not only introduces the potential for deposition of iron-related scales but is also known to have a negative impact on scale inhibitor performance against calcium carbonate and barium sulfate scales. However, the impact on the inhibitor is different for both types of scale. The objective of this work is to evaluate the performance efficiency of polymeric and phosphonate-based scale inhibitor blends under both static and dynamic testing conditions using a synthetic brine with high TDS and varying concentrations of dissolved iron (up to 250 ppm).
The synergistic effects of combining these chemistries will be evaluated for this work. Dynamic Scale Loop (DSL) and static bottle testing will be used to determine the performance the efficiencies of the developed products.
When tested individually under a mixed scaling scenario with a high TDS and high iron containing brine, the scale inhibitors selected for this study had performance efficiencies (MED) values of 200 ppm or greater. However, when polymer/phosphonate scale inhibitor blends were evaluated a significant improvement in performance efficiency was observed.
This paper will give a detailed account of testing conducted to identify inhibitors capable of preventing the deposition of calcium carbonate and iron-related scales in challenging environments by utilizing the synergistic effects of the scale inhibitor chemistries.
Effect of Magnesium and Iron on Precipitation of Calcium Carbonate in Rich Monoethylene Glycol MEG
Authors: Kundu Shiv Shankar , Seiersten Marion Elisabeth 
Published: June 2020

Abstract
Monoethylene glycol (MEG) regeneration systems often have a pre-treatment unit for controlled precipitation and subsequent removal of carbonates and hydroxides. The purpose is to avoid scaling in downstream process system. CaCO3 is often the main solid removed in the pre-treatment. This study is on the effect of magnesium and iron(II) ions on the CaCO3 polymorph that forms, its particle size and morphology and the residual calcium concentration in solution.
Experiments were performed in a continuous reactor at 80 °C. The residence time was ca. 20 minutes. The feed to the reactor was 50 wt% MEG (representative rich MEG) containing divalent cations and NaCl. Concentrated alkali (NaHCO3, Na2CO3 and/or NaOH) was added to precipitate the divalent cations. The slurry in the reactor was sampled and filtered. The filtrate was analysed for alkalinity and residual divalent cations, and the dried solids were characterised to determine crystal morphology in addition to elemental and phase composition.
The experiments were run as a continuous process for ca. 4 hours. Steady state with respect to precipitation was established after ca. 1 hour and from that point in time, the concentration of Ca2+ and CO32- was nearly constant. Aragonite was the dominating CaCO3 polymorph and the main precipitate. At steady state, the saturation ratio (SR, activity product divided by the solubility constant) of aragonite was in the range 1-5. Magnesium ions in solution seemed to maintain the steady state SR of aragonite above 1, while the aragonite crystals became significantly smaller when Mg2+ precipitated as an amorphous solid and the residual concentration in solution was low. Siderite is less soluble than aragonite, and in 50 wt% MEG at 80 °C, its precipitation rate was sufficiently high to give low residual Fe2+ concentration when CaCO3 precipitated to low Ca2+ concentration. Siderite co-precipitating with aragonite at mol ratio siderite:aragonite~1:5 had little effect on the morphology and particle size of aragonite.
Are Scale-Dissolver Enhancers Necessary for Calcium Sulfates?
Authors: Reyes-Garcia Enrique Antonio , Holan Kristina Henkel 
Published: June 2020

Abstract
Scale dissolvers for CaSO4, are composed of chelants, including aminocarboxylates or phosphonates, and can contain lower concentrations of other chemical additives (enhancers) that improve dissolution. We investigate the effectiveness of enhancers, whose function is to increase the dissolution rate, by examining the effect of substituted acetates. The objective is to elicit the chemical properties that make an enhancer effective, identify costs, safety considerations, and validate their application and limitations for field use.
Two types of mineral anhydrite and nine enhancer agents were used in static dissolution tests. Thin slabs were soaked in dissolver fluids, including a converter agent, at a pH between eight and ten. The enhancer concentration spanned 0.5, 5, and 10% w/v and probed both the catalytic and inhibitory effects. The dissolver was selected and optimized based on a customized screening methodology. Tests with mass/volume ratios of 0.1 and 0.02 were employed to fit mass-loss data to a kinetic model and rank the general rates of dissolution, which indicate there is a favorable chemical enhancer type of additive.
Mass-loss rates using two types of anhydrite, obtained at 200°F from one to six hours, indicate strong enhancer activity. Distinctive effects are found depending on the chemical substituent on the enhancer agent. Dissolution of anhydrite shows significantly different rates at 1 hour and mass-limiting effects with no differentiation for m/v = 0.02 at four hours and nearly a similar initial rate at one hour for m/v = 0.1. A significant differentiation is observable after one hour. Inhibitory effects are discernable at high concentrations (10% enhancer). The type of substrate also shows differences in dissolution activity among blue and grey anhydrite. We found a strong correlation with the dissolver enhancer chemical type, indicating a chemical class of agents that could have applicability in descaling operations. The enhancers have been ranked by health and safety characteristics and cost to assess the feasibility of use in oilfield environments.
The use of enhancer agents in scale dissolver fluids can provide dissolution within one to four hours, helping shorten the shut-in period for this treatment. Tests show that including highly polarizable agents can lead to faster dissolution of anhydrite.
Evaluation of the Need for Scale Inhibitor Injection During Formation Water Production in a Subsea Gas Field Using Partly PH Stabilised Mono Ethylene Glycol
Authors: Halvorsen Anne Marie , Hauge Kristin , Andersen Kari Straume , Kaasa Baard 
Published: June 2020

Abstract
A subsea gas field uses MEG with pH stabiliser and film forming corrosion inhibitor for hydrate and corrosion control. Formation water production from some of the wells is expected and when mixed with partly pH stabilised MEG, there is an increased risk for carbonate scaling in the mixing point at the wellhead and in the production pipeline. Scale calculations gives calcium carbonate saturation ratios at a level where scale formation is expected in produced water systems which indicate a need for scale inhibitor. It is assumed that precipitation of salts in MEG systems is slower than in water-based systems and a work was started to investigate if higher saturation ratios could be tolerated in a system containing MEG than in a water system without MEG. Scale testing were performed with and without MEG at relevant field conditions to evaluate if formation water can be produced without use of scale inhibitor at a low risk for scaling. Glass equipment with a mixing cell connected to short steel pipes mounted upstream and downstream of a glass coil were used in the scale testing. Calcium carbonate scale was identified by SEM/EDS on the steel pipes and the amounts of deposited calcium carbonate were found by weighing. Amounts of deposition in the tests were compared with the theoretically amounts that could precipitate. These results were further combined with deposition considerations in the piping in the field as a function of time to evaluate the risk for blocking the piping downstream the MEG injection point with calcium carbonate scale. Based on the scale testing and deposition evaluations it was concluded that use of scale inhibitor was not necessary since the risk for build-up of scale in the piping was very low.
Modelling the Impact of Low Salinity Waterflooding, Polymer Flooding and Thermally Activated Polymer on Produced Water Composition
Authors: Al Bahri Mohammed Said , Vazquez Oscar , Beteta Alan , Al Kalbani Munther Mohammed , Mackay Eric James 
Published: June 2020

Abstract
It is common that a large volume of hydrocarbons remained unrecovered after primary and secondary recovery. Enhanced Oil Recovery (EOR), as tertiary recovery, plays a key role in recovering additional volumes of hydrocarbons. However, there is little work in the literature on the impact of different EOR mechanisms on the flow behaviour of formation/injected brines and scaling tendencies. The objective of this manuscript is to investigate, by the means of reservoir simulation, the impact of different EOR techniques, namely low salinity waterflooding (LSW), polymer flooding and Thermally Activated Polymer (TAP), for in-depth conformance control, on oil recovery and BaSO4 scale deposition.
A reactive transport reservoir simulator was used to evaluate the impact of three EOR techniques in the mixing profiles of injected seawater and formation brine, resulting in the precipitation reaction of BaSO4, due to the incompatible mixing of formation and injected brines. Three two-dimensional models were considered, a homogeneous and heterogeneous areal model to compare polymer flooding and LSW; and a vertical heterogeneous model to analyse the effect of TAP.
Results show that LSW delays and reduces the risk of BaSO4 scale deposition at the producer, due to the fact that the concentration of injected SO42- is significantly lower than full sulphate injection seawater. However, LSW results in longer co-production period of Ba2+ and SO42- ions, due to the fact that Ba2+ stripping is reduced because of the scale precipitation within the reservoir is reduced. Polymer flooding improves the sweep displacement, which delays the onset of scale formation, shortens the co-production period of the scaling ions at the producer and reduces the amount of water produced, hence, reducing the scale risk. TAP injection results in the delay of the injected water breakthrough, which delays the onset of scale formation in the producer; however, it can increase the amount of formation water (hence Ba2+ ions concentration), mainly from the low permeability zones, in the producer.
EOR techniques may have a major influence on the evolution of scaling ions in the produced water, which has to be taken into account for an optimum scale management strategy, to maximize oil production.
Improved Scale Squeeze Placement in Horizontal Wells With Pressure Variations Along the Well Using Non-Newtonian Fluids With Inflow Control Devices
Authors: Droppert Vincent , Hatscher Stephan , Djayapertapa Lesmana , Byrne Michael 
Published: June 2020

Abstract
The Nova subsea oilfield development is located in the Norwegian sector of the Northern North Sea and will be developed with 3 oil-producer / water-injector pairs. Two of the production wells will be open hole horizontal wells of moderate length (400 – 1000 m) completed with sand screens equipped with ICDs (inflow control devices) to facilitate the best possible clean-up and to optimize inflow distribution.
The injection of filtered and treated seawater has been selected for reservoir pressure support. Despite the relatively low Barium content (&lt;70 mg/L) in the formation water, sulphate scaling is expected to appear in the production wells once injection water breakthrough occurs. In order to maintain well productivity, periodic successfully placed scale squeezes are essential.
As the horizontal wells are completed across multiple reservoir segments in the same layer, uncertainties in fault transmissibility and water injector connectivity may result in variation of pressure along the well, thereby complicating squeeze placement. Traditionally, variation in rate and fluid viscosity have been applied to improve placement of scale inhibitor in the higher-pressure layers connected to the water injector. Chemical vendor simulations indicated that for a pressure variation below 5 bar adequate placement could be achieved with non-Newtonian fluids, however for higher differential pressures significant portions of the well would go untreated.
The Nova sand screens are equipped with inflow control devices designed to allow the best possible clean-up after drilling and optimize inflow during production by distribution of drawdown and limiting of annular flow. The idea of using the same principles for scale squeeze was difficult to prove due to limitations in vendor placement software and other industry standard modelling packages not being able to model the combination of ICDs and non-Newtonian fluids.
Computational Fluid Dynamics (CFD) on the other hand can simulate various factors that could influence the placement of scale inhibitors along the well length. Factors such as Newtonian versus non-Newtonian scale inhibitors, different reservoir pressure profile, ICD nozzle sizes and different well completions. This is all possible because CFD is largely based on physics and rigorous geometry, which is a significant step forward compared to the industry-standard scale squeeze placement software (Byrne 2010, 2011, 2014).
Application of a computational fluid dynamics well model has provided confidence that the combination of non-Newtonian fluids and production ICDs would allow scale squeeze placement along the whole reservoir interval despite significant pressure variations across it.
Economic Optimization and Calcite Scale Management of CO2-EOR in Carbonate Reservoirs
Authors: Rodrigues Hydra , Mackay Eric , Arnold Daniel , Azari Vahid , Vazquez Oscar 
Published: June 2020

Abstract
How to estimate operational controls so as to optimize economic returns in CO2-WAG projects and reduce calcite scale risk? The reactivity and heterogeneity intrinsic to carbonate reservoirs make CO2-WAG (Water Alternating Gas) injection a big challenge. While miscibility effects greatly increase oil recovered, the presence of CO2 can cause severe flow assurance issues. The aim of this paper is to introduce a simulation-based methodology to optimize the design of CO2-EOR operations, considering economics, mineral scaling risk and environmental impact.
A compositional reservoir model was built to simulate a reactive 3-phase miscible flow in porous media. Aiming at maximizing the Net Present Value (NPV), we optimized the following operational variables: duration of waterflooding period; injection rates; producer bottomhole pressure (BHP); WAG ratio, gas half-cycle duration and number of cycles for different WAG stages (tapered WAG). We then used the forecasted data to quantify calcium carbonate scaling tendency for the scenarios of interest and design scale management strategies (squeeze treatments) with the lowest costs.
The optimal WAG design found through the methodology increased NPV by 55.6% compared to a base-case waterflooding scenario. We also found that performing a waterflood in a carbonate reservoir with high CO2 content will result in more severe calcite scale risk than applying equivalent WAG schemes. A lower production BHP can reduce the potential for precipitation, by allowing the CO2 to evolve from the aqueous solution within the reservoir, before it arrives at the production wellbore. On the other hand, a lower producer BHP can increase water production rates and, therefore, scale risk.
The proposed workflow provides valuable insights on the procedures involved in simulating and optimizing CO2-WAG projects with high calcite scale risk. Its application demonstrated the importance of an integrated analysis that seeks for higher economic returns in a sustainable manner, with reduced production issues caused by CO2 speciation.
The Importance of an Appropriate Test Program for the Evaluation of Suppliers Raw Materials
Authors: Williams Helen , McCallum Catriona , Johnston Michael , Jordan Myles 
Published: June 2020

Abstract
The practice of scale squeeze treatments to oil and gas production wells to prevent inorganic scale formation has been used for over 30 years. The test methods used for selection of chemicals for these treatments are well understood. Performance testing to determine a minimum effective dose (MED) followed by core flood testing to understand propensity for formation damage has been conducted successfully for many years to allow chemical selection.
This paper describes the steps taken to qualify a new source for a common squeeze scale inhibitor chemistry. Samples from an established supplier were compared with those from the potential new supplier. Physical properties were compared and showed no difference, and the chemicals performed similarly in static jar tests for sulphate scale control. Further testing in a coreflood test confirmed that no formation damage resulted from application of either chemical. Return profiles from the chemical tests indicated similar squeeze lifetimes would be expected for both chemicals.
Further testing was conducted to confirm similar performance following desorption from the reservoir. Static jar tests were conducted using samples taken from the postflush of the coreflood. These indicated very different performance from the initial tests. The sample from the potential new supplier did not perform at the same MED, or at higher dose rates tested. This can be attributed to a difference in the weight distribution of the chemical, which results in different rates of desorption which impacts the sulphate scale inhibition performance.
The results shared in this paper will indicate the importance of ensuring tests conducted to qualify new sources consider more than simple physical properties but also the application environment of the chemical. Testing for continual injection application would have passed the alternative chemical as suitable. However, for squeeze applications, the variation in molecular weight reduced the chemical's sulphate scale inhibition, only observed in coreflood effluent performance tests.
This paper clearly shows that specific evaluation of chemicals under appropriate field conditions are critical to ensure appropriate chemicals are selected and applied in the field.
Extended Release Phosphonate Scale Inhibitor for Enhanced Squeeze Application
Authors: Jayawickramage Rangana , Swanson Kyle , Guraieb Paula , Nguyen Bradley , Tomson Ross 
Published: June 2020

Abstract
Diethylenetriamine penta(methylenephosphonicacid) (DTPMP) is a commonly used phosphonate scale inhibitor for CaCO3 and BaSO4. Even though DTPMP can be squeezed into the reservoir, the duration of the flow back could be improved. Therefore, frequent injection is needed to maintain the minimum inhibitor concentration, which costs a lot of money, time and chemicals. There have been some studies carried out to extend the release life of DTPMP, but none was able to get into a level that can be scalable and proven in the field. Taking into consideration those facts, an extended release carrier platform for DTPMP (ER-DTPMP) was designed and synthesized to extend the squeeze life time of DTPMP while maintaining its excellent inhibition properties.
ER-DTPMP was synthesized by attaching DTPMP into a proprietary carrier platform via various bridging components. Temporal product stability is shown well past five months and ongoing. The product has undergone extensive compatibility testing which includes product stability in high temperatures, compatibility with brine and KCl fluids, effect of shear, and high temperature and pressure.
Possible formation damage was studied in regain perm experiments by measuring differential pressure across the core. Around 300% (3x) extension of lifetime of incumbent DTPMP was obtained for the ER-DTPMP, when performing core flood experiments using a sandstone core. Field trials are ongoing at the time of this publication and will be the subject of a consequent paper.