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In response to the increasing number of violent incidents resulting in fatalities, injuries and lost workdays in the healthcare industry (Figure 1, p. 40), several unions and National Nurses United (NNU, 2019) petitioned OSHA for a standard to prevent workplace violence. OSHA (2020a) granted the petition on Jan. 10, 2017, which has since been on the unified agenda in the pre-rule stage with the public comment period closing April 6, 2017. Although no federal rule is currently in place to directly address this exposure, nine state OSHA plans have developed workplace violence prevention rules (OSHA, 2020a). In the past few years, OSHA has taken several actions, moving closer to a workplace violence prevention standard. Early in 2016, OSHA (2016a) published an advisory document titled “Guidelines for Preventing Workplace Violence for Healthcare and Social Service Workers” that updated the voluntary guidelines of 1994 and 2004. In January 2017, the public comment period opened and OSHA (2017) published an enforcement directive updating the enforcement procedures and scheduling for enforcement of occupational exposure to workplace violence. Although practitioners, labor unions and governmental agencies have conducted studies on violence in the workplace, specifically in the healthcare sector, the issues are still largely governed by use of the General Duty Clause of the OSH Act of 1970. Despite General Duty Clause citations being issued for workplace violence exposure in healthcare, the industry continues to experience one of the highest numbers of related injuries compared to all other private industries (OSHA, 2016a).
The expanding solvent-steam-assisted gravity drainage (ES-SAGD) is a newly proposed thermal recovery technique showing promising efficiency in terms of a smaller steam-to-oil ratio and greater production rate to recover heavy oils and bitumen from oil-bearing formations, where a solvent is coinjected with the steam in the SAGD process. Numerical simulation of the ES-SAGD process requires reliable relative permeability data. The number of reported measurements of relative permeability involving bitumen systems is limited in the literature, mostly because of the experimental difficulties involved in such measurements. The relative permeability data sets for Canadian bitumen, in the presence of solvents, are simply not available in the open literature. The fluid-flow behavior of bitumen/water systems in the presence of solvent is an important matter that must be assessed before the implementation of any ES-SAGD process; therefore, the objective of the current study is to evaluate the impact of a light hydrocarbon solvent (n-hexane) on bitumen/water relative permeability under SAGD conditions. For this purpose, two-phase bitumen/water relative-permeability measurements were conducted in sandpacks over a wide range of temperatures from 70°C to 220°C using Athabasca bitumen, deionized water, and a light hydrocarbon solvent. A well-instrumented experimental setup was developed to perform the relative permeability measurements with the capability of applying confining pressure on the sand and measuring the pore-pressure profile with several intermediate pressure taps. Isothermal oil-displacement tests were carried out with solvent premixed with bitumen. The history-matching approach and Johnson-Bossler-Naumann (JBN) method were used to translate the oil displacement data into the relative-permeability curves. The results obtained with a solvent from this study and without any solvent reported in our previous study are compared to assess the solvent’s impact on relative permeability. In addition, the steady-state relative permeability was measured to assess the reliability of unsteady-state relative permeability. The interfacial tension (IFT) and contact-angle measurements using the same fluids were carried out to determine the fluid/fluid interaction and wettability state of the system under high-pressure/high-temperature (HP/HT) conditions.
The results of the present study confirmed that the two-phase diluted bitumen/water relative permeability is sensitive to temperature, especially in terms of the endpoint relative permeability to bitumen and water. Furthermore, adding normal hexane (below the asphaltene precipitation threshold) not only improves the displacement efficiency of water flooding because of the significant decrease in oil viscosity but also modifies the wettability and IFT of this system. At the same temperature, the two-phase oil/water relative permeability for bitumen/water systems is significantly different when the oil is diluted with the solvent. Also, the impact of solvent is more pronounced at lower temperatures. Furthermore, the consistency between the steady-state and unsteady-state relative permeability data proved that the effect of viscous fingering was small enough.
Al-Bayati, Ahmed Jalil (Lawrence Technological University) | O'Barr, Kevin (North Carolina Department of Labor) | Suk, SungJoon (Western Carolina University) | Albert, Alex (North Carolina State University) | Chappell, Jarred (North Carolina Rate Bureau)
The prequalification process is often used by hiring firms to evaluate the ability of contractors to execute the work successfully (Truitt, 2012). Considering safety performance as one of the prequalification standards is essential to ensure that an acceptable level of safety performance is achieved (Tappura, Sievänen, Heikkilä et al., 2015; Truitt, 2012). Generally, firms with satisfactory safety performance records have a well-defined procedure to identify and eliminate possible hazards in the workplace to minimize work-related incidents (Huang & Hinze, 2006). These firms are expected to achieve superior safety performance with a lower likelihood of work-related incidents (Brahmasrene & Smith, 2008). The likelihood positively impacts budget, completion time, work quality and reputation (Abudayyeh, Fredericks, Butt et al., 2006; Jallon, Imbeau & de Marcellis-Warin, 2011; Ladewski & Al-Bayati, 2019; Votano & Sunindijo, 2014).
As a result, national and international agencies such as American Society of Civil Engineers (ASCE) and U.K.’s Health and Safety Executive (HSE) have suggested the adoption of specific safety best practices to ensure superior safety performance (Liang, Zhang & Su, 2018). However, the proposed best practices have been designed to be used internally within organizations, and hiring firms (e.g., general contractors) often do not have access to the information. Consequently, hiring firms have limited capability to evaluate the overall safety performance of bidders. Written safety programs and experience modification rate (EMR) have been suggested as prequalification criteria (Alzahrani & Emsley, 2013). There is a positive correlation between safety performance and the implementation of the well-established safety program (Gilkey, del Puerto, Keefe et al., 2012). However, it is difficult to assess the level and quality with which firms execute and enforce the safety plan on the basis of a written program; Wilbanks (2018) suggests that utilizing written safety programs as a prequalification is questionable, which leaves EMR as the most reliable prequalification criterion. EMR popularity and acceptance as a prequalification criterion have increased rapidly in recent years (Clayton, 2016).
Visible light is all around us, from sunlight to street lighting and automobile headlights to the backlight on a smartphone and in nearly every indoor space. Humans are so accustomed to working and living in artificial light that many of us have not stopped to consider the implications. Most OSH professionals’ experience with light and artificial lighting is likely limited to assessing whether sufficient light exists for people to see where they are going or carry out a task, or whether a light is too bright. This article aims to provide a current review of lighting for OSH professionals. Such a review is timely due to emerging issues including energy efficiency, human health impacts (e.g., blue light hazard, circadian rhythm disruption, fatigue), human performance (e.g., visual performance, visual comfort) and environmental impacts (e.g., light pollution).
The visible light spectrum (VLS) is typically considered the portion of the electromagnetic spectrum from approximately 400 to 700 nm wavelength (Figure 1; Elert, 2019; IUPAC, 1997). The colors range from violet (~400 to 450 nm), blue (~450 to 500 nm), green (~500 to 550 nm), yellow (~550 to 600 nm), orange (~600 to 650 nm) and red (~650 to 700 nm). However, there can be some significant variation in exact wavelength ranges reported for colors (Elert, 2019; Helmenstine, 2020; Jones, 2020). The radiant energy of light is characterized by the direct relationship with frequency (Brune, 2020); that is, the shorter wavelength range of the VLS (e.g., violet/purple) has more intrinsic energy than longer wavelengths (e.g., red). The radiant flux (power) of a light source is a function of the frequency of the emitted radiation and time over which the energy is transmitted (DiLaura, Houser, Mistrick et al., 2011; Sliney, 2016).
Invasion of mud filtrate while drilling is considered one of the most common sources of formation damage. Minimizing formation damage, using appropriate drilling-fluid additives that can generate good-quality filter cake, provides one of the key elements for the success of the drilling operation. This study focuses on assessing the effect of using different types of nanoparticles (NPs) with calcium- (Ca-) bentonite on the formation-damage and filter-cake properties under downhole conditions.
Four types of oxide NPs were added to a suspension of 7-wt% Ca-bentonite with deionized water: ferric oxide (Fe2O3), magnetic iron oxide (Fe3O4), zinc oxide (ZnO), and silica (SiO2) NPs. The NPs/Ca-bentonite suspensions were then used to conduct the filtration process at a differential pressure of 300 psi and a temperature of 250°F using a high-pressure/high-temperature (HP/HT) American Petroleum Institute (API) filter press. Indiana limestone disks of 1-in. thickness were examined as the filter medium to simulate the formation in the filtration experiments. A computed tomography (CT) scan technique was used to characterize the deposited filter cake and evaluate the formation damage that was caused by using different fluid samples.
The results of this study showed that the filtrate invasion is affected by the type of NPs, which is also affecting the disk porosity. Using 0.5-wt% Fe2O3 NPs with the 7-wt% Ca-bentonite fluid showed a greater potential to minimize the amount of damage. The average porosity of the disk was decreased by 1.0%. However, adding 0.5-wt% Fe3O4, SiO2, and ZnO NPs yielded a disk-porosity decrease of 4.7, 13.7, and 30%, respectively. The decrease in the disk porosity after filtration is directly proportional to the volume of the invaded filtrate. Compared with that of the base fluid, the best decrease in the filtrate invasion was achieved when adding 0.5 wt% Fe2O3 and Fe3O4 NPs by 42.5 and 23%, respectively. The results revealed that Fe2O3 and Fe3O4 NPs can build a better Ca-bentonite platelet structure and thus a good-quality filter cake. This is because of their positive surface charge and stability in suspensions, as demonstrated by zeta-potential measurements, which can minimize formation damage. Increasing the concentration of Fe3O4 NPs from 0.5% to 1.5 wt% showed an insignificant variation in the filtrate invasion, spurt loss, and filter cake permeability; however, an increase in the filter-cake thickness and amount of damage created was observed. The 1.5-wt% ZnO NPs showed better performance compared with the case having 0.5-wt% ZnO NPs, but in the meanwhile, it showed the lowest efficiency compared with the other types of NPs. This could be because of their surface charge and suspension instability.
Results of this work are useful in evaluating the drilling applications using Ca-bentonite-based fluids modified with NPs as an alternative to the commonly used Na-bentonite. In addition, it might help in understanding the NPs/Ca-bentonite interaction for providing more efficient drilling operations and less formation damage.
The rotating disk apparatus (RDA) is used to study reaction kinetics. However, the current equations used to interpret the results from the RDA make oversimplifying assumptions. Some of these assumptions are not met in practice, yet no work has been done to study their impact on the mass transfer of the proton (H+) to the disk. The objectives of the current work are threefold: study flow regimes under the rotating disk in the RDA for Newtonian and non-Newtonian fluids, investigate the impact of the reactor boundaries on the mass transfer of H+ to the disk in Newtonian fluids, and identify the dimensions of the reactor that minimize this impact.
The mass transfer of the H+ was compared between different dimension reactors. Contrary to information reported in the literature, both the diameter of the reactor and the axial distance between the base of the disk and the bottom of the reactor have an impact on the rate of mass transfer of H+ to the disk. Moreover, the velocity profiles in the reactor showed three flow regimes: fully axisymmetric, fully asymmetric flow, and intermediate flow. These different regimes varied depending on the axial distance between the base of the disk and the bottom of the reactor, the diameter of the reactor, the rotational speed of the disk, and the kinematic viscosity of the reacting fluid.
Hydrocarbon (re-)development projects need to be evaluated under uncertainty. Forecasting oil and gas production needs to capture the ranges of the multitude of uncertain parameters and their impact on the forecast to maximize the value of the project for the company. Several authors showed, however, that the oil and gas industry has challenges in adequately assessing the distributions of hydrocarbon production forecasts.
The methods for forecasting hydrocarbon production developed with digitalization from using analytical solutions to numerical models with an increasing number of gridblocks (“digital twins”) toward ensembles of models covering the uncertainty of the various parameters. Analytical solutions and single numerical models allow calculation of incremental production for a single case. However, neither the uncertainty of the forecasts nor the question in which the distribution of various outcomes the single model is located can be determined. Ensemble-based forecasts are able to address these questions, but they need to be able to cover a large number of uncertain parameters and the amount of data that is generated accordingly.
Theory-guided data science (TGDS) approaches have recently been used to overcome these challenges. Such approaches make use of the scientific knowledge captured in numerical models to generate a sufficiently large data set to apply data science approaches. These approaches can be combined with economics to determine the desirability of a project for a company (expected utility). Quantitative decision analysis, including a value of information (VoI) calculation, can be done addressing the uncertainty range but also the risk hurdles as required by the decision-maker (DM). The next step is the development of learning agent systems (agent: autonomous, goal-directed entity that observes and acts upon an environment) that are able to cope with the large amount of data generated by sensors and to use them for conditioning models to data and use the data in decision analysis.
Companies need to address the challenges of data democratization to integrate and use the available data, organizational agility, and the development of data science skills but making sure that the technical skills, which are required for the TGDS approach, are kept.
This paper presents a case history of scale treatments performed in a well producing in the North Sea. Kvitebjørn is a gas and condensate producer with high reservoir pressure (480bar) and high temperature (152°C). Well A-7 T2 started production in January 2014 and has a history of a carbonate scale precipitation.A few months after start-up, formation water breakthrough was observed in addition to a reduction in Production Index.
Due to challenges with removing scale by wireline, interventions using scale dissolver were performed in late 2017 and early 2018. The second dissolver treatment was followed by a scale squeeze to protect the well from further scaling. The chemicals used were qualified according to the Operator’s technical specifications. Due to high reservoir temperature, thermal stability was vital in the qualification process. The formation permeability was moderate, which was important to consider when evaluating the risk of formation damage.
The environmental category for the chemicals versus their performance was an important factor in the qualification process. Modelling programs were used to assess placement distribution under various bullhead pumping conditions. For the scale squeeze, a modelling program was used to simulate treatment lifetime using isotherms derived from laboratory core flood testing.
Water samples were taken from the well and analysed onshore in the supplier’s laboratory. Following the scale squeeze, water samples were taken from the well during the entire treatment lifetime. Ion concentrations and residual inhibitor concentrations were monitored together with production parameters to assess the scale situation in the well.
Following the treatments, the well showed an increased gas production. The well produced 1.2MSm3 at 40% choke before the treatments and 1.2MSm3 at 6-7% choke after. Laboratory work combined with field experience from this first well that was treated, forms the basis for possible future treatments. Being able to treat wells through pro-active and efficient scale inhibitor squeeze treatments will allow for continued production of wells exposed to scale risk, avoiding the cost and risks associated with mechanical scale removal and avoiding production deferral associated with potential dissolver jobs.
Scale control and inhibition is very important for maintaining flow assurance of oil production. Several specialty chemicals are used to delay, reduce or prevent scale deposition and, in particular, polymers and phosphonate-based chemicals have been used extensively. The accurate and precise topside measurement of scale inhibitors plays an important role in assessing the efficiency of scale squeeze and continuous-chemical injection treatments. At present, numerous techniques exist for scale inhibitor (SI) analysis but each method has its own limitation and often these methods give results of either total chemical content or elemental analysis without details of chemical speciation. Furthermore, most techniques often lack the ability for on-site analysis on fresh produced water samples, which yields the potential for quick and more accurate and precise information due to minimal sample degradation.Nanotechnology-based Surface Enhanced Raman Spectroscopy (SERS) developed as the next-generation method to fill the gap in speciation of phosphonates and to determine low concentrations of different scale inhibitor chemicals in produced brines in a timely and cost-effective manner.Particular focus is placed upon the individual and mixed analysis of a novel phosphonate and Deta Phosphonate (DETPMP) respectively. Development of this method with handheld instrumentation provides better detection and quantification of scale inhibitors in the field and reduces time and cost compared to sending samples to off-site laboratories for data collection.
The control of inorganic scale deposition within production wells by deployment of scale squeeze treatments is a well-established method for both onshore and offshore production wells. Factors that have influenced the change from 12 to 24 months squeeze treatments include changing MIC values, rising operation expenditure related to subsea vs platform deployment costs and in all cases assessing total operational cost vs simply chemical costs alone. The implication of deferred oil associated with delayed production during pumping and post squeeze well cleanup was also considered in the design process for these wells. The paper outlines the elements of the process that should be considered/reviewed when making the decision to change from the conventional 12 months to 24 months squeeze treatment. Designs and field results from three oil producing basins, each with different cost drivers, have been used to illustrate how it is possible to maintain effective scale management through the life cycle of these production wells. 2 SPE-200701-MS