bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improving Malaria Prevention with Innovative Biotechnology Integration
Authors: Ngunjiri S. , Brown A. , Isnard A. , Taudon N. , Imbert C. , Fusai T. , Leclipteux T. , Lefevre O. , Lichtenberger J. M. , Deffaud C. , Diara M. 
Published: October 2017

Abstract

OBJECTIVES/SCOPE
The development of an immunochromatographic test for quick detection of malaria preventive medicines (doxycycline, proguanil and mefloquine) in urine is described. The test integration and observed results in ExxonMobil (EM) workplace malaria program are also presented for potential adoption by organizations seeking to improve adherence to malaria prevention in workers operating in endemic locations.

METHODS PROCEDURES, PROCESS
In 2007, EM established a unique partnership with the French Army Biomedical Institute and two biomedical engineering manufacturers to develop a rapid detection test (RDT). Using specific drug antibodies, they created the tests detecting doxycycline, proguanil and mefloquine in urine. After the initial proof of concept in the laboratory setting, the RDTs were tested in malaria endemic locations using urine samples from workers on malaria preventive medicines and laboratory methods were used to confirm the results. Following such validation process and commercial production, the tests were integrated into ExxonMobil’s malaria program with implementation completed in all eligible sites located in endemic areas by 2013.

RESULTS, OBSERVATIONS, CONCLUSIONS
The first tests successfully developed were for proguanil and mefloquine, followed two years later by doxycycline. The RDT validity was tested against the standard laboratory techniques which use High-Performance Liquid Chromatography (HPLC).
Using urine samples collected in Chad and Equatorial Guinea, 100% of the tests detecting the drugs were confirmed by the laboratory method. Reading and reporting issues were identified for the validation of proguanil and mefloquine and subsequently addressed by an improved test user guide.
For doxycycline EM phase, two different RDTs were compared on 99 urine samples and verified with HPLC: 86.9% tested positive by both RDT’s and 91.9% by HPLC. This could be attributed to the detection level set for the RDT. Only 8 samples were truly negative. A further comparison of the strips showed that one had well-marked responses and more stable immunoglobulins for the test component.
As a result of the test development and implementation, 65% of the 32,496 malaria drug prevention compliance tests performed between 2013 and 2016 were conducted by RDTs. They helped further reduce noncompliance rates, keep the number of cases as low as 15 per year and save approximately 1.6 million dollars during that period. Additional benefits are related to having immediate results and opportunity for timely counseling on malaria prevention.
The use of this newly developed rapid test detecting malaria prevention medicines in urine is an additional incentive for malaria chemoprophylaxis compliance. It is affordable, practical and commercially available to help reduce malaria risk and consequences to companies and their non-immune workers going to malaria-endemic locations.
Unique Design and Performance of a High Temperature Viscoelastic Diverter Pill for Sandstone Acid Yields Better Diversion Response and Increased Production
Authors: Usie Marty , Carman Paul , Langlinais Kevin , Nino-Penaloza Andrea , Mccartney Elizabeth 
Published: October 2017

Abstract
Foam diversion has industry recognition as a proven approach to diversion in remedial sandstone acidizing in deep-water environments. With long intervals and large displacement volumes it is critical that a stable diverter reach the perforations with sufficient viscosity to sustain diversion effectiveness. Industry publications and laboratory testing indicate that non-stabilized foam systems tend to breakdown over time. A novel sandstone acidizing diverter (SSAD) system was recently developed and applied successfully in the field.
The new SSAD system is comprised of a surfactant based gelling agent prepared in an ammonium chloride base fluid. The formulation of the SSAD system can be altered as needed to obtain desired rheology and break profile. In order to demonstrate the viscosity potential of this system, formulations without breaker were prepared in the laboratory for each specific well application at bottom-hole temperature. For instance, a formulation designed for 240 °F bottom-hole temperature, provided a stable viscosity slug of 300 cp at 100s-1 for six hour duration. The system maintained viscosity above 100 cp at 40s-1 after six hours with internal breaker.
In 2015, two wells in deep water Gulf of Mexico with 200°F bottom-hole temperatures and an average perforated interval of 114 ft were treated with an organic mud acid treatment with no diverter. These zones were then re-stimulated in late 2016 with the same organic mud acid system and the new SSAD system. The initial production of the two wells treated in 2015 versus the re-stimulation treatment in 2016 showed a twofold production increase. Diversion pressure response was observed to be as high as 285 psi.
The SSAD system can be applied in wells with low and elevated bottomhole temperatures up to 300°F. The SSAD system is non-damaging to the formation and will break in presence of hydrocarbons, or an internal breaker can be added for enhanced clean-up. Other features include extended fluid stability and no additional mixing equipment or personnel requirements compared to foam.
The case study of the two wells in deep water Gulf of Mexico demonstrates the effectiveness of the new SSAD treatment compared to the conventional treatments without diversion being previously pumped in the Gulf of Mexico. Not only do SSAD treatments provide enhanced diversion compared to foam, on average, the cost of an SSAD system is 25% less than a treatment using foam diversion.
A Fully-Coupled Wellbore-Reservoir Model for Transient Liquid Loading in Horizontal Gas Wells
Authors: Tang Hewei , Hasan A. Rashid , Killough John 
Published: October 2017

Abstract
Liquid loading is a challenging issue in most mature gas fields. The dynamic interaction between wellbore and reservoir when liquid loading happens cannot be comprehensively simulated by a single wellbore simulator or a single reservoir simulator. In this paper, we developed a fully implicitly coupled wellbore/reservoir model to predict the onset of liquid loading and simulate the subsequent unstable production period.
We fully couple a multi-segment well model with an in-house compositional reservoir simulator based on the control-volume finite-difference method. Transient material balance and mixture momentum balance are solved simultaneously with the reservoir system to obtain pressure, mixture velocity, and phase holdup in each wellbore segment. We further proposed a drift-flux model that is able to predict the transitions from stable flow patterns to unstable patterns for different pipe inclinations from vertical to horizontal. The model is applied in the coupled wellbore-reservoir simulator to characterize the two-phase flow in horizontal wellbores. We validate the coupled wellbore-reservoir model with a numerical reservoir simulator and demonstrate the model capability in simulating the whole producing life of liquid-loaded horizontal gas wells. The parametric study indicates that wellbore perforation numbers and joint pipe length before the first perforation can influence the onset time of liquid loading and the duration of unstable production.
Most of previous studies focus on predicting the onset of liquid loading phenomenon. In this paper, our model first achieves the analysis of the unstable production period after liquid loading occurs. The detection of unstable production can be much straightforward comparing to the onset of liquid loading, which makes the model a promising tool in assisting the decision of deliquification strategies for field operators.
Subsea Multilateral Technology Step Change in Australia
Authors: Benson C. A. , Cappiello S. , Campbell B. 
Published: October 2017

Abstract
Because of the substantial cost involved, subsea environments demand technologies which improve efficiency. This statement is particularly true in marginal developments. In such scenarios, multilateral completions have played an integral part in improving field economics through improved well performance and reducing both field and operating costs to a point where the field development is financially appealing. In the northwest shelf of Australia, there have been four major oil field developments to date which have been based either entirely or partially on multilateral completions. This paper describes the evolution of multilateral completions throughout the past 10 years in Australia for two such developments, outlining the efficiency and operational gains during that time period.
Sand face completion techniques in Australia's northwest shelf vary from conventional standalone screens (SAS) to more sophisticated sand control methods, such as gravel packing. For multilateral wells in this region, even though gravel packs have been installed in other regions, developments to date have been limited to oil producers with SAS with inflow control devices (ICDs) and swell packers for compartmentalization. Nonetheless, the process of constructing and completing a subsea multilateral completion can be complex, and often trip intensive. Early multilateral field developments borrowed technology from the Norwegian northwest shelf; however, as such, the completions were not optimized for the specific Australian operating environment. Following the first successful subsea multilateral field developments in Australia, customized technology began to be developed to address and improve completion efficiencies. Specifically, several global and regional first installations were implemented between 2014 and 2016 that reduced dedicated installation time by 42% and helped reduce or eliminate operational risks.
In addition to discrete technologies, well architectures have also been revisited to further the economic advantages of multilateral completions. Trilateral wells, where three laterals penetrate the reservoir, are now commonplace in subsea developments in Australia. The custom solutions developed throughout the past 10 years demonstrate not only industry maturity, but also region specific advancements in multilateral completion technology.
Australia's history of multilateral completions is a success story, highlighting an industry's adoption of new technology and appetite for improvement on a broader scale. In ten years, the step change in multilateral completion has been appreciable. The result of a decade worth of improvement and customization is a fit-for-purpose, reliable, robust and efficient completion practice.
Effect of Kerogen Type and Maturity on Performance of Carbon Dioxide Storage in Shale
Authors: Takbiri-Borujeni Ali , Kazemi Mohammad , Sun Ting , Mansouri-Boroujeni Mahdi 
Published: October 2017

Abstract
Potential for sequestration of carbon dioxide in organic rich shale is investigated in this work. Adsorption isotherms and Onsager diffusion coefficients are determined using molecular dynamics simulations for atomistic kerogen models. The kerogen unit models prepared by (Ungerer et al., 2014) are used in this study. To build representative solid state models for kerogen, eight kerogen molecules are placed in a periodic cubic cell. Once the initial configuration of kerogen molecules is prepared, constant-temperature constant- volume simulations and then constant-temperature constant-pressure simulations are performed to obtain the final structures. For the final structure, computed density and adsorption isotherms are within the reported experimental values. Grand Canonical Monte Carlo (GCMC) simulations are performed for CH4-CO2 mixtures to investigate binary adsorption isotherms in kerogen models with different maturities. Equilibrium molecular dynamics (EMD) simulations are used to determine Onsager diffusion coefficients. As pressure for each species in the binary mixtures increases, its adsorbed amount increases and adsorbed amount of the other species decreases. Adsorbed amount of CO2 is higher than that of CH4 for all kerogen types at all pressures tested due to the strong permanent quadrapole moment of CO2. Due to higher adsorption affinity of CO2 to kerogen pore surfaces compared to CH4, its Onsager diffusion coefficients are smaller than those for CH4 for all kerogen types.
Further Insights into the Mechanism of Disproportionate Permeability Reduction
Authors: Liang Bin , Jiang Hanqiao , Li Junjian , Seright R. S. , Lake Larry W. 
Published: October 2017

Abstract
Disproportionate permeability reduction (DPR) is a phenomenon whereby many water-soluble polymer solution and polymer gels reduce the permeability to water flow more than to oil or gas flow. DPR is important for some gels that are applied to production wells in water-shutoff treatments. The mechanisms of DPR need more investigation and clarification. In this study, experiments on two different scales, core- and micro-model-scale, were conducted to study the mechanism of DPR in flow through permeable medium treated with Cr(III)-acetate-HPAM gels. The procedures for the two experiments can be similarly divided into five phases: gelant injection and gelation, oil flooding, gel rehydration with no oil phase pressure difference, oil re-flooding, and water flooding.
In the core-scale experiments, we used nuclear magnetic resonance (NMR) to monitor the T2 signal change during fluorine-tagged oil and water flooding after the gel treatment. NMR can detect the signal change of trapped and free water inside the gel in different pore sizes in porous medium. In the micro-model-scale experiments, a microscopic glass-etched model is subject to red oil and blue water flooding alternately after the gel treatment. Oil extrusion under an oil phase pressure gradient and the evolution of oil flow channel are recorded by a video sensor. The subsequent water flooding is also investigated.
Results show that a gel-displacement mechanism is a primary reason for the development of the oil flow path initially. As the displacement proceeds, the gel dehydration occurs induced by the oil phase pressure and therefore the flow channel continues forming, but no gel is produced during this phase. During gel rehydration, the flow channel is blocked, which can be inferred from the T2 spectrum and visual microscope image. However, the rehydrated gel can only partially reduce permeability and oil pathways re-establish easily with the subsequent oil flooding. In water flooding, water permeability decreases abruptly. The mechanisms for the disproportionate permeability reduction involve channel segregation, gel rehydration, residual oil effects, and the low permeability of gel relative to water.
Stress Management: First Openhole Multistage Ball Drop in Khazzan
Authors: Casero A. , Rylance M. , Al Shueili A. , Ishteiwy O. , White D. , Al Manji A. , Dawson W. , dwi Kurniadi S. , Bruseth E. 
Published: October 2017

Abstract
Openhole multistage (OHMS) completion systems have been available for nearly 20 years. Their introduction was primarily linked to improved operational efficiency, achievable through the elimination of redundant operations, costs, and time from the existing application of plug-and-perf (P&P) solutions. However, increased understanding with time has demonstrated that the most effective applications of the approach are those that offer better connection within the reservoir. Examples of such applications include delivery of fracturing within extended reach wells, application to naturally fractured formations, and use of the OHMS systems in offshore or logistically challenged areas.
The use of an OHMS system has a number of potential advantages for certain applications, not least of which is preservation of the uncemented annulus with extensive direct reservoir access within the completion. One of the major advantages of this geometry is that there is an unparalleled and flawless wellbore-to-reservoir communication in place, immediately prior to fracturing. In hard-rock, high-stress-ratio cased-cemented scenarios, where tortuosity and near-wellbore friction can dominate, an ability to avoid such issues in the first place is an advantage. This is particularly true in those horizontal wells drilled and completed in complex stress regimes. In these cases, a complex connection resulting from perforating can often be detrimental to creation of desired fracture width, making proppant placement challenging and thereby reducing the effective fracture conductivity.
Within the Khazzan field, in the Sultanate of Oman, such a complex tectonically impacted stress-state exists in the formations of interest, combined with an ancient hard-rock environment exhibiting a wide variance in effective permeability. Early multifractured cased-cemented horizontal well simmediately demonstrated complex fracture-to-wellbore communication behaviour, which was addressed in a number of ways. One of these approaches included plans for deployment of the OHMS as a potential technique to ensure a smoother and simplerfracture-to-wellbore interface.
This paper will fully describe the experience of the first OHMS completion deployed in the Khazzan field including details on the fracture design, operational execution, surveillance, post-fracture cleanup, and productivity. The paper will particularly address those aspects related to near-wellbore tortuosity, fracture connectivity, proppant placement, and evidence of connection quality. The paper will assess this completion approach alongside previously applied techniques and report on the potential of the approach for more widespread deployment in resolving fracture complexity.
Proppant Transport in Fractures with Foam-Based Fracturing Fluids
Authors: Tong Songyang , Singh Robin , Mohanty Kishore K. 
Published: October 2017

Abstract
The placement of proppants in hydraulically fractured wells determines the conductivity of fractures and productivity of shale wells. In slickwater farcturing, proppants are often not transported deep into fractures. In this paper, proppant transport in foam-based fracturing fluid is visualized in a laboratory-scale fracture slot. Effect of parameters like foam quality, proppant loading, and injection rate are systematically investigated. Additionally, a CFD based model is developed to simulate the lab experiments by assuming the foam as a single-phase non-Newtonian fluid. Experiments show that dry foams (80% quality) can carry proppants between the lamellas with little vertical settling. A complex flow pattern is developed at the bottom of the slots in dry foams due to protrusion of foam fingers into proppant laden foam flow. Proppants are not carried very well in wet foams (70% quality) and form a proppant bed near the injection well. This is due to severe drainage of surfactant solution from the foam as it moves through the fracture. CFD simulation of proppant transport agrees approximately with the experimental observations for the dry foams. The simulation results do not agree with the experimental observations for the wet foams. The assumption of treating foams as a continuum non-Newtonian fluid is not valid for wet foams where drainage of surfactant solution is significant.
Rock-On-A-Chip Approach Provides New Insight for Well Interferences in Liquids-Rich Shale Plays
Authors: He Kai , Xu Liang , Lord Paul , Lozano Martin , Kenzhekhanov Shaken , Yin Xiaolong , Neeves Keith , Huang Tao 
Published: October 2017

Abstract
As infill drilling practices become more widely used, operators have observed increased well interference or "bashing" in various shale plays wherein the production of mature wells has been significantly impaired by new infilling wells. Notably, some wells have experienced production decrease of approximately 80% as a result of bashing. One possible explanation is the occurrence of hydraulic communication between the old and new wells because they are most likely connected by the newly created or reactivated natural fractures. However, the mechanisms in which hydraulic communication influences production have not been fundamentally studied.
Current technologies, such as pressure-transient analysis or production data mining, do not explicitly provide a physical understanding of the bashing phenomena. This paper discusses a study wherein "Rock-on-a-chip" (ROC) devices were used to investigate hydraulic fracturing fluid invasion and flowback processes. A homogeneous porous network based on the Voronoi tessellation method was patterned on a ROC device. To simulate one aspect of well interference (the impact of an offset well's fracturing fluid entering an existing well's fracture network), two fluid invasion-flowback cycles were performed. It was hypothesized that if the fracturing fluid injected through the new infill enters the fracture networks of existing wells, fracturing fluid would again be forced into the matrix, inflicting damage to the fracture-matrix interface and impairing production.
Test results revealed that water saturations in the ROC after the second flowback were higher than those after the first invasion-flowback cycle, suggesting that the second invasion-flowback cycle could indeed damage the matrix and reduce the relative permeability of the oil. Additionally, surfactant clearly improved the displacement efficiencies in the matrix. One experiment shows that surfactant used in the second invasion-flowback cycle even reduced the damage incurred by the first invasion-flowback cycle. The benefit of surfactant has been observed from field results from the Wolfcamp shale, where it was discovered that the EURs (estimated ultimate recoverys) of wells bashed by surfactant-stimulated offset wells were higher than those bashed by non-surfactant-stimulated offset wells. This study shows that fracturing fluid from offset wells can, in fact, damage the productivity of existing wells through connected fractures. In addition, surfactant, when properly selected, can potentially be used to help reduce damage, or even repair previous damage, caused by well bashing.